ENI S.p.A.
Annual Report 2011

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Sovracop20F_Eni_2011 4/12/12 10:42 AM Pagina 1 Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2011: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1 Internet Home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary BNY Mellon Shareowner Services PO Box 358516 Pittsburgh, PA 15252-8516 shrrelations@bnymellon.com Contacts: - Institutional Investors/Broker Desk: UK: Mark Lewis - Tel. +44 (0) 20 7964 6089; mark.lewis@bnymellon.com USA: Ravi Davis - Tel. +1 212 815 4245; ravi.davis@bnymellon.com Hong Kong: Joe Oakenfold - Tel. +852 2840 9717; joe.oakenfold@bnymellon.com - Retail Investors: Domestic Toll Free – Tel. 1-866-433-0354 International Callers – Tel. +1.201.680.6825 Cover: Inarea - Rome - Italy Layout and supervision: Studio Joly Srl - Rome - Italy Printing: Primaprint Srl - Viterbo - Italy eni.com A n n u a l R e p o r t o n F o r m 2 0 - F 2 0 1 1 A n n u a l Re p o r t o n Fo r m 2 0 - F 2 0 1 1 Sovracop20F_Eni_2011 4/12/12 10:42 AM Pagina 1 Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2011: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1 Internet Home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary BNY Mellon Shareowner Services PO Box 358516 Pittsburgh, PA 15252-8516 shrrelations@bnymellon.com Contacts: - Institutional Investors/Broker Desk: UK: Mark Lewis - Tel. +44 (0) 20 7964 6089; mark.lewis@bnymellon.com USA: Ravi Davis - Tel. +1 212 815 4245; ravi.davis@bnymellon.com Hong Kong: Joe Oakenfold - Tel. +852 2840 9717; joe.oakenfold@bnymellon.com - Retail Investors: Domestic Toll Free – Tel. 1-866-433-0354 International Callers – Tel. +1.201.680.6825 Cover: Inarea - Rome - Italy Layout and supervision: Studio Joly Srl - Rome - Italy Printing: Primaprint Srl - Viterbo - Italy eni.com A n n u a l R e p o r t o n F o r m 2 0 - F 2 0 1 1 A n n u a l Re p o r t o n Fo r m 2 0 - F 2 0 1 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ————————— Form 20-F (Mark One) REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 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 OR 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 (Which represent the right to receive two Shares) New York Stock Exchange* New York Stock Exchange * 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 (cid:1)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 (cid:1) No (cid:2) 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. 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 (cid:2) No (cid:1) Yes (cid:1) No (cid:2) 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 (cid:1) No (cid:2) * This requirement does not apply to the registrants until their fiscal year ending December 31, 2011. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer (cid:1) Accelerated filer (cid:2) Non-accelerated filer (cid:2) Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: U.S. GAAP (cid:2) International Financial Reporting Standards as issued by the International Accounting Standards Board (cid:1) Other (cid:2) 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. 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). Item 17 (cid:2) Item 18 (cid:2) Yes (cid:2) No (cid:1) TABLE OF CONTENTS Certain Defined Terms .......................................................................................................................................................................... Presentation of Financial and Other Information ................................................................................................................................ Statements Regarding Competitive Position ........................................................................................................................................ Glossary .................................................................................................................................................................................................. Abbreviations and Conversion Table ................................................................................................................................................... PART I Item 1. Item 2. Item 3. Item 4. Item 4A. Item 5. Item 6. Item 7. Item 8. Item 9. Item 10. Item 11. Item 12. 12A. 12B. 12C. 12D. PART II Item 13. Item 14. Item 15. Item 16. 16A. 16B. 16C. 16D. 16E. 16F. 16G. 16H. PART III Item 17. Item 18. Item 19. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS ................................................. OFFER STATISTICS AND EXPECTED TIMETABLE ..................................................................................... KEY INFORMATION ............................................................................................................................................ Selected Financial Information ................................................................................................................................ Selected Operating Information .............................................................................................................................. Exchange Rates ........................................................................................................................................................ Risk Factors .............................................................................................................................................................. INFORMATION ON THE COMPANY ................................................................................................................ History and Development of the Company ............................................................................................................ Business Overview ................................................................................................................................................... Exploration & Production ........................................................................................................................................ Gas & Power ............................................................................................................................................................. Refining & Marketing .............................................................................................................................................. Engineering & Construction .................................................................................................................................... Petrochemicals .......................................................................................................................................................... Corporate and Other activities ................................................................................................................................. Research and Development ..................................................................................................................................... Insurance ................................................................................................................................................................... Environmental Matters ............................................................................................................................................. Regulation of Eni’s Businesses ............................................................................................................................... Property, Plant and Equipment ................................................................................................................................ Organizational Structure .......................................................................................................................................... UNRESOLVED STAFF COMMENTS ................................................................................................................. OPERATING AND FINANCIAL REVIEW AND PROSPECTS ....................................................................... Executive Summary ................................................................................................................................................. Critical Accounting Estimates ................................................................................................................................. 2009-2011 Group Results of Operations ................................................................................................................ Liquidity and Capital Resources ............................................................................................................................. Recent Developments .............................................................................................................................................. Management’s Expectations of Operations ............................................................................................................ DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES ........................................................................ Directors and Senior Management .......................................................................................................................... Compensation ........................................................................................................................................................... Board Practices ......................................................................................................................................................... Employees ................................................................................................................................................................. Share Ownership ...................................................................................................................................................... MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS ...................................................... Major Shareholders .................................................................................................................................................. Related Party Transactions ...................................................................................................................................... FINANCIAL INFORMATION .............................................................................................................................. Consolidated Statements and Other Financial Information ................................................................................... Significant Changes ................................................................................................................................................. THE OFFER AND THE LISTING ......................................................................................................................... Offer and Listing Details ......................................................................................................................................... Markets ..................................................................................................................................................................... ADDITIONAL INFORMATION ........................................................................................................................... Memorandum and Articles of Association ............................................................................................................. Material Contracts .................................................................................................................................................... Exchange Controls ................................................................................................................................................... Taxation .................................................................................................................................................................... Documents on Display ............................................................................................................................................. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ................................... DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES .................................................... Debt Securities .......................................................................................................................................................... Warrants and Rights ................................................................................................................................................. Other Securities ........................................................................................................................................................ American Depositary Shares ................................................................................................................................... DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES .............................................................. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS ..................................................................................................................................... CONTROLS AND PROCEDURES ....................................................................................................................... Board of Statutory Auditors Financial Expert ........................................................................................................ Code of Ethics .......................................................................................................................................................... Principal Accountant Fees and Services ................................................................................................................. Exemptions from the Listing Standards for Audit Committees ............................................................................ Purchases of Equity Securities by the Issuer and Affiliated Purchasers ............................................................... Change in Registrant’s Certifying Accountant ....................................................................................................... Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual ................................................................................. Mine Safety Disclosure ............................................................................................................................................ FINANCIAL STATEMENTS ................................................................................................................................. FINANCIAL STATEMENTS ................................................................................................................................. EXHIBITS ................................................................................................................................................................ i Page ii ii ii iii vi 1 1 1 1 3 5 5 25 25 30 30 59 74 81 83 85 86 89 89 96 106 106 106 107 107 109 112 125 130 131 139 139 145 156 162 165 166 166 166 167 167 167 168 168 169 171 171 177 177 178 182 183 184 184 184 184 184 186 186 186 187 187 187 188 188 188 189 191 192 192 192 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 “(cid:1)” 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 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. GLOSSARY Financial terms Leverage Net borrowings 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”. 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 BOE Concession contracts Condensates Contingent resources Conversion capacity Conversion index Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons. 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”). 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 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 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. 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. 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 Development Waters deeper than 460 meters. 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 EPIC Exploration FPSO FSO Infilling wells LNG LPG Margin Mineral Potential Mineral Storage Engineering, Procurement and Construction. Engineering, Procurement, Installation and Construction. Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling. Floating Production Storage and Offloading System. Floating Storage and Offloading System. 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. 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. Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression. 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. (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. 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) Network Code Over/Under lifting Possible reserves Probable reserves 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. A code containing norms and regulations for access to, management and operation of natural gas pipelines. 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 are those additional reserves that are less certain to be recovered than 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 Proved reserves Reserves 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 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 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 Ship-or-pay Strategic Storage Take-or-pay Upstream/Downstream 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. 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. 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. 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. 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 BCF mmCM BCM BOE KBOE = = = = = = million cubic feet billion cubic feet million cubic meters billion cubic meters barrel of oil equivalent thousand barrel of oil equivalent mmBOE = million barrel of oil equivalent BBOE BBL KBBL = = = billion barrel of oil equivalent barrels thousand barrels mmBBL = million barrels BBBL = billion barrels ktonnes = thousand tonnes mmtonnes = million tonnes MW GWh TWh /d /y E&P G&P R&M E&C = megagawatt = gigawatthour = terawatthour = per day = per year = the Exploration & Production segment = the Gas & Power segment = the Refining & Marketing segment = the Engineering & Construction segment CONVERSION TABLE 1 acre 1 barrel 1 BOE = 0.405 hectares = 42 U.S. gallons = 1 barrel of crude oil 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 0.00636 barrels 1 kilometer 1 short ton 1 long ton 1 tonne of oil equivalent = approximately 0.62 miles = 0.907 tonnes = 1.016 tonnes = 1 metric ton 1 tonne of crude oil = 1 metric ton of crude oil = 5,550 cubic feet of natural gas* = 2,000 pounds = 2,240 pounds = 1,000 kilograms = approximately 2,205 pounds = 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 Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS NOT APPLICABLE PART I 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 ((cid:1) million except data per share and per ADR) 87,204 108,082 83,227 98,523 109,589 4,465 686 100 837 (444) (312) (26) 13,433 16,239 4,030 (988) (845) 1,045 (466) (623) 125 9,120 13,866 15,887 1,758 2,896 3,687 (273) 149 (102) (86) (675) (424) 1,422 1,302 881 (427) (1,384) (436) (319) (361) (420) (189) (271) 18,739 18,517 12,055 16,111 17,435 6,860 4,367 10,011 8,825 6,318 5.11 5.11 2.73 5.09 5.09 2.43 3.33 3.33 1.21 4.45 4.45 1.74 4.81 4.81 1.89 14.01 14.00 7.48 14.97 14.97 7.14 9.27 9.27 3.36 11.81 11.81 4.62 13.40 13.40 5.26 CONSOLIDATED PROFIT STATEMENT DATA Net sales from operations ................................................................... Operating profit by segment (1) Exploration & Production ............................................................. Gas & Power .................................................................................. Refining & Marketing ................................................................... Petrochemicals ............................................................................... Engineering & Construction ......................................................... Other activities (2) .......................................................................... Corporate and financial companies (2) .......................................... Impact of unrealized intragroup profit elimination (3) ................. Operating profit ................................................................................... Net profit attributable to Eni .............................................................. Data per ordinary share ((cid:1)) (4) Operating profit: - basic ................................................................................................... - diluted ................................................................................................ Net profit attributable to Eni basic and diluted ................................. Data per ADR ($) (4) (5) Operating profit: - basic .................................................................................................. - diluted ............................................................................................... Net profit attributable to Eni basic and diluted ................................. 1 As of December 31, 2007 2008 2009 2010 2011 ((cid:1) million except number of shares and dividend information) CONSOLIDATED BALANCE SHEET DATA Total assets .......................................................................................... 101,460 116,673 117,529 131,860 142,945 19,830 20,837 24,800 27,783 29,597 Short-term and long-term debt ........................................................... 4,005 4,005 Capital stock issued ............................................................................. Minority interest .................................................................................. 4,921 3,978 40,428 44,436 46,073 51,206 55,472 Shareholders’ equity - Eni share ........................................................ 10,593 14,562 13,695 13,870 13,438 Capital expenditures ............................................................................ Weighted average number of ordinary shares outstanding (fully diluted - shares million) ............................................................ Dividend per share ((cid:1)) ......................................................................... Dividend per ADR ($) (4) ...................................................................... 3,623 1.04 2.90 3,668 1.30 3.74 3,639 1.30 3.72 3,622 1.00 2.91 3,622 1.00 2.64 4,005 4,522 4,005 2,439 4,005 4,074 ________ (1) (2) (3) (4) (5) 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. 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 (cid:1)120 million and (cid:1)54 million, respectively. Prior-year data have not been restated. 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. 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. 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 ((cid:1)1.04 per ADR) at the Noon Buying Rate recorded on the payment date on September 29, 2011, while the balance of (cid:1)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. Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL) .......................................................................... of which developed............................................................................... Proved reserves of liquids of equity-accounted entities at period end (mmBBL) .......................................................................... of which developed............................................................................... Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) (1) ........................................................................... of which developed............................................................................... Proved reserves of natural gas of equity-accounted entities at period end (BCF)................................................................................ of which developed............................................................................... Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)................................................................. of which developed............................................................................... Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end ..................................................................... of which developed .............................................................................. Reserves replacement ratio (2) ............................................................. (3)................................. Average daily production of liquids (KBBL/d) Average daily production of natural gas available for sale (mmCF/d) (3) ............................................................... Average daily production of hydrocarbons available for sale (KBOE/d) (3) ............................................................... Hydrocarbon production sold (mmBOE)............................................... Oil and gas production costs per BOE (4)............................................ Profit per barrel of oil equivalent (5).................................................... ________ Year ended December 31, 2007 2008 2009 2010 2011 3,127 1,953 3,243 2,009 3,377 2,001 3,415 1,951 3,134 1,850 142 26 142 33 86 34 208 52 300 45 16,549 17,214 16,262 16,198 15,582 10,967 11,138 11,650 10,965 10,363 3,022 428 3,015 420 1,588 234 1,684 246 4,700 53 6,010 3,862 6,242 3,948 6,209 4,030 6,332 3,926 5,940 3,716 668 101 138 1,020 666 107 135 1,026 362 74 96 1,007 511 96 125 997 1,146 54 142 845 3,819 4,143 4,074 4,222 3,763 1,684 611.4 6.90 14.19 1,748 632.0 7.65 16.00 1,716 622.8 7.41 8.14 1,757 638.0 8.89 11.91 1,523 548.5 10.86 16.98 (1) (2) (3) (4) (5) 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. 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. 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). 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”. 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 Year ended December 31, 2007 2008 2009 2010 2011 78.75 6.08 8.74 83.69 5.63 8.91 83.79 5.81 7.95 93.57 5.39 97.55 98.23 6.17 6.00 98.96 104.23 103.72 37.32 33.84 30.89 31.5 31.5 31.1 33.96 29.93 33.19 34.55 35.84 37.15 554 544 544 12.02 12.03 11.80 75.81 6.19 9.41 91.41 5.65 97.06 47.87 31.7 39.54 34.80 564 11.73 78.16 6.21 9.53 93.90 2.86 96.76 43.18 32.0 40.28 31.96 574 11.37 6,441 5,956 5,986 6,167 6,287 2,486 8.80 2,502 7.37 2,206 6.25 15,390 19,105 18,730 20,505 20,417 75,125 78,094 77,718 79,941 78,686 2,353 7.22 2,477 6.52 Selected Operating Information continued Sales of natural gas to third parties (6)................................................. Natural gas consumed by Eni (6).......................................................... Sales of natural gas of affiliates (Eni’s share) (6)................................ Total sales and own consumption of natural gas of the Gas & Power segment (6)........................................................... E&P natural gas sales in Europe and in the Gulf of Mexico (6)......... Worldwide natural gas sales (6)............................................................ Transport of natural gas for third parties in Italy (6)........................... Length of natural gas transport network in Italy at period end (7)..... Electricity sold (8) ................................................................................. Refinery throughputs (9) ....................................................................... Balanced capacity of wholly-owned refineries (10)............................. Retail sales (in Italy and rest of Europe) (9) ........................................ Number of service stations at period end (in Italy and rest of Europe)................................................................. Average throughput per service station (in Italy and rest of Europe) (11) ........................................................... Petrochemical production (9)................................................................ Engineering & Construction order backlog at period end (12) ........... Employees at period end (units) ........................................................... ________ (6) (7) (8) (9) (10) (11) (12) Expressed in BCM. Expressed in thousand kilometers. Expressed in TWh. Expressed in mmtonnes. Expressed in KBBL/d. Expressed in thousand liters per day. Expressed in (cid:1) 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) (U.S. dollars per (cid:1)) At period end Year ended December 31, 2007......................................................................................................................... 2008......................................................................................................................... 2009......................................................................................................................... 2010......................................................................................................................... 2011......................................................................................................................... 1.49 1.60 1.51 1.46 1.49 1.29 1.24 1.25 1.19 1.29 1.37 1.47 1.39 1.33 1.39 1.46 1.39 1.44 1.34 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 (cid:1)) October 2011 .......................................................................................................................... November 2011 ...................................................................................................................... December 2011 ...................................................................................................................... January 2012........................................................................................................................... February 2012......................................................................................................................... March 2012 ............................................................................................................................ 1.42 1.38 1.35 1.32 1.35 1.33 1.32 1.33 1.29 1.27 1.30 1.30 1.40 1.34 1.29 1.32 1.34 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 (cid:1)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 (cid:1)1.2 billion in executing exploration projects and it plans to spend approximately (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)710 million, reversing the prior-year profit of (cid:1)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 (cid:1)2.22 billion (net of limited amounts of volume make-up) and has paid the associated cash advances amounting to (cid:1)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 (cid:1)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; • • • performing site clean-ups. installing pollution control equipment; implementing additional safety measures; and 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 (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)29,121 million and operating profit of (cid:1)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 (cid:1)34,731 million and operating profit of (cid:1)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 (cid:1)51,219 million and operating loss of (cid:1)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 (cid:1)6,491 million and an operating net loss of (cid:1)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 (cid:1)11,834 million and operating profit of (cid:1)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 (cid:1)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 (cid:1)13.44 billion, while expenditures incurred in joint venture initiatives and other investments amounted to (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)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 (cid:1)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 ((cid:1)7,357 million) deployed mainly in Norway, Kazakhstan, Algeria, the United States, Congo and Egypt, and exploration projects ((cid:1)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 ((cid:1)898 million and (cid:1)337 million, respectively) as well as development and increase of storage capacity ((cid:1)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 (cid:1)629 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment ((cid:1)1,090 million). There were no significant acquisitions in the year. In 2010, capital expenditures amounted to (cid:1)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 ((cid:1)8,578 million) deployed mainly in Egypt, Kazakhstan, Congo, the United States and Algeria, and exploration projects ((cid:1)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 ((cid:1)842 million and (cid:1)328 million, respectively) as well as development and increase of storage capacity ((cid:1)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 (cid:1)692 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment ((cid:1)1,552 million). There were no significant acquisitions in the year. In 2009, capital expenditures amounted to (cid:1)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 ((cid:1)7,478 million) deployed mainly in Kazakhstan, the United States, Egypt, Congo, Italy and Angola, and exploration projects ((cid:1)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 (cid:1)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 ((cid:1)919 million and (cid:1)278 million, respectively) as well as the development and increase of the storage capacity ((cid:1)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 (cid:1)608 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment ((cid:1)1,630 million). In 2009, Eni’s acquisitions amounted to (cid:1)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 (cid:1)2.05 billion. Exploration & Production BUSINESS OVERVIEW 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 (cid:1)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 (cid:1)1.7 billion will be spent to build transportation infrastructures and LNG projects through equity- accounted entities. Exploration projects will attract some (cid:1)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 (cid:1)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) 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) (3) (4) (5) From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. See “Item 19 – Exhibits”. Includes Eni’s share of proved reserves of equity-accounted entities. See “Item 19 – Exhibits”. 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 “Supplemental oil and gas information” on page F-115. HYDROCARBONS (mmBOE) Consolidated subsidiaries Year ended Dec. 31, 2009 ..................... Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2010 ..................... Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2011 ....................... Developed ................................................... Undeveloped............................................... Equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2010 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2011 ....................... Developed ................................................... Undeveloped............................................... Consolidated subsidiaries and equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2010 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2011 ....................... Developed .................................................. Undeveloped .............................................. Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves 703 490 213 724 554 170 707 540 167 703 490 213 724 554 170 707 540 167 590 432 158 601 405 196 630 374 256 590 432 158 601 405 196 630 374 256 1,922 1,266 656 2,096 1,215 881 2,031 1,175 856 15 12 3 23 22 1 21 19 2 1,937 1,278 659 2,119 1,237 882 2,052 1,194 858 1,141 799 342 1,133 812 321 1,021 742 279 22 5 17 28 5 23 83 4 79 1,163 804 359 1,161 817 344 1,104 746 358 1,221 614 607 1,126 543 583 950 482 468 1,221 614 607 1,126 543 583 950 482 468 236 139 97 295 139 156 230 129 101 309 44 265 317 43 274 656 5 651 545 183 362 612 182 430 886 134 752 263 168 95 230 141 89 238 162 76 16 13 3 143 26 117 386 26 360 279 181 98 373 167 206 624 188 436 133 122 11 127 117 10 133 112 21 133 122 11 127 117 10 133 112 21 6,209 4,030 2,179 6,332 3,926 2,406 5,940 3,716 2,224 362 74 288 511 96 415 1,146 54 1,092 6,571 4,104 2,467 6,843 4,022 2,821 7,086 3,770 3,316 33 LIQUIDS (mmBBL) Consolidated subsidiaries Year ended Dec. 31, 2009 ..................... Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2010 ..................... Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2011 ....................... Developed .................................................. Undeveloped .............................................. Equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2010 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2011 ....................... Developed .................................................. Undeveloped .............................................. Consolidated subsidiaries and equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2010 ....................... Developed .................................................. Undeveloped .............................................. Year ended Dec. 31, 2011 ....................... Developed .................................................. Undeveloped .............................................. Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves 233 141 92 248 183 65 259 184 75 233 141 92 248 183 65 259 184 75 351 218 133 349 207 142 372 195 177 351 218 133 349 207 142 372 195 177 895 659 236 978 656 322 917 622 295 13 10 3 19 18 1 17 16 1 908 669 239 997 674 323 934 638 296 770 544 226 750 533 217 670 483 187 7 4 3 6 4 2 22 4 18 777 548 229 756 537 219 692 487 205 849 291 558 788 251 537 653 215 438 849 291 558 788 251 537 653 215 438 94 45 49 139 39 100 106 34 72 50 7 43 44 5 39 110 110 144 52 92 183 44 139 216 34 182 153 80 73 134 62 72 132 92 40 16 13 3 139 25 114 151 25 126 169 93 76 273 87 186 283 117 166 32 23 9 29 20 9 25 25 32 23 9 29 20 9 25 25 3,377 2,001 1,376 3,415 1,951 1,464 3,134 1,850 1,284 86 34 52 208 52 156 300 45 255 3,463 2,035 1,428 3,623 2,003 1,620 3,434 1,895 1,539 34 NATURAL GAS (BCF) Consolidated subsidiaries Year ended Dec. 31, 2009 ........................ Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2010 ..................... Developed ............................................. Undeveloped.......................................... Year ended Dec. 31, 2011 ....................... Developed ................................................... Undeveloped............................................... Equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2010 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2011 ....................... Developed ................................................... Undeveloped............................................... Consolidated subsidiaries and equity-accounted entities Year ended Dec. 31, 2009 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2010 ....................... Developed ................................................... Undeveloped............................................... Year ended Dec. 31, 2011 ....................... Developed ................................................... Undeveloped............................................... Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total reserves 2,704 2,001 703 2,644 2,061 583 2,491 1,977 514 1,380 1,231 149 1,401 1,103 298 1,425 995 430 2 2 1,380 1,231 149 1,401 1,103 298 1,427 995 432 2,704 2,001 703 2,644 2,061 583 2,491 1,977 514 5,894 3,486 2,408 6,207 3,100 3,107 6,190 3,070 3,120 14 12 2 24 22 2 20 17 3 5,908 3,498 2,410 6,231 3,122 3,109 6,210 3,087 3,123 2,127 1,463 664 2,127 1,550 577 1,949 1,437 512 85 5 80 118 4 114 338 4 334 2,212 1,468 744 2,245 1,554 691 2,287 1,441 846 2,139 1,859 280 1,874 1,621 253 1,648 1,480 168 2,139 1,859 280 1,874 1,621 253 1,648 1,480 168 814 539 275 871 560 311 685 528 157 1,487 217 1,270 1,520 214 1,306 3,033 24 3,009 2,301 756 1,545 2,391 774 1,617 3,718 552 3,166 629 506 123 530 431 99 590 385 205 2 2 22 6 16 1,307 8 1,299 631 506 125 552 437 115 1,897 393 1,504 575 565 10 544 539 5 604 491 113 575 565 10 544 539 5 604 491 113 16,262 11,650 4,612 16,198 10,965 5,233 15,582 10,363 5,219 1,588 234 1,354 1,684 246 1,438 4,700 53 4,647 17,850 11,884 5,966 17,882 11,211 6,671 20,282 10,416 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. Additions to proved reserves ........................ of which purchases and sales of reserves-in-place ....................................... Production for the year ................................. Subsidiaries Equity-accounted entities 2009 2010 2011 2009 2010 2011 605 776 183 (296) 158 644 (mmBOE) 25 (638) (12) (653) (7) (568) (314) (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 (cid:1)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 (KBBL/d) Italy .................................................. Rest of Europe ................................. North Africa ..................................... Sub-Saharan Africa ......................... Kazakhstan ...................................... Rest of Asia ..................................... Americas .......................................... Australia and Oceania ..................... Eni consolidated subsidiaries 56 133 287 309 70 56 71 8 990 2009 2010 2011 Eni consolidated subsidiaries 61 121 297 318 65 47 60 9 978 Eni share of equity- accounted entities 4 3 1 11 19 Eni consolidated subsidiaries 64 120 204 275 64 33 55 11 826 Eni share of equity- accounted entities 5 3 1 10 19 Eni share of equity- accounted entities 5 3 1 8 17 38 NATURAL GAS PRODUCTION AVAILABLE FOR SALE (1) 2009 2010 2011 (mmCF/d) Italy ................................................... Rest of Europe .................................. North Africa...................................... Sub-Saharan Africa .......................... Kazakhstan........................................ Rest of Asia ...................................... Americas ........................................... Australia and Oceania ...................... ________ Eni consolidated subsidiaries 630 608 1,500 213 241 391 416 46 4,045 Eni share of equity- accounted entities 3 26 29 Eni consolidated subsidiaries 648 517 1,556 365 221 412 385 91 4,195 Eni share of equity- accounted entities 3 24 27 Eni consolidated subsidiaries 648 498 1,165 422 212 378 323 93 3,739 Eni share of equity- accounted entities 4 20 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 Americas Australia and Oceania Total 2009 Consolidated subsidiaries Oil and condensate, per BBL .................. Natural gas, per KCF ................................. Average production cost, per BOE .......... Equity-accounted entities Oil and condensates, per BBL ................... Natural gas, per KCF ................................. Average production cost, per BOE ........... 2010 Consolidated subsidiaries Oil and condensate, per BBL..................... Natural gas, per KCF ................................. Average production cost, per BOE .......... Equity-accounted entities Oil and condensates, per BBL ................... Natural gas, per KCF ................................. Average production cost, per BOE ........... 2011 Consolidated subsidiaries Oil and condensates, per BBL ................... Natural gas, per KCF ................................. Average production cost, per BOE ........... Equity-accounted entities Oil and condensates, per BBL ................... Natural gas, per KCF ................................. Average production cost, per BOE ........... Development activities 56.02 9.01 9.69 56.46 7.06 8.28 56.42 5.79 3.99 59.75 1.66 13.19 52.34 0.45 5.20 14.60 56.85 10.62 8.87 72.19 8.71 9.42 67.26 7.40 9.42 70.96 6.87 5.63 78.23 1.87 15.19 66.74 0.49 6.40 16.09 77.78 13.53 9.73 55.34 4.09 3.44 9.01 7.44 4.95 75.20 4.35 5.62 57.05 9.87 5.05 55.66 4.05 7.39 56.41 23.14 72.84 4.70 8.15 71.70 27.78 50.40 8.14 9.56 73.00 7.40 9.75 57.02 5.62 7.41 44.43 6.81 13.72 72.95 6.01 8.89 58.86 8.73 17.45 101.20 11.56 11.17 97.56 9.72 10.31 97.18 10.65 26.91 97.63 5.95 5.96 17.98 5.39 10.82 110.09 1.97 18.32 108.92 11.43 98.68 0.57 6.37 101.09 5.27 8.28 101.15 4.02 12.38 98.05 7.38 12.14 102.47 6.44 10.86 74.98 15.68 7.68 93.03 46.77 84.78 13.89 26.76 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) Italy....................................................................... Rest of Europe ..................................................... North Africa......................................................... Sub-Saharan Africa ............................................. Kazakhstan ........................................................... Rest of Asia.......................................................... Americas .............................................................. Australia and Oceania ......................................... Total including equity-accounted entities ..... Productive 18.3 12.5 40.7 35.8 3.8 38.6 15.6 2.2 167.5 Exploration activities Dry Productive 23.9 2.9 44.3 28.0 1.8 41.7 27.6 1.5 171.7 0.4 1.9 4.3 1.0 7.6 Dry Productive 25.3 3.3 55.9 28.2 1.3 39.2 27.6 0.4 181.2 1.0 0.2 0.3 2.5 1.8 0.5 6.3 Dry Gross Net 0.3 1.1 1.0 2.5 3 18 27 28 13 12 17 2 3.9 12.5 6.6 2.2 5.4 6.9 4.9 118.0 39.5 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 Productive Dry Productive Dry Productive Dry Gross Net (units) Italy....................................................................... Rest of Europe ..................................................... North Africa......................................................... Sub-Saharan Africa ............................................. Kazakhstan ........................................................... Rest of Asia.......................................................... Americas .............................................................. Australia and Oceania ......................................... Total including equity-accounted entities...... ________ 4.1 4.8 2.3 1.0 0.8 13.0 1.0 0.2 3.8 2.7 3.9 3.8 1.4 16.8 1.7 9.3 2.3 1.0 1.0 15.3 0.5 1.1 8.1 4.7 2.8 6.3 0.4 23.9 6.0 21.0 21.0 63.0 13.0 16.0 11.0 4.4 6.5 15.7 18.6 2.3 6.9 3.3 151.0 57.7 0.7 3.4 2.6 7.6 1.4 15.7 0.3 6.2 0.6 0.2 2.5 9.8 (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.................................................. Italy........................................................... Rest of Europe ........................................ Croatia....................................................... Norway ..................................................... Poland ....................................................... United Kingdom....................................... Ukraine...................................................... Other Countries ........................................ AFRICA................................................... North Africa ........................................... Algeria....................................................... Egypt ......................................................... Libya ......................................................... Tunisia....................................................... Sub-Saharan Africa .............................. Angola....................................................... Congo........................................................ Democratic Republic of Congo............... Gabon........................................................ Ghana ........................................................ Mali ........................................................... Mozambique............................................. Nigeria....................................................... Togo .......................................................... Other Countries ........................................ ASIA ........................................................ Kazakhstan................................................ Rest of Asia ............................................. China ......................................................... India........................................................... Indonesia................................................... Iran ............................................................ Iraq ............................................................ Pakistan ..................................................... Russia........................................................ Saudi Arabia ............................................. Timor Leste............................................... Turkmenistan............................................ Yemen ....................................................... Other Countries ........................................ AMERICA .............................................. Brazil......................................................... Ecuador ..................................................... Trinidad & Tobago................................... United States............................................. Venezuela ................................................. Other Countries ........................................ AUSTRALIA AND OCEANIA ........... Australia.................................................... Other Countries ........................................ Total ......................................................... ________ 29,079 19,097 9,982 987 2,418 1,968 1,151 3,458 152,671 44,277 17,244 6,594 18,165 2,274 108,394 4,520 6,074 615 7,615 1,086 21,640 12,352 8,439 6,192 39,861 112,745 880 111,865 18,232 10,089 12,912 820 640 11,347 1,507 25,844 6,470 200 20,560 3,244 11,187 745 2,000 66 5,896 1,154 1,326 15,279 15,241 38 320,961 286 151 135 2 50 3 74 2 4 270 112 39 52 10 11 158 68 26 1 6 2 1 1 46 2 5 74 6 68 10 13 12 4 1 18 4 4 1 1 460 2 1 1 442 6 8 16 15 1 1,106 17,324 10,927 6,397 1,975 2,262 2,110 50 67,154 31,781 2,261 5,109 17,947 6,464 35,373 4,636 1,835 28,902 17,478 324 17,154 200 206 1,735 1,456 1,074 8,781 3,502 200 5,979 1,513 1,985 382 1,721 378 1,980 1,980 109,915 24,007 10,721 13,286 5,838 1,968 789 49 4,642 200,957 36,772 17,358 10,727 8,687 164,185 20,360 7,681 478 7,615 5,144 32,458 12,956 11,723 6,192 59,578 100,759 4,609 96,150 5,326 25,364 27,106 14,172 1,495 8,087 14,600 15,602 745 7,261 2,049 5,547 49,304 48,540 764 390,629 41,331 21,648 19,683 1,975 8,100 1,968 2,899 99 4,642 268,111 68,553 19,619 15,836 26,634 6,464 199,558 24,996 9,516 478 7,615 5,144 32,458 12,956 40,625 6,192 59,578 118,237 4,933 113,304 5,526 25,570 28,841 1,456 1,074 22,953 4,997 11,216 9,055 2,161 987 337 807 30 20,167 13,877 815 1,837 8,951 2,274 6,290 625 1,012 4,653 5,893 105 5,788 39 109 656 820 352 2,582 1,030 14,807 7,817 6,990 1,998 1,968 207 15 2,802 26,023 16,872 9,151 987 2,335 1,968 1,014 45 2,802 117,053 137,220 30,532 16,655 9,065 8,250 4,061 5,898 13,295 4,344 2,274 100,398 106,688 6,218 5,020 263 7,615 1,885 21,640 9,502 8,491 6,192 39,862 55,284 880 54,404 5,365 9,206 17,719 820 352 9,289 1,469 5,593 4,008 263 7,615 1,885 21,640 9,502 3,838 6,192 39,862 49,391 775 48,616 5,326 9,097 17,063 6,707 439 8,087 200 200 6,740 6,740 200 14,600 21,581 2,258 1,985 382 8,982 2,427 5,547 51,284 50,520 764 500,544 3,052 50 1,985 66 853 98 1,045 1,045 41,373 3,244 7,157 745 3,244 10,209 795 1,985 66 5,123 914 1,326 25,685 25,647 38 213,048 254,421 4,270 816 1,326 24,640 24,602 38 (a) (b) Square kilometers. 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) (units) Italy ............................................................................................... Rest of Europe .............................................................................. North Africa .................................................................................. Sub-Saharan Africa ...................................................................... Kazakhstan ................................................................................... Rest of Asia .................................................................................. Americas ....................................................................................... Australia and Oceania .................................................................. Total including equity-accounted entities .............................. ________ (a) Multiple completion wells included above: approximately 2,304 (741.7 net to Eni). Oil wells Natural gas wells Gross Net Gross Net 237.0 414.0 1,357.0 2,952.0 89.0 602.0 152.0 7.0 5,810.0 191.5 63.3 651.8 562.6 28.9 381.5 79.8 3.8 1,963.2 630.0 207.0 144.0 479.0 849.0 344.0 14.0 2,667.0 546.5 93.1 56.0 32.1 328.7 113.2 3.3 1,172.9 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 start-up at (Eni’s approximately 4 KBOE/d. interest 95%) with production 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 1965. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 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 (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. facilities was completed; 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 from export gas has subsequently been increased 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% the drilling of 2 interest. The agreement foresees 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 ((cid:1)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 ((cid:1)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. in West Karachaganak. Located onshore Kazakhstan, Karachaganak is a liquid and gas field. Operations are 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. conducted by conditions precedent, 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 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. approved by The development plan of the operated Jankrik (Eni’s interest 55%) and Jau (Eni’s interest 85%) gas fields has been authorities. Planned relevant 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 the Bontang liquefaction plant for gas, while condensates will be linked to 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). foresees extension, to gradually Development activities progressed at the Zubair oil field. The project, having a 20-year term with a further 5-year 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. the through joint venture Severenergia In September 2011, Eni signed a contract whereby Gazprom commits to purchase volumes of gas produced the by development of the Samburgskoye field. The agreement secured a final 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. investment decision for started Turkmenistan. Eni 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. activities its 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 2001. 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 Italy ........................................................................................................................................ Outside Italy ......................................................................................................................... Russia ..................................................................................................................................... Algeria (including LNG) ....................................................................................................... Libya ...................................................................................................................................... the Netherlands ..................................................................................................................... Norway ................................................................................................................................... the United Kingdom .............................................................................................................. Hungary ................................................................................................................................. Qatar (LNG) .......................................................................................................................... Other supplies of natural gas ............................................................................................... Other supplies of LNG .......................................................................................................... Total supplies of subsidiaries ............................................................................................ Withdrawals from (input to) storage .................................................................................... Network losses, measurement differences and other changes ........................................... Volumes available for sale of Eni’s subsidiaries ............................................................ Volumes available for sale of Eni’s affiliates .................................................................. E&P volumes ....................................................................................................................... 2009 2010 2011 6.86 81.79 22.02 13.82 9.14 11.73 12.65 3.06 0.63 2.91 4.49 1.34 88.65 1.25 (0.30) 89.60 7.95 6.17 (BCM) 7.29 75.20 14.29 16.23 9.36 10.16 11.48 4.14 0.66 2.90 4.42 1.56 82.49 (0.20) (0.11) 82.18 9.23 5.65 7.22 76.16 21.00 13.94 2.32 11.02 12.30 3.57 0.61 2.90 6.16 2.34 83.38 1.79 (0.21) 84.96 8.94 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 (cid:1)2.22 billion (net of limited amounts of volume make-up) and has paid the associated cash advances amounting to (cid:1)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 89.60 Total sales of subsidiaries .................................................................................................. 40.04 Italy (including own consumption) ....................................................................................... 48.65 Rest of Europe ....................................................................................................................... 0.91 Outside Europe ...................................................................................................................... 7.95 Total sales of Eni’s affiliates (Eni’s share) ....................................................................... - Italy ........................................................................................................................................ 6.80 Rest of Europe ....................................................................................................................... 1.15 Outside Europe ...................................................................................................................... 97.55 Total sales of G&P .............................................................................................................. E&P in Europe and in the Gulf of Mexico (a) ...................................................................... 6.17 Worldwide gas sales ............................................................................................................ 103.72 _______ (BCM) 82.00 34.23 46.74 1.03 9.41 0.06 7.78 1.57 91.41 5.65 97.06 84.37 34.60 45.16 4.61 9.53 0.08 7.82 1.63 93.90 2.86 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 ITALY ................................................................................................................................... 40.04 Wholesalers ........................................................................................................................... 5.92 Gas release ............................................................................................................................. 1.30 Italian gas exchange and spot markets ................................................................................. 2.37 Industries ............................................................................................................................... 7.58 Medium-sized enterprises and services ............................................................................... 1.08 Power generation ................................................................................................................... 9.68 Residential ............................................................................................................................. 6.30 Own consumption ................................................................................................................. 5.81 INTERNATIONAL SALES .............................................................................................. 63.68 Rest of Europe ..................................................................................................................... 55.45 Importers in Italy ................................................................................................................... 10.48 European markets .................................................................................................................. 44.97 Iberian Peninsula .................................................................................................................. 6.81 Germany-Austria ................................................................................................................... 5.36 Benelux .................................................................................................................................. 15.72 Hungary ................................................................................................................................. 2.58 UK-Northern Europe ............................................................................................................ 4.31 Turkey .................................................................................................................................... 4.79 France .................................................................................................................................... 4.91 Other ...................................................................................................................................... 0.49 Extra European markets ................................................................................................... 2.06 6.17 E&P in Europe and in the Gulf of Mexico ...................................................................... WORLDWIDE GAS SALES ............................................................................................ 103.72 (BCM) 34.29 4.84 0.68 4.65 6.41 1.09 4.04 6.39 6.19 62.77 54.52 8.44 46.08 7.11 5.67 14.87 2.36 5.22 3.95 6.09 0.81 2.60 5.65 97.06 34.68 5.16 5.24 7.21 0.88 4.31 5.67 6.21 62.08 52.98 3.24 49.74 7.48 6.47 11.95 2.24 6.10 6.86 7.01 1.63 6.24 2.86 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 Altergaz. 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 License 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 G&P sales ............................................................................................................................. Italy ........................................................................................................................................ Rest of Europe ....................................................................................................................... Extra European markets ........................................................................................................ E&P sales .............................................................................................................................. Liquefaction plants: - Bontang (Indonesia) ........................................................................................................... - Point Fortin (Trinidad and Tobago) .................................................................................. - Bonny (Nigeria) .................................................................................................................. - Darwin (Australia) .............................................................................................................. 2009 2010 2011 (BCM) 11.2 11.8 0.2 9.8 1.2 3.8 0.7 0.6 2.2 0.3 9.8 2.0 3.9 0.6 0.4 2.5 0.4 9.8 0.1 8.9 0.8 3.1 0.8 0.5 1.4 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 Power generation sold ........................................................................................................... Trading of electricity (a).......................................................................................................... 24.09 9.87 (TWh) 25.63 13.91 25.23 15.05 Power sales by market Free market ............................................................................................................................ Italian Exchange for electricity ............................................................................................ Industrial plants ..................................................................................................................... Other (a) ................................................................................................................................... 33.96 39.54 40.28 24.74 4.70 2.92 1.60 27.48 7.13 3.21 1.72 26.87 8.67 3.23 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 Brindisi .................................................................................................... Ferrera Erbognone ................................................................................... Livorno .................................................................................................... Mantova ................................................................................................... Ravenna ................................................................................................... Taranto ..................................................................................................... Ferrara ...................................................................................................... Bolgiano ................................................................................................... Nettuno .................................................................................................... _______ (1) Capacity available after completion of dismantling of obsolete plants. Total installed capacity in 2011(1) (MW) Technology Fuel 1,321 1,030 CCGT CCGT 199 Power station 836 CCGT CCGT 972 75 Power station 841 CCGT 30 Power station 2 Power station gas gas/syngas gas/fuel oil gas gas gas/fuel oil gas gas photovoltaic energy 5,306 Power Generation 2009 2010 2011 Purchases Natural gas .............................................................................................................. (mmCM) (ktoe) Other fuels ............................................................................................................... - of which steam cracking....................................................................................... Production 25.23 Electricity................................................................................................................. Steam........................................................................................................................ (ktonnes) 10,048 10,983 14,401 Installed generation capacity............................................................................... 5.3 5,154 547 103 5,008 528 99 4,790 569 82 25.63 24.09 (TWh) (GW) 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 ITALY Mazara del Vallo-Minerbio (under upgrading) Tarvisio-Sergnano-Minerbio Passo Gries-Mortara OUTSIDE ITALY (2) TTPC (Oued Saf Saf-Cap Bon) TMPC (Cap Bon-Mazara del Vallo) GreenStream (Mellitah-Gela) Blue Stream (Beregovaya-Samsun) _______ Lines (units) Length of main line Diameter Transport capacity (1) Pressure min-max Compression stations (km) (inch) (mmCM/d) (bar) (No.) 2/3 3 1/2 1,480 48/42 - 48 434 42/36, 34 and 48/56 48/34 177 105.0 118.8 64.4 75 58/75 55/75 7 3 1 Lines Total length Diameter Transport capacity (3) Transit capacity (4) Compression stations (units) 2 lines of km 370 5 lines of km 155 1 line of km 520 2 lines of km 387 (km) (inch) (BCM/y) (BCM/y) (No.) 740 775 520 774 48 20/26 32 24 34.0 33.5 8.0 16.0 33.2 33.5 8.0 16.0 5 1 1 (1) (2) (3) (4) Transport capacity refers to the capacity at the entry point connected to the import pipelines. 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. Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline. 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. The South Stream project Eni and Gazprom are jointly assessing the technical and economic feasibility of the offshore section in the Black Sea of a project to build a new import route to Europe to market gas produced in Russia. The South Stream pipeline will provide transport capacity of up to 63 BCM/y and is expected to be composed by two sections: (i) an offshore section crossing the Black Sea from the Russian coast at Beregovaya (the same starting point of the Blue Stream pipeline) to the Bulgarian coast at Varna; and (ii) an onshore section crossing Bulgaria for which two options are currently being evaluated: one pointing North West and another one pointing South West. The second option envisages crossing Greece and the Adriatic Sea before linking to the Italian network. In September 2011, Eni and Gazprom within their strategic partnership signed a series of agreements in areas of common interest including the development of the offshore section in the Black Sea of the South Stream project through the definition of terms for the participation to the project of gas operators Wintershall and EDF, each with a 15% stake. Gazprom and Eni will hold 50% and 20% interests, respectively. Final Investment Decision (FID) expected by November 2012. Regulated businesses in Italy Reorganization of Regulated businesses in Italy. Implementing the so-called Third Energy Package (for further details see “Regulation of Eni’s Businesses” below), on December 5, 2011 with effect from January 1, 2012, “Snam Rete Gas SpA” changed its company name in “Snam SpA”. At the same date Snam SpA transferred the “transportation, dispatching and metering of natural gas” business unit to a new company that from January 1, 2012, took the name of Snam Rete Gas SpA. The reorganization of Regulated businesses in Italy based on Snam SpA as holding the 100% interest in the four companies operating the transport, re-gasification, storage and distribution of natural gas, intends to build an organizational model meeting the new legal provisions on the unbundling of transport activities as provided by Italian laws implementing European Directive No. 2009/73/EC. The AEEG (the Italian Authority for Electricity and Gas) is currently assessing the conformity to the law of the model adopted by Snam SpA. Eni, through Snam SpA (Eni’s interest being 52.53%), which is listed on the Italian Stock Exchange, operates most of the Italian natural gas transport network, a re-gasification terminal located in Panigaglia, an extensive local distribution network and gas underground storage deposits and related facilities. In the next four years, Snam plans to make capital expenditures in the regulated businesses in the amount of approximately (cid:1)6.7 billion of which 1.4 billion will be spent in 2012. These investments will be aimed at improving the security and flexibility of the gas system, through: (i) increasing gas transport capacity by extending the gas network by about 1,000 kilometers from the approximately 32,000 kilometers as at 2011 and by increasing the installed power of the compression stations by around 4% versus 2011; and (ii) improving the overall flexibility and security of the storage system through an increase in both the modulation and peak capacity and providing storage services to the industrial market, in line with the provisions of the Legislative Decree No. 130/2010. Capital expenditures in the storage business are expected to deliver a 30% increase in the modulation capacity (from 10 billion standard cubic meters in 2011 to around 13 billion standard cubic meters by 2015) and a 14% increase in the peak capacity in the period; and (iii) operating efficiency and improvement of quality of gas distribution service. The projects included in the plan should lead to a rise in the number of current users reaching approximately 6.4 million in 2015, an increase of around 8% compared to the 5.9 million redelivery points installed as at 2010. With the execution of the 4-year investment plan, the value of the Company’s Regulated Asset Base (RAB) is estimated to increase by an average of 4% per year through 2015, on the basis of the current regulatory framework. It is also expected that the incentivized portion of the RAB will reach 40% in 2015 as compared to 26% in 2011. Eni, through Snam, operates the re-gasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can re-gasify 17,500 CM of LNG per day and input 3.5 BCM/y into the Italian transport network. 71 Italian Transport Activity Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport and re-gasification activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This makes transport a low risk business capable of delivering stable returns. Eni’s network extends for 32,010 kilometers and comprises: (i) a national transport network extending over 9,080 kilometers, made up of high pressure trunk-lines mainly with a large diameter, which carry natural gas from the entry points to the system – import lines, storage sites and main Italian natural gas fields – to the linking points with regional transport networks. The national network includes also some interregional lines reaching important markets; and (ii) a regional transport network extending over 22,930 kilometers, made up of smaller lines and allowing the transport of natural gas to large industrial complexes, power stations and local distribution companies in the various local areas served. The major pipelines interconnected with import trunk-lines that are part of Eni’s national network are: • • • • • • for natural gas imported from Algeria (Mazara del Vallo delivery point): - two lines with a 48/42-inch diameters, each approximately 1,500-kilometer long, including the smaller pipes that cross underwater the Messina Strait, connect Mazara del Vallo on the Southern coast of Sicily where they link with the TMPC pipeline carrying Algerian gas, to Minerbio (near Bologna). This pipeline is undergoing upgrades with the laying of a third line with a 48-inch diameter and 583-kilometer long (of these 525 are already operating). At the Mazara del Vallo entry point the available transport capacity, which is measured at the beginning of each thermal year starting on October 1, is approximately 105 mmCM/d; for natural gas imported from Libya (Gela delivery point): - a 36-inch diameter line and 67-kilometer long linking Gela, the entry point of the GreenStream underwater pipeline, to the national network near Enna along the trunk-line transporting gas coming from Algeria. Transport capacity at the Gela entry point is approximately 38 mmCM/d; for natural gas imported from Russia (Tarvisio and Gorizia delivery points): - two lines with 42/36/34-inch diameters extending for a total length of approximately 900 kilometers connecting the Austrian network at Tarvisio. This facility crosses the Po Valley reaching Sergnano (near Cremona) and Minerbio. This pipeline is undergoing upgrades by the laying of a third 264-kilometer long line with a diameter from 48 to 56 inches. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 119 mmCM/d plus the transport capacity available at the Gorizia entry point of approximately 5 mmCM/d; for natural gas imported from the Netherlands and Norway (Passo Gries delivery point): - one line, with a 48-inch diameter and 177-kilometer long that extends from the Italian border at Passo Gries (Verbania), to the node of Mortara, in the Po Valley. The pipeline transport capacity at the Passo Gries entry point amounts to 64 mmCM/d; for natural gas coming from the Panigaglia LNG terminal: - one line, with a 30-inch diameter and 170-kilometer long that links the Panigaglia terminal to the national transport network near Parma. The pipeline transport capacity at the Panigaglia entry point amounts to 13 mmCM/d; and for natural gas coming from the Rovigo Adriatic LNG terminal: - a 36-inch diameter connection at the Minerbio junction with the Cavarzere-Minerbio pipeline belonging to Edison Stoccaggio SpA, which receives gas from the LNG terminal located offshore of Porto Viro. The pipeline transport capacity at the Cavarzere entry point amounts to 26 mmCM/d. Eni’s system is completed by: (i) eleven compressor stations with a total power of 883.7 MW used to increase gas pressure in pipelines to the level required for its flow; and (ii) four marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo and Messina in Sicily and Favazzina and Palmi in Calabria. The interconnections managed by Snam Rete Gas in the Italian transport network are guaranteed by 22 linkage and dispatching nodes and by 568 plant units including pressure reduction and regulation plants. These plants allow the regulation of the flow of natural gas in the network and guarantee the connection of pipes working at different pressures. In 2011, volumes of natural gas input in the national grid (78.30 BCM) decreased by 5.01 BCM from 2010 due to declining domestic demand. Eni transported 43.18 BCM of natural gas on behalf of third parties, down 4.68 BCM from 2010, or 9.8%. 72 Gas volumes transported (a) Eni .......................................................................................................................................... On behalf of third parties ...................................................................................................... 2009 2010 2011 39.58 37.32 76.90 (BCM) 35.45 47.86 83.31 35.12 43.18 78.30 ________ (a) Includes amounts destined to domestic storage. In 2011, the LNG terminal in Panigaglia (La Spezia) re-gasified 1.89 BCM of natural gas (1.98 BCM in 2010). Development of gas infrastructure in Europe. In January 2012, Snam and Fluxys G signed an agreement for the evaluation of future joint strategies aimed at seizing potential development opportunities concerning infrastructures in the gas sector in Europe. The agreement concerns transport, storage and re-gasification of natural gas, by means of projects aimed at strengthening flexibility and security of supplies of European infrastructure. Distribution Activity Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. The Company’s subsidiary Italgas and other subsidiaries operate in the distribution activity in Italy serving 1,330 municipalities through a low pressure network consisting of approximately 50,300 kilometers of pipelines supplying 5.9 million customers and distributing 7.64 BCM in 2011. Under Legislative Decree No. 164/2000, distribution activities are considered a public service and therefore are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This business, therefore, presents low risk and a steady cash generation profile. Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. In accordance with the provisions of the relevant legislation, tenders for new natural gas distribution concessions will no longer be issued by each municipality but exclusively by the multi- municipality minimum geographical areas (known as “Ambiti Territoriali Minimi - ATEM”, or local areas). Distribution activity in Italy 2009 2010 2011 Volumes distributed: ........................................................................................ - on behalf to Eni ............................................................................................... - on behalf to third parties ................................................................................. Installed network ............................................................................................... Active meters ..................................................................................................... Municipalities served ........................................................................................ (BCM) (km) (No. of users) (No.) 7.73 6.26 1.47 49,973 8.15 6.30 1.85 50,307 7.64 5.59 2.05 50,301 5,770,672 5,848,478 5,896,611 1,330 1,330 1,322 Storage The storage gas business in Italy is a fully-regulated activity which returns are preset by the Italian Authority for Electricity and Gas. Italian regulated storage services are provided through eight storage fields, based on ten storage concessions vested by the Ministry of Productive Activities, with a total modulation capacity of 10 BCM. From the beginning of its operations, Stogit progressively increased the number of customers served and the share of revenues from third parties. 73 Storage Total storage capacity: ......................................................................... - of which strategic storage .................................................................. - of which available storage ................................................................. Available capacity: - share utilized by Eni .......................................................................... - share utilized by third parties ............................................................ Total offtake from (input to) storage: .................................................. - input to storage ................................................................................... - offtake from storage .......................................................................... Total customers .................................................................................... 2009 2010 2011 13.9 5.0 8.9 30 70 16.52 7.81 8.71 56 14.2 5.0 9.2 29 71 15.59 8.00 7.59 60 15.0 5.0 10.0 22 78 15.31 7.78 7.53 104 (BCM) (%) (%) (BCM) (No.) In 2011, 7.78 BCM (down 0.22 BCM from 2010) were input to the Company’s storage deposits, while 7.53 BCM of gas were off-taken (slightly lower than one year ago). In 2011, storage capacity amounted to 15 BCM, of which 5 were destined to strategic storage. The share of storage capacity used by third parties was 78% (71% in 2010). Capital Expenditures See “Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment”. Refining & Marketing Eni’s Refining & Marketing segment engages in the supply of crude oil, refining and marketing of refined products, trading and shipping of crude oil and product primarily in Italy and in Central-Eastern Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company’s operations are fully- integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations. In 2011, the Refining & Marketing segment recorded sharply lower operating losses than a year ago. The main drivers were unprofitable refining margins as high costs of oil-based feedstock were only partially transferred to product prices pressured by weak demand, high inventories and excess capacity, particularly in the Mediterranean area. In addition, increased oil prices triggered higher costs of energy utilities which are typically indexed to it. Finally, narrowing light-heavy crude price differentials reduced the cost advantage of Eni’s complex refineries which are able to maximize the yields of valuable products from processing of heavy crudes. Looking forward, management does not expect any meaningful improvement in the trading environment over the next four years of the industrial plan. The ongoing economic downturn is anticipated to weigh on the recovery of demand for fuels, while high costs of the crude oil feedstock and energy utilities will continue squeezing refining margins. On the supply side, it is unlikely that ongoing capacity rationalization will help absorb product surpluses on the short term. Also retail and wholesale marketing activities of refined products will be affected by sluggish demand and product oversupply that is expected to trigger pricing competition. Furthermore, we expect that the ongoing liberalization process in Italy will add further competitive pressure and reduce sales opportunities, despite the possibility to develop non-oil activities. See “Item 3 – Risk Factors” and “Regulation” below. Against the backdrop of a challenging market environment and in the midst of an industry downturn, we plan to implement all available levers to improve operations efficiency and profitability. The main planned initiatives in our refining operations are: • • • • to pursue integration of refinery cycles in order to maximize the value of internally-produced semi-finished products and other feedstock; to maximize refinery flexibility and conversion to take advantage of the availability of discounted crudes on the market place; to enhance energy efficiency and plant reliability; to rationalize logistic costs and pursue other cost measures; 74 • • to strictly select capital expenditures; and to boost margins leveraging on risk management activities. In the marketing activity, we plan to preserve our profitability by: • • enhancing our lead on the domestic market; preserving our customer base by effective marketing actions, rolling out our “eni” brand and service excellence; boosting margins by increasing the number of fully automated outlets and the contribution from non-oil products and services; and selectively growing our market share in European markets. • • In the 2012-2015 period, we plan to make capital expenditures amounting to (cid:1)2.8 billion, in line with the previous plan, carefully selecting capital projects. Management plans to invest approximately (cid:1)2 billion to upgrade the Company’s best refineries mainly by completing and starting-up the EST (Eni Slurry Technology) project at the Sannazzaro unit which will upgrade the conversion capacity of the refinery, as well as improving plant efficiency and reliability. Retail activities will attract some 25% of the planned expenditure which will be mainly directed to upgrade and modernize our service stations in Italy and in selected European countries, and to complete the network rebranding. As a result of all these actions, management believes that the Refining & Marketing segment will improve results by (cid:1)550 million by 2015 (at the same scenario experienced in 2011) with over (cid:1)400 million coming from the Refining activity. The matters regarding future plans 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 include difficulties in obtaining approvals from relevant Antitrust Authorities and developments in the relevant market. Supply In 2011, a total of 59.02 mmtonnes of crude were purchased by the Refining & Marketing segment (68.25 mmtonnes in 2010), of which 27.64 mmtonnes from Eni’s Exploration & Production segment. Volumes amounting to 20.44 mmtonnes were purchased on the spot market, while 10.94 mmtonnes were purchased under long-term supply contracts with producing countries. Approximately 27% of crude purchased in 2011 came from Russia, 20% from West Africa, 11% from the North Sea, 11% from the Middle East, 9% from North Africa, 6% from Italy, and 16% from other areas. In 2011, some 32.10 mmtonnes of crude purchased were marketed (down approximately 4.07 mmtonnes, or 11.3%, from 2010). In addition, 4.26 mmtonnes of intermediate products were purchased (3.05 mmtonnes in 2010) to be used as feedstock in conversion plants and 15.85 mmtonnes of refined products (15.28 mmtonnes in 2010) were purchased to be sold on markets outside Italy (12.45 mmtonnes) and on the domestic market (3.40 mmtonnes) as a complement to available production. Refining As of December 31, 2011, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 38.3 mmtonnes (equal to 767 KBBL/d) and a conversion index of 61%. The conversion index is a measure of a refinery complexity. The higher the index, the wider the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies which the Company generally expects to achieve as certain qualities of crude (particularly the heavy ones) may trade at discount with reference to the light crude Brent benchmark. Eni’s five 100-percent owned refineries have balanced capacity of 28.7 mmtonnes (equal to 574 KBBL/d), with a 64% conversion rate. In 2011, refinery throughputs in Italy and outside Italy were 31.96 mmtonnes. The Company plans to selectively upgrade its refining system by increasing complexity and flexibility at its best refineries. The main capital project will be the completion of a new conversion unit at the Sannazzaro refinery designed on the EST proprietary technology for converting the heavy barrel by almost eliminating residue from conversion processes. The start-up of this of this plant is planned to be in the last months of 2012. Higher conversion capacity is expected to enable the Company to extract value from both from conventional crudes as well as to get opportunities from extra-heavy crudes and non-conventional raw materials. 75 The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2011. Refining system in 2011 Ownership share (%) Distillation capacity (total) (KBBL/d) Distillation capacity (Eni’s share) (KBBL/d) Primary balanced refining capacity (Eni’s share) (KBBL/d) Conversion index (1) (%) Fluid catalytic cracking - FCC (2) (KBBL/d) Residue conversion (KBBL/d) Go-Finer (KBBL/d) Mild Hydro- cracking/ Hydro- cracking (KBBL/d) Visbreaking/ thermal cracking (KBBL/d) Coking (KBBL/d) Distillation capacity utilization rate (Eni’s share) (%) Balanced refining capacity utilization rate (Eni’s share) (%) Wholly owned refineries Italy Sannazzaro Gela Taranto Livorno Porto Marghera Partially owned refineries (3) Italy Milazzo Germany Vohburg/Neustadt (Bayernoil) Schwedt Czech Republic Kralupy e Litvinov Total refineries ________ 100 100 100 100 100 50 20 8.33 32.4 685 223 129 120 106 107 874 248 215 231 180 1,559 685 223 129 120 106 107 245 124 43 19 59 930 574 190 100 120 84 80 193 80 41 19 53 767 64 59 142 72 11 20 51 76 36 42 30 61 69 34 35 167 45 49 49 24 236 37 37 42 12 30 25 25 67 37 29 29 99 32 43 24 128 46 46 89 29 38 22 27 27 116 46 66 80 50 83 67 38 88 89 92 105 79 72 79 94 65 83 85 51 101 119 92 105 88 85 (1) (2) (3) Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity. Conversion plant where vacuum feedstock undergoes cracking at high pressure and moderate temperature thus producing mostly high quality gasoline. This kind of plant guarantees high operating flexibility to the refinery. Capacity of conversion plant is 100%. Italy Eni’s refining system in Italy is composed of five wholly-owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy have operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to end markets and the integration with Eni’s other activities. The Sannazzaro refinery has balanced refining capacity of 190 KBBL/d and a conversion index of 59%. Management believes that this unit is among the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-Western Italy and Switzerland. The high degree of flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdCK), with the last unit entered into operations in June 2009, which enable middle distillate conversion and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. Eni is developing a conversion plant employing the Eni Slurry Technology with a 23 KBBL/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled by the end of 2012. In addition the Short Contact Time-Catalytic Partial Oxidation project is underway for the production of hydrogen. This reforming technology will exploit a proprietary technology which allows transforming gaseous and liquid hydrocarbons (also derived from bio-mass) into synthetic gas (carbon monoxide and hydrogen). The Taranto refinery has balanced refining capacity of 120 KBBL/d and a conversion index of 72%. This refinery can process a wide range of crude and other feedstock. It principally produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2011, a total of 2.5 mmtonnes of this oil were processed). The Gela refinery has balanced refining capacity of 100 KBBL/d and a conversion index of 142%. This refinery is located on the Southern coast of Sicily and is integrated with upstream operations as it processes heavy crude produced from Eni’s nearby offshore and onshore fields in Sicily. Its high conversion level is ensured by an FCC unit with go-finer for feedstocks upgrading and two coking plants enabling conversion of heavy residues topping or vacuum residues. The power plant of this refinery also contains residue and exhaust fume treatment plants (so-called SNOx) which allow full compliance with the tightest environmental standards, removing almost all sulphur and nitrogen composites coming from the coke burning-process. An upgrade of the Gela refinery is underway by means of a refurbishment of its power plant, substantially renewing pet-coke boilers, aimed at increasing profitability maximizing synergies deriving from the integration of refining and power generation. 76 The Livorno refinery, with balanced refining capacity of 84 KBBL/d and a conversion index of 11%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its pipeline links with the local harbor and with the Florence storage sites by means of two pipelines optimizes intake, handling and distribution of products. The Porto Marghera refinery, with balanced refining capacity of 80 KBBL/d and a conversion index of 20%, this refinery supplies mainly markets in North-Eastern Italy and Austria. Besides its primary distillation plants, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) designed to increase yields of valuable products. Rest of Europe In Germany, Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that included Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 60 KBBL/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. Eni holds a 32.4% stake in Ceska Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to about 53 KBBL/d to support its marketing activities in Eastern Europe. The table below sets forth Eni’s petroleum products availability figures for the periods indicated. Availability of refined products ITALY Refinery throughputs At wholly-owned refineries ................................................................................................... Less input on account of third parties ................................................................................... At affiliates refineries ............................................................................................................ Refinery throughputs on own account.............................................................................. Consumption and losses ........................................................................................................ Products available for sale.................................................................................................. Purchases of refined products and change in inventories.................................................... Products transferred to operations outside Italy ................................................................... Consumption for power generation....................................................................................... Sales of products................................................................................................................... OUTSIDE ITALY Refinery throughputs on own account.............................................................................. Consumption and losses ........................................................................................................ Products available for sale.................................................................................................. Purchases of finished products and change in inventories .................................................. Products transferred from Italian operations ........................................................................ Sales of products................................................................................................................... Refinery throughputs on own account.............................................................................. of which: refinery throughputs of equity crude on own account......................................... Total sales of refined products .......................................................................................... Crude oil sales....................................................................................................................... 2009 2010 2011 (mmtonnes) 24.02 (0.49) 5.87 29.40 (1.60) 27.80 3.73 (3.89) (0.96) 26.68 5.15 (0.25) 4.90 10.12 3.89 18.91 34.55 5.11 45.59 36.11 25.70 (0.50) 4.36 29.56 (1.69) 27.87 4.24 (4.18) (0.92) 27.01 5.24 (0.24) 5.00 10.61 4.18 19.79 34.80 5.02 46.80 36.17 22.75 (0.49) 4.74 27.00 (1.55) 25.45 3.22 (1.77) (0.89) 26.01 4.96 (0.23) 4.73 12.51 1.77 19.01 31.96 6.54 45.02 32.10 TOTAL SALES .................................................................................................................... 81.70 82.97 77.12 In 2011, refining throughputs were 31.96 mmtonnes, down 8.2% from 2010. Volumes processed in Italy decreased by approximately 2.84 mmtonnes, or 8.7%, from 2010, reflecting the decision to cut throughputs at the Venice plant in response to an unfavorable market scenario and unexpected standstills, in addition to planned standstill at the other plants. Eni’s refining throughputs outside Italy decreased by 5.3% mainly in the Czech Republic as a consequence of the planned downtime at the Litvinov refinery. Total throughputs in wholly-owned refineries were 22.75 mmtonnes, down by 2.95 mmtonnes (or 11.5%) from 2010, determining a refinery utilization rate of 79%, declining from 2010 consistent with the unfavorable scenario. Approximately 22.3% of volumes of processed crude was supplied by Eni’s Exploration & Production segment (15.8% in 2010) representing a 6.5 percentage point increase from 2010, corresponding to higher volume of approximately 1.52 mmtonnes. 77 Logistics Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 20 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude. Eni’s logistic model is organized in a hub structure including five main areas. These hubs monitor and centralize the handling of product flows aiming to drive forward more efficiency particularly in cost control of collection and delivery of orders. Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic cost, and increasing efficiency. Eni operates in the transport of oil and refined products: (i) by sea through spot and long-term lease contracts of tanker ships; and (ii) on land through the ownership of a pipeline network extending approximately 1,447 kilometers. Secondary distribution to retail and wholesale markets is effected through third parties who also own their means of transportation, in some instances with minority participation of Eni. Marketing Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive operated network of service stations, franchises and other distribution systems. The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated. Oil products sales in Italy and outside Italy Italy Retail ...................................................................................................................................... Wholesale .............................................................................................................................. Petrochemicals........................................................................................................................ Other sales .............................................................................................................................. Total ....................................................................................................................................... Outside Italy Retail ...................................................................................................................................... Wholesale .............................................................................................................................. Other sales ............................................................................................................................. Total ....................................................................................................................................... 2009 2010 2011 (mmtonnes) 9.03 9.56 18.59 1.33 6.76 26.68 2.99 4.07 7.06 11.85 18.91 8.63 9.45 18.08 1.72 7.21 27.01 3.10 4.30 7.40 12.39 19.79 8.36 9.36 17.72 1.71 6.58 26.01 3.01 4.27 7.28 11.73 19.01 TOTAL SALES .................................................................................................................... 45.59 46.80 45.02 In 2011, sales volumes of refined products (45.02 mmtonnes) decreased of 1.78 mmtonnes from 2010, or 3.8%, mainly due to lower volumes sold in all the relevant segments on the domestic and foreign market. Retail Sales in Italy The re-branding of Eni’s service stations continued in 2011. We plan that by the end of 2012 80% of our proprietary service stations will have been re-branded to the “eni brand”. In the context of weak domestic demand for fuels and rising competition, management plans to preserve the market share achieved in 2011 (30.5%) by improving service quality, upgrading our outlets, retaining customers by means of innovative marketing actions and segmentation of the offering (in function of payment modalities or quality of the product, enhancing the role of loyalty programs). Great focus will be dedicated to improve efficiency by the automation of part of the network. Finally we expect a growing contribution to profitability by non-oil activities as we intend to expand the quality and range of products and services offered to our customers and pursue continuing innovation in the layout of our stores located at our proprietary outlets. In 2011, retail sales in Italy of 8.36 mmtonnes decreased by approximately 270 ktonnes, down 3.1% driven by lower consumption of gasoil and gasoline, in particular in highway service station related to the decline in freight transportation. Average throughput related to gasoline and gasoil (2,173 kliters) decreased by approximately 149 kliters from 2010. Eni’s retail market share for 2011 was 30.5%, up 0.1 percentage point from 2010 (30.4%). At December 31, 2011, Eni’s retail network in Italy consisted of 4,701 service stations, 159 more than at December 31, 2010 (4,542 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (158 units), the 78 opening of new service stations (14 units), partly offset by the closing of service stations with low throughput (13 units). In 2011 even sales of premium fuels (fuels of the “eni blu+” line with high performance and lower environmental impact), despite the support of strong promotional campaigns were affected by the decline in domestic consumption and were lower than the previous year. In particular, sales of eni BluDiesel+ amounted to approximately 493 mmtonnes (approximately 592 mmliters) with a decline of approximately 80 ktonnes from 2010 and represented 9% of volumes of gasoil marketed by Eni’s retail network. At December 31, 2011, service stations marketing BluDiesel+ totaled 4,130 units (4,071 at 2010 year end) covering approximately 88% of Eni’s network. Retail sales of BluSuper+ amounted to 62 ktonnes (approximately 83 mmliters), with a slight decrease from 2010 and covered 2.4% of gasoline sales on Eni’s retail network (down 0.2% from a year ago). At December 31, 2011, service stations marketing BluSuper+ totaled 2,703 units (2,672 at December 31, 2010), covering approximately 57% of Eni’s network. Eni was also engaged in increasing its supply of non-oil products and services in its service stations in Italy by developing a chain of franchised outlets, in particular: (i) “enicafè”, a format present in 350 stations after the upgrading of bars and stores in its network; (ii) “enicafè&shop”, a format including corners for the sale of food and car-care products in 200 Eni outlets. In 2011 Eni also launched a new self-service option h.24 of food, non-food and personal care products by means of the installation of eni branded vending machines in 150 outlets with the aim of extending this service to over 1,000 outlets in the next two years. Retail Sales in the Rest of Europe Eni’s strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany and Eastern Countries (e.g. Czech Republic) leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities. In 2011, retail sales of refined products marketed in the rest of Europe (3.01 mmtonnes) were down 2.9% (approximately 90 ktonnes) from 2010. Volume additions in Austria, reflecting the purchase of service stations, were offset by lower sales in Germany due to certain lease contract terminations, in France due to the rationalization of service stations with lower throughput and in Eastern Europe due to declining demand. At December 31, 2011, Eni’s retail network in the rest of Europe consisted of 1,586 units, a decrease of 39 units from December 31, 2010 (1,625 service stations). The network evolution was as follows: (i) the closing of 41 low throughput service stations mainly in Austria and France; (ii) the negative balance of acquisitions/releases of lease concessions (17 units) with negative changes in particular in Germany, Austria and Switzerland; (iii) the purchase of 12 service stations, in particular in France and Germany; and (iv) the opening of 7 new outlets. Average throughput (2,299 kliters) decreased by 142 kliters from 2010 (2,441 kliters). The key markets of Eni’s presence are: Austria with a 9.6% market share, Hungary with 11.9%, Czech Republic with 11.6%, Slovakia with 10.9%, Switzerland with 6.6% and Germany with a 3.1% on national base. These market shares were calculated by Eni based on public data of national consumption and Eni’s sales volumes. Non-oil activities in the rest of Europe are present in 1,101 service stations (eni owned network), of which 321 are in Germany and 144 in France. Other businesses Wholesale Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Along with traditional products provided with the high quality Eni standard, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and concessionaires. In 2011, sales volumes on wholesale markets in Italy (9.36 mmtonnes) were down by approximately 90 ktonnes from 2010, or 1%, mainly reflecting a decline in demand from transports and industrial customers due to a generalized slowdown and strong competitive pressure which affected in particular bunkering and bitumen, but also LPG due to unusual weather conditions. Jet fuel and fuel oil sales increased, while gasoil sales dropped starkly in 2011. Eni’s wholesale market share for 2011 averaged 28.3%, down 0.9 percentage points from 2010 (29.2%). Supplies of feedstock to the petrochemical industry (1.71 mmtonnes) were basically in line with 2010 recording a slight decline of 79 10 ktonnes related to lower feedstock supplies due to lower demand from industrial customers. Sales on wholesale markets outside Italy (3.84 mmtonnes) decreased by 1%, mainly in Hungary, Germany and the Czech Republic, while sales increased in Austria, Switzerland and France. Other sales (18.31 mmtonnes) decreased by 1.29 mmtonnes, or 6.6%, mainly due to lower sales volumes to oil companies. Eni also markets jet fuel directly at 49 airports, of which 27 are in Italy. In 2011, these sales amounted to 2.1 mmtonnes (of which 1.6 mmtonnes are in Italy). Eni is also active in the international market of bunkering, marketing marine fuel mainly in 120 ports, of which 80 are in Italy. In 2011, marine fuel sales were 1.98 mmtonnes (1.91 mmtonnes in Italy). LPG In Italy, Eni is leader in LPG production, marketing and sale with 601 ktonnes sold for heating and automotive use equal to a 18.9% market share. An additional 214 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna. Outside Italy, LPG sales in 2011 amounted to 485 ktonnes of which 384 ktonnes in Ecuador where LPG market share is around 37.5%. Lubricants Eni operates seven (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state-of-the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero. In 2011, retail and wholesale sales in Italy amounted to 100 ktonnes with a 23.6% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 140 ktonnes, of these about 60% were registered in Europe (mainly Spain, Germany, Austria and France). Oxygenates Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sells approximately 1.7 mmtonnes/y of oxygenates mainly ethers (approximately 5.3% of world demand) and methanol (approximately 0.9% of world demand). About 80% of products are manufactured in Italy in Eni’s plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 20% is bought and resold. Eni also distributes bio- ETBE on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio- ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. Starting from March 1, 2010, Italian regulation on bio-fuels content has been changed from 3% to 3.5%. Through Bio-ETBE and FAME blending into fossil fuels Eni covered the compliance within 96% in 2011. From January 1, 2012, the compulsory content of bio-fuels increases to 4.5% from 2011 4%, Eni plans to cover compliance through Bio-ETBE, FAME and direct blending of ethanol in gasolines in particular in some extents of Sannazzaro refinery inland. Capital Expenditures See “Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment”. 80 Engineering & Construction Eni engages in engineering, construction and drilling both offshore and onshore for the oil&gas industry through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 42.91%), and Saipem’s controlled entities. Saipem boasts a strong competitive position in the market for services to the oil industry, particularly in executing large, complex EPC contracts for the construction of offshore and onshore facilities and systems to develop hydrocarbons reserves as well as LNG, refining and petrochemicals plants, pipeline layering and offshore and onshore drilling services. The Company owes its market position to technological and operational skills which we believe are acknowledged in the marketplace due to its capabilities to operate in frontier areas and complex ecosystems, efficiently and effectively managing large projects, engineering competencies and availability of technologically-advanced vessels and rigs which have been upgraded in recent years through a large capital expenditure plan. Management expects to further strengthen Saipem’s competitive position in the medium term, leveraging on its business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. In particular, Saipem plans to implement the following strategic guidelines: (i) to maximize efficiency in all business areas at the same time maintaining top execution and security standards, preserve competitive supply costs, optimize the utilization rate of the fleet, increase structure flexibility in order to mitigate the effects of negative business cycles as well as develop and promote a company culture that will permit identification and management of risks and business opportunities; (ii) to continue focusing on the more complex and difficult projects in the strategic segments of deepwater, FPSO, heavy crude and LNG (offshore and onshore, for the gas monetization) upgrading; (iii) to promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries; (iv) to leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition; and (v) to complete the expansion and revamping program of its construction and drilling fleet in consideration of the future needs of the oil&gas industry, in order to confirm the Company’s leading position in the segment of complex projects with high profitability. Saipem expects to invest approximately (cid:1)2.4 billion over the next four years to complete the upgrading program of its fleet of vessels and rigs, further expanding the operational features, the dimension and the geographical reach and of its fleet as well as to support the activities related to the execution of projects in portfolio and the acquisition of new orders. Orders acquired in 2011 amounted to (cid:1)12,505 million, of these projects 91% are to be carried out outside Italy, while orders from Eni companies represented 7% of the total. Order backlog was (cid:1)20,417 million as of December 31, 2011 ((cid:1)20,505 million as of December 31, 2010). Projects to be carried out outside Italy represented 91% of the total order backlog, while orders from Eni companies amounted to 14% of the total. Orders acquired ......................................................................................... Engineering & Construction Offshore........................................................ Engineering & Construction Onshore......................................................... Offshore drilling........................................................................................... Onshore drilling............................................................................................ Originated by Eni companies ...................................................................... To be carried out outside Italy..................................................................... Order backlog and breakdown by business........................................... Engineering & Construction Offshore........................................................ Engineering & Construction Onshore......................................................... Offshore drilling........................................................................................... Onshore drilling............................................................................................ Originated by Eni companies ...................................................................... To be carried out outside Italy..................................................................... ((cid:1) million) (%) (%) ((cid:1) million) (%) (%) 2009 2010 2011 9,917 12,935 12,505 6,131 4,600 5,089 5,006 7,744 3,665 780 326 585 588 265 578 7 7 32 91 94 79 18,730 20,505 20,417 6,600 5,430 5,544 9,604 8,035 10,543 3,301 3,354 3,778 912 1,064 1,487 14 16 22 91 94 93 Engineering & Construction Offshore Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies (“NOCs”). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction 81 process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a pipelayer, a field development ship for deepwater, an FPSO and other supporting assets for offshore activity. Saipem’s Offshore construction fleet is made up 35 vessels and a large number of robotized vehicles able to perform advanced subsea operations. Its major vessels are: (i) the Saipem 7000 semi-submersible dynamic positioned vessel, with 14 ktonnes of lift capacity, capable to lay pipelines using the J-lay technique to the maximum depth of 3,000 meters; (ii) the Field Development Ship for the development of underwater fields in dynamic positioning, provided with cranes lifting up to 600 tonnes and a system for J-lay pipe laying to a depth of 2,000 meters; (iii) the Castoro 6 semi-submersible vessel, capable of laying pipes in waters up to 1,000 meters deep; (iv) the Saipem 3000 multifunction vessel for the development of hydrocarbon fields, able to lay rigid and flexible pipes and provided with cranes capable of lifting over 2 ktonnes; and (v) the Semac semi-submersible vessel used for large diameter underwater pipe laying. The fleet also includes remotely operated vehicles (ROV), highly sophisticated and advanced underwater robots capable of performing complex interventions in deep waters. The most significant order awarded in 2011 in Engineering & Construction offshore construction were: (i) the EPIC contract on behalf of South Oil Co for the expansion of the Basra oil center and related infrastructures in the field of the Iraq Crude Oil Export Expansion - Phase 2 project; (ii) the EPIC contract on behalf of Saudi Aramco for the realization of the offshore infrastructures in the field of the development of the offshore fields Arabiyah and Hasbah in the Arabian section of the Persian Gulf; and (iii) an EPIC contract on behalf of Husky Oil China Ltd for the installation of two 79-kilometer long pipelines and umbilicals as well as the construction of a subsea production system for the development of Liwan 3-1 field in water depths of 1,500 meters in the South China Sea. Engineering & Construction Onshore In the Engineering & Construction Onshore construction business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the oil&gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through its technology excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of Middle-East, Caspian Sea, Northern and Western Africa and Russia. The principal orders awarded in 2011 in Engineering & Construction Onshore were: (i) the realization of 39 kilometers high-speed/high-capacity railway along the Treviglio-Brescia railway in northern Italy on behalf of Rete Ferroviaria SpA; (ii) the EPC contract for the construction of a Secondary Upgrader with a capacity of 43 KBBL/d of Hydrotreated gas oil. The infrastructure will be part of the Horizon Oil Sands Project – Hydrotreater Phase 2 – in Alberta, in the Athabasca Region, Canada; and (iii) the EPC contract for the realization of a gas pipeline, 42 inches in diameter and 435-kilometer long, which will connect the gas fields in the Bowen and Surat Basins to the Gladstone State Development Area (GSDA), near the city of Gladstone, in the western Australian coast on behalf of Gladstone Operations Pty Ltd. Offshore drilling Saipem is the only engineering and construction contractor that provides also offshore and onshore drilling services to oil companies. In the offshore drilling segment Saipem mainly operates in West Africa, North Sea, Mediterranean Sea and Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum depth of 9,200 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-the-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In particular, in the next years Saipem intends to complete the building of: the Scarabeo 8 and 9, new generation semi-submersible platforms, that have been already rented to Eni through multi-year contracts. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment). 82 Saipem’s offshore drilling fleet consists of 15 vessels fully equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. Its major vessels are: the Saipem 12000 and Saipem 10000, designed to explore and develop hydrocarbon reservoir operating in excess of 3,600 and 3,000 meter water depth, respectively in full dynamic positioning. In 2010, those vessels operated in West Africa and Far East. Other relevant vessels are Scarabeo 5 and 7, third and fourth generation semi-submersible rigs able to operate at depths of 1,900 and 1,500 meters of water, respectively. Average utilization of drilling vessels in 2011 stood at 100% (100% in 2010). The most significant order awarded in 2011 in Offshore drilling were: (i) a 24-month extension contract, from August 2012, for the lease of the drilling vessel Saipem 10000 on behalf of Eni; (ii) a 24-month extension contract, from August 2015, for the lease of the drilling vessel Saipem 12000 on behalf of Total E&P Angola; and (iii) a 36-month extension contract for the lease of the jack-up Perro Negro 7 on behalf of Saudi Aramco. Onshore drilling Saipem operates in this area as a main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this area Saipem can leverage its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments. Average utilization of rigs in 2011 stood at 96,1% (94% in 2010). The 91 rigs owned by Saipem at year end were located as follows: 28 in Venezuela, 21 in Peru, 10 in Saudi Arabia, 8 in Colombia, 7 in Algeria, 5 in Kazakhstan, 3 in Brazil, 3 Bolivia, 2 in Congo, 2 in Ecuador, 1 in Italy and 1 in Ukraine, and Saipem also used rigs owned by third parties (6 in Peru and 4 in Kazakhstan) as well as rigs owned by the joint company Saipar. The most significant order awarded in 2011 in Onshore drilling were: (i) a contract on behalf on Saudi Aramco in Saudi Arabia for the lease of nine rigs with a contract duration from one to three years; (ii) contracts on behalf of various clients in Peru, Colombia and Bolivia for the lease of fourteen rigs with a contract duration from 4 to 12 months; and (iii) 2 contracts on behalf of Ural Oil and Samek for the lease of 2 rigs with a contract duration of 4 and 12 months, respectively. Capital Expenditures See “Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment”. Petrochemicals Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and Western Europe. Eni’s strategy in its petrochemical business is to effectively and efficiently manage operations in order to lower the break-even considering the volatility of costs of oil-based feedstock, cyclicality in demand, strong competitive pressures from operators with lower cost structure especially in the Middle-East leveraging on stranded gases, taking into account the commoditized nature of many of Eni’s products. In fact, Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See “Item 3 – Risk Factors”. In 2011, the Petrochemicals segment reported sharply lower operating losses from 2010 mainly due to worsening European economic environment, declining demand and falling product margins. Management expects a weak macroeconomic outlook for 2012 which will weigh on a rebound in demand for petrochemicals products and the risks associated with volatile crude oil prices. In particular, rising oil prices could put pressure on unit margins of commodities. In light of this, management is planning to implement a strategy intended to refocusing the petrochemical business, strengthening the product mix of the Company by developing higher value added products, particularly in the businesses of elastomers, styrenics, resins, EVA and entering into bio-based chemical production. In the next years products demand in those higher value-added segments is planned to grow and 83 margins to be resilient also with higher feedstock prices. Management expects sales of higher value added products to improve by 50% within 2015, with a contribution on total sales amounting to 40%. The Company will also leverage on international expansion especially in Asia and Latin America through licensing activities, product alliances and joint ventures. Results of our extra-European activities are expected to grow substantially by 2015. The Company’s strategy will also continue to leverage on efficiency actions to reduce operating costs and the rationalization program of our plants in order to improve yields and efficiency, restructuring our unprofitable site, in particular cutting the Company’s ethylene and polyethylene capacity. All these actions will allow improving our operating profit by 2015. To target those objectives, management plans to make capital expenditures amounting to approximately (cid:1)1.7 billion over the next four years. The main investment regards the conversion of the Porto Torres unit in Sardinia, Italy, into an innovative bio-based chemical complex to produce bio-plastics and other bio-based chemical products for which significant growth is expected in the medium-long term. In addition, the Company plans to develop the product line in the elastomers and monomers businesses revamp the efficiency of the Company’s cracking units as well as complying with all applicable regulations on environment, health and safety issues. In 2011 sales of petrochemical products (4,040 ktonnes) decreased by 691 ktonnes (or -14.6%) from 2010 mainly due to a substantial decrease in demand reflecting the current economic downturn. Petrochemical production (6,245 ktonnes) decreased by 975 ktonnes from 2010, or 13.5%, Main decreases were registered in basic petrochemical and polyethylene while elastomer production achieved a slight increase (up 1.1%). The above mentioned demand decrease required unexpected outages in all the plants, in Italy and abroad. In Italy, relevant production decreases were registered at the Porto Torres plant (down 46.4%), as a result of the shutdown of the plant in connection with the start in the second quarter of 2011 of the above mentioned bio-based project related to the conversion of the site. Outside Italy, main decreases were registered at the Dunkerque site due to the slow restart after the expected shutdown and Feluy due to the closure of the polystyrene plant at the end of 2010. Average unit sales prices increased by 20% from 2010 due to the positive impact of the oil price scenario (virgin naphtha prices increased by 31% from 2010). Also polymer prices registered a relevant increase, in particular elastomers (up 34%). Notwithstanding the above mentioned increase in sales prices, unit margins reported a steep decline due to higher supply costs of oil-based feedstock which were not recovered in sales prices. The table below sets forth Eni’s main petrochemical products availability for the periods indicated. Year ended December 31, 2009 2010 2011 (ktonnes) Basic petrochemicals ............................................................................................................. Polymers ................................................................................................................................. 4,350 2,171 4,860 2,360 4,101 2,144 Total production .................................................................................................................. 6,521 7,220 6,245 Consumption of monomers .................................................................................................. Purchases and change in inventories .................................................................................... (2,701) 445 4,265 (2,912) 423 4,731 (2,631) 426 4,040 The table below sets forth Eni’s main petrochemical products revenues for the periods indicated. Basic petrochemicals ............................................................................................................. Polymers ................................................................................................................................. Other revenues........................................................................................................................ 1,832 2,185 186 2,833 3,126 182 2,987 3,299 205 Total revenues....................................................................................................................... 4,203 6,141 6,491 Year ended December 31, 2009 2010 2011 ((cid:1) million) 84 Basic petrochemicals Basic petrochemicals revenues ((cid:1)2,987 million) increased by (cid:1)154 million from 2010 (up 5.4%) in all main business segments due to the steep increase in average unit prices (olefins/aromatics up 20%, intermediates up 16%) as a result of an improved scenario, partly offset by lower volumes sold (18% on average). In particular, a decline was reported in sales volumes of olefins (ethylene down 22%; butadiene down 57% due to the lack of raw material) and intermediates (down 21% on average, in particular phenol and acetone). Basic petrochemical production (4,101 ktonnes) decreased by 759 ktonnes from last year (down 15.6%), due to lower sales/demand of monomers. Lower ethylene production reflected facility downtimes in the Porto Marghera and Porto Torres plants. In addition intermediates sales decreased (down 14%) due to unavailability of raw material and planned facility downtimes in the Mantova plant. Polymers Polymer revenues ((cid:1)3,299 million) increased by (cid:1)173 million from 2010 (up 5.5%) due to increases in average unit prices (elastomers up 34%, styrene polymers up 12%; polyethylene up 11%). Sales volumes decreased on average by 11.5% (main decreases were registered in polyethylene, down 16%, lattices down 15%, polibutadiene and thermoplastic rubbers down approximately 9%) due to a steep decline in demand. Sales of ABS and SBR rubbers showed an opposite trend, up 5% and 2%, respectively. Polymer production (2,144 ktonnes) decreased by 216 ktonnes from 2010 (down 9%), mainly polyethylene (down 15%) due to the delay in the restart of the Dunkerque production lines, planned facility downtimes in the Priolo, Ragusa and Gela in the last part of the year as well as a decline in demand. Capital Expenditures See “Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment”. Corporate and Other activities These activities include the following businesses: • • the “Other activities” segment comprises results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years; and the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Adfin SpA, Eni International BV and Eni Insurance Ltd, Eni carries out lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an inter-company basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations. Seasonality Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year-to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years that are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa. 85 Research and Development Technological research and development (“R&D”) and continuous innovation represent key success factors in implementing Eni’s business strategies as they support our long-term competitive performance. The Company believes that the oil industry has to face a number of challenges in the near future and that technology will play a vital role in helping it to effectively manage them. In particular: • • • • continuing uncertainty about the future evolution of prices and demand for oil and gas; limited access to new hydrocarbon resources, with the consequent problems for production growth and reserve replacement; a growing importance of renewable sources in satisfying energy need, as well as the role of unconventional resources; and greater attention to operations safety in the aftermath of recent accidents in the industry. • • • • • Against this backdrop, management has identified key technology priorities: • continued technological innovation to increase the recovery factor; to develop drilling technologies to be applied in complex environments and deep/ultra-deep offshore areas; to maximize asset value, especially for gas and marginal fields and by reducing time-to-market; implementation of new technologies to minimize the environmental footprint of Eni’s operations, actively manage risks to employees and communities’ health and safety; develop technologies to reduce greenhouse gas emissions in industrial operations with particular reference to energy efficiency, gas flaring reduction and CO2 use; focusing on innovative fuels and bio-fuels enhancing performance and environmental quality to anticipate stricter regulation; commitment to develop a potentially breakthrough technologies in the renewable energy (solar and bio-mass). The relevant results achieved in certain research projects, enable us to start up the application phase; strengthening of strategic alliances and scientific cooperation projects with international academic institutions and research centers which we believe are qualified in the marketplace. As part of this, in 2008 we signed a research alliance with the Massachusetts Institute of Technology (MIT), Boston (U.S.), focused on innovative technology in the field of solar energy and in the oil and gas business. The overall expenditure for academic institutions and research centers amounted to (cid:1)30 million in 2011. In 2011, Eni signed a new agreement with Stanford University which will develop a research program focused on oil&gas technologies and environmental issues for an overall expenditure of $10 million over the next four years. Other agreements were signed with the Milan and Turin Polytechnic universities and with the Italian National Research Center (CNR). In 2011, Eni filed 79 patent applications (88 in 2010), 37 of these coming from Eni Divisions and Eni Corporate, 13 from Petrochemicals and 28 from the Engineering & Construction activities of Saipem. In particular, 51% of Eni Divisions and Eni Corporate patents concerned exploration activities of unconventional resources, maximizing the recovery factor, transportation and products/processes in the downstream oil segment and 41% were innovation on renewable energy sources. The efficacy and efficiency of intellectual property management and of know-how dissemination are monitored within the R&D performance assessment system. In 2011, the review of Eni’s portfolio was performed following two key aspects: maximizing innovative solutions created by the R&D projects underway and streamlining of the existing portfolio in line with Eni’s business strategy. In the year the ratio patents filing/expiring was 1.22 (1.14 in 2010, 0.81 in 2009). In 2011, Eni’s overall expenditure in R&D amounted to (cid:1)191 million which were almost entirely expensed as incurred ((cid:1)221 million in 2010 and (cid:1)207 million in 2009). At December 31, 2011, a total of 925 persons were employed in research and development activities. Below, we describe the main results achieved in the development and application of innovative technologies in 2011. Exploration & Production - Seismic depth migration. Eni has developed a set of proprietary technologies for more accurate image reconstruction of highly complex subsurface structures, e.g., subsalt environments, deep reservoirs below carbonates, and fractured reservoirs. Eni Depth Velocity Analysis (e-dva™) and Eni-Kirkhhoff True Amplitude Depth Migration (e-kta™) have been successfully applied in 2011 in Australia (Kitan), Angola (Lira discovery), Mozambique (Mambo discovery), and Ghana (Sankofa and Gyename discoveries). Eni-Depth Velocity Analysis (e-dva™) together with proprietary Reverse Time Migration (RTM) processing, has been successfully applied to several exploration projects in 2011, among which Australia, where it allowed the identification of new oil bearing structures not visible with conventional tools. 86 - Eni Common Reflection Surface Stack (e-crs™). This is a proprietary seismic processing technology that enhances the signal/noise ratio in challenging imaging areas. In 2011 its application in Pakistan and India contributed to positive exploration results. - Eni Deep water dual casing running (e-dwdc™). This proprietary technology for simultaneously drilling and then installing the conductor pipe and the first casing has been applied to drill wells in Angola (Cinguvu-2 and Cabaça South East-3 appraisal wells) and Mozambique (Mamba South 1 and Mamba North 1 discovery wells). Its use reduced the drilling time for this phase, while assuring maximum hole verticality and operational safety. - Eni Circulation device (e-cd™). Proprietary technology has been used to drill wells in Alaska, Angola, China, Egypt, Ghana, and Italy. Eni Circulation Device technology provides enhanced hydraulic control and has demonstrated excellent capacity also for well bore cleaning, opening new application perspectives. - e-sight, thin layer reservoirs. Proprietary while-drilling and log interpretation technologies (e-sight™) recently industrialized provide an industry-leading capability to identify, quantify and develop thin layer reservoirs, which are by-passed with conventional approaches. This has led to the identification of important additional resources in Italy and internationally, and increased production in 2011. Gas & Power - Eni Kassandra meteo forecast. Since 2009 Eni has been developing a new climate weather forecast system in collaboration with the Italian Weather Operations Centre (MOPI) to gain know-how regarding the temperature trend on a regional and seasonal scale. Eni developed “Eni Kassandra meteo forecast”, a proprietary system for forecasting temperatures from meteorological and climate data. The system has been validated in 2011 at the European level and is going to be used in the management and sale of energy resources obtaining competitive advantages in both gas and power businesses. - Pipeline monitoring. With the aim of guaranteeing excellent quality standards and efficient transport services, as part of its activity of pipeline monitoring, Eni developed theoretical models of acoustic-elastic transmission in pipes used for gas and oil transport as well as algorithms for remote localization of impacts and fluid leaks along the pipe. The prototypal system of this monitoring technology will be applied on transport and production pipes in Eni plants in Italia, Tunisia and Nigeria. In addition, studies were also completed on new acoustic sensors with Wi-Fi remote control for sunken pipes at gas stations that cannot be checked with PIG (Pipeline Inspection Gauges), and radar technologies for remote monitoring of vibrations and pipe displacement. - Transport at Intermediate Pressure (TPI). In 2011 Eni completed the TPI project dedicated to validate natural gas transport technologies by means of onshore high pressure pipes in high grade structural steel. For the same volumes of gas transported with traditional solutions, the introduction of this technology allows to reduce the overall costs for long distance transportation. Refining & Marketing - Eni Slurry Technology (EST). The EST proprietary technology is an innovative process for hydro-conversion by means of a nanodispersed catalyst (slurry) and a peculiar process scheme to refine various kinds of heavy feedstock: residues from the distillation of heavy and extra-heavy crude (such as the ones from the Orinoco Belt in Venezuela) or non-conventional products such as tar sands, characterized by high contents of sulphur, nitrogen, metals, asphaltenes and other pollutants that are hard to manage in conventional refineries. EST does not produce by-products and completely converts feedstocks into distillates. In May 2011, at the Sannazzaro de’ Burgondi refinery preliminary activities have started for the construction of the plant employing for the first time on an industrial scale EST. - Total Conversion. Successful results have been obtained from the continuous operation of the Slurry Dual Catalyst pilot plant: this technology, based on the combination of two nanocatalysts could lead to a relevant breakthrough in the EST process, increasing its productivity and improving product quality. - Short Contact Time-Catalytic Partial Oxidation (SCT-CPO). It is a reforming technology that can convert gaseous and liquid hydrocarbons (also derived from bio-mass) into synthetic gas (carbon monoxide and hydrogen). This technology can contribute to process intensification as it allows to produce synthetic gas and hydrogen using reactors up to 100 times smaller than those currently in use, with relevant savings. The development of this technology, that makes 87 use of oxygen enriched air, has been completed and another version making use of pure oxygen is under development. In 2011 at the Sannazzaro refinery the Short Contact Time-Catalytic Partial Oxidation project is underway. - Zero Waste project. For the treatment of industrial, oily and biological waste generated by the oil industry a thermal process has been studied that allows for the gasification of sludge that is turned into an inert residue. A patent application has been filed on this project. In the third quarter of 2011 Eni started up a pilot plant for pyrolisis/gasification and inertization of industrial sludge (Zero Waste project) with capacity of 50 kg/h at the site of Centre for new materials development of in Rome. Petrochemicals - Basic petrochemicals. In the intermediates business a new technology was introduced at a pilot scale aimed at eliminating the coproduction of acetone (an unwanted co-product) in the production of cumene from benzene. - Elastomers. In 2011, in the elastomer business technological innovation were industrially homologated through the use of two new grades of E-SBR rubbers for Tire green application (low emissions) allowing to obtain an higher performance product. New nitrilyc rubbers utilizable in the production of gloves, flexible pipes and washers, were industrialized with a more efficient and non volatile anti oxidant, that allows to eliminate emissions in finishing operations. - Polymers. In the styrene business new additive was successfully tested that allows to improve the environmental footprint in the production of EPS (Expanded Polystyrene in continuous mass) reducing by 30% the formation of bromide by-products. Engineering & Construction - Offshore. R&D activity was finalized at continuous improvement of innovative solutions for offshore fields: in particular, among the main innovations in 2011 were: (i) the project for a system for the transport of liquefied natural gas between two units of offshore Floating LNG; (ii) methodologies and innovative structures for the laying of offshore pipelines aiming at reducing their impact on the environment and on habitat restoration; and (iii) in the field of renewable energies, activities connected to the realization of a prototype of a submarine turbine moved by sea currents in 2012. - Onshore. R&D activities for the year related mainly process technologies in the upstream and mid-downstream segments aimed in particular at: (i) increasing the productivity of the proprietary technology for the production of fertilizers (Snamprogetti™ Urea); (ii) reducing the environmental impact of urea producing plants based on the recovery of ammonia; and (iii) transport of CO2 in the field of Enhanced Oil Recovery technologies for the development of onshore fields. Eni Corporate - Photoactive materials. A Luminescent Solar Concentrator consists of a slab of transparent material (polymeric or glassy) doped with fluorescent molecules, patented by Eni, which works as microscopic light emitters. The emitted radiation is partially concentrated within the slab by total internal reflections and is waveguided toward its edges where PV cells are placed. LSCs allow for a substantial decrease in standard PV module costs by reducing the effective cell surface with respect to the absorbing surface. The positive results obtained at lab level allow the commencement of a demonstration phase. - Micro-organisms for bio-diesel. Purpose of the project is the use of micro-organisms (yeasts and bacteria) that accumulate lipids similar to those deriving from oil-bearing vegetables, that can easily be turned into bio-diesel. The raw material employed by these micro-organisms derives from the treatment of wood-cellulose bio-mass in order to not compete with food products. The identified yeasts have higher productivity than the traditional oil crops, including palm oil. In 2011, planned activities started-up at a pilot plant with a 200 liter capacity. The full completion is expected to be tested in 2012. - Photoproduction of hydrogen. This project has breakthrough content for water splitting into O2 and H2. New materials was synthesized for innovative photoelectrodes and demonstration cells was constructed. The new materials 88 (e.g. titanium oxide, tungsten, and iron), based on original processes that use nanotechnology, have lead to interesting efficiency levels in the conversion of solar energy into chemical energy, up to the best levels reached on a world basis. In 2011, a demonstration device for H2 production has been built and tested in open air. Results derived from the Eni-MIT alliance Oil spills in marine environment. The project derives from the discovery of an innovative material with great selective capacity for the absorption of oil dispersed in water. This could be a first step towards new systems for treating oil spills in marine environments. Ultraflexible solar cell. One of the most important results obtained by the Solar Frontier Center: these cells made of a thin photoactive material covered by a layer of transparent plastic can be bent without breaking or reducing performance and this allows to cover irregular surfaces without using metal stilts. Solar cells on paper. In this case the photoactive device is made on paper as a printed document. The innovative technique is the same used for producing cells on plastic and flexible substrata. A paper cell can be a low cost solution for application where the key aspect is not duration but fast installation and easy transport. Insurance In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance Ltd, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market. Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (“OIL”) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni makes recourse to insurance companies who we believe are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.1 billion for offshore events and $1.5 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1 billion for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segment and FPSOs used by the Exploration & Production segment for developing offshore fields; $500 million for time charters. Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which could have a material impact on our results and liquidity. See “Item 3 – Risk Factors – Risk associated with the exploration & production of oil and natural gas”. Environmental Matters Environmental Regulation Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, products and other activities, including legislation that implements 89 international conventions or protocols. In particular, 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, limit or prohibit drilling activities on certain protected areas, provide for measures to be taken to protect the safety of the workplace and health of communities affected by the Company’s activities, and impose criminal or civil liabilities for pollution resulting from oil, natural gas, refining and petrochemical operations. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. We believe that the Company will continue incurring significant amounts of expenses to comply with pending regulations in the matter of environmental, health an safety protection and safeguard, particularly to achieve any mandatory or voluntarily reduction in the emission of greenhouse gases in the atmosphere and cope with climate change. A brief description of major environmental laws impacting Eni’s activities located in Italy and Europe is outlined below. Italy On August 16, 2011, Legislative Decree No. 121/2011 “Implementation of Directive No. 2008/99/EC on the criminal protection of the environment, and Directive No. 2009/123/EC – amending Directive No. 2005/35/EC – on pollution caused by ships and the introduction of penalties for violations” came into force. This decree introduced into Italian law the liability of legal entities in relation to the crimes committed by employees against the environment. Particularly, the Italian legislator broadened the scope of corporations’ liabilities for the crimes committed by employees to include crimes relating the illicit discharge of industrial waste water, violations in reporting, record keeping and other omitted evidence in the matter of waste, unauthorized waste management, illegal trafficking of waste, as well as crimes relating the application in Italy of the Convention on International Trade in animal and plant species threatened with extinction, violations of measures intended to protect the stratospheric ozone and the environment and pollution caused by ships. On October 5, 2011, Legislative Decree No. 162/2011 implementing Directive No. 2009/31/EC (CCS Directive) came into force. The decree represents a key point to launch and support, from an institutional point of view, the implementation of demonstrative projects which are finalized to investigate and analyze from a scientific point of view, the technological aspects of the CCS, in order to optimize current technologies or to find new solutions with a marginal and sustainable economic impact for the capture and storage processes. On April 29, 2006, Legislative Decree No. 152/2006 “Environment Regulation” came into force. This as amended and updated by four following decrees was designed to rationalize and coordinate the whole regulation of environmental matters by setting: • • • • • procedures for Strategic Environment Assessment (SEA), Environmental Impact Assessment (EIA) and Integrated Pollution Prevention and Pollution Control (IPPC); procedures to preserve soil, prevent desertification, effectively manage water resources and protect water from pollution; procedures to effectively manage waste and remediate contaminated sites; air protection and reduction of atmospheric pollution; and environmental liability. The most important changes introduced by the Decree regarded reclamation and remediation activities as this Decree provided a site-specific risk-based approach to determine objectives of reclamation and remediation projects, cost-effective analysis required to evaluate remediation solutions, and criteria for waste classification. On January 4, 2011, Decree No. 219/2010 entered in force implementing the Directive 2008/105/EC on environmental quality standards in the field of water policy (modifies Part III of the Decree No. 152/2006). Moreover, on February 22, 2011 a new monitoring criteria and classification of water bodies (in line with Water Framework Directive) introduced by Ministerial Decree No. 260/2010 entered in force. Ministerial Decree substitutes integrally Annex I of the II Part of the Environmental Code (Decree 152/2006). 90 Decree No. 4/2008 introduced important changes regarding SEA and EIA procedures, landfill, waste and remediation. The most important aspects of these regulations to Eni are those regulating permits for industrial activities, waste management, and remediation of polluted sites, water protection and environmental liability. Decree No. 128/2010 introduced IPPC regulations and additional restricting emission limits for certain critical pollutants, in compliance with the IED directive. In relation to the accident that occurred in the Gulf of Mexico, the Decree also introduced permit restrictions regarding offshore activities, in line with the European Parliament Resolution of October 7, 2010 on EU action on oil exploration and extraction in Europe. Eni has rescheduled certain offshore activities in the Mediterranean Sea and the North European Sea to take account of such developments. Decree No. 205/2010 implemented the Directive No. 2008/98/EC about waste and adopted SISTRI (an automated tracking system of special and hazardous waste). The new system aims at real time monitoring of the route of waste from production through disposal/recycling, also prosecuting any unlawful act. The new regulatory system is expected to be fully implemented by June 2012. The system has already introduced some significant changes in Eni’s organization and internal procedures. Decree No. 155/2010 adopted in the Italian law the European prescriptions on ambient air quality, established by the Directive No. 2008/50/EC. Its main innovation is the definition of monitoring criteria and emission limits for fine particulate substances (PM 2.5), to be achieved by January 1, 2015. Eni is executing a number of site characterizations and inquiries to comply with the above mentioned regulations. The objective of this activity is to detect the pollution levels and presence of contaminants in the sites where the Company is conducting or has conducted in the past its industrial activities. With particular reference to certain industrial sites which were divested or restructured in past years, the Company has established environmental provisions to take account of the expected future costs to clean-up and remediate the industrial areas. In 2010, the Company proposed a global environmental transaction to the Italian Ministry for the Environment in order to define the clean-up projects and measures of environmental remediation relating nine industrial sites of national interest where the Company owned or held in concession certain industrial areas. The Company took a charge of (cid:1)1,109 million in 2010 operating profit. On February 19, 2011, Legislative Decree of December 30, 2010, No. 257, entered in force, implementing Directive No. 2008/101/EC of the European Parliament and of the Council, which includes aviation activities in the scheme for greenhouse gas emission allowance trading within the Community. Legislative Decree No. 81/2008 concerned the protection of health and safety in the work place and was designed to regulate the work environments, equipments and individual protection devices, physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees. The complexity and scale of situations and contexts where Eni is operating requires the adoption of business processes, guidelines and principles for improving its performance in health and prevention. To this end Eni upholds: • • • • • clear policies; an ethical code; endorsement of international conventions and principles; guidelines and procedures; and sharing of knowledge. On November 23, 2011, the legislation regulating works in confined spaces has come into effect (Decree No. 177/2011), in application of Legislative Decree No. 81/2008. In 2011, the Decree No. 151/2011 has also come into effect rationalizing the previous legislation on fire prevention and protection. European Union On June 1, 2007, REACH regulation of the European Union (EC No. 1907/2006 December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemical and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed by chemicals, while enhancing the competitiveness of the EU chemicals industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to ECHA how the substance can be 91 safely used, and they must communicate the risk management measures to the users. If the risks cannot be managed, authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of REACH registration depends on the tonnage band of a substance and the classification of a substance; next deadlines are 2013 and 2018. The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation (EC) No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals it introduced is based on the United Nations’ Globally Harmonized System (GHS). The Regulation will replace two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. There is a transition period until 2015. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them. The European Commission has put forward its new Energy Policy for Europe - EPE, so-called “20-20 by 2020”, a far-reaching package of proposals that will deliver on the European Union’s ambitious commitments to fight climate change, promote renewable energy and increase energy security. The following regulations were published in order to define the criteria for cutting emissions cost-effectively by 2020 compared with levels recorded in 2005: • Directive No. 2009/28/EC: fixing target of 20% share of energy from renewable sources in 2020. It creates cooperation mechanisms so that the EU can achieve the targets in a cost effective way. It also includes a flat 10% target for renewables in transport (bio-fuels, “green” electricity, etc.); this legislation also sets out sustainability criteria that bio-fuels should meet to ensure they deliver real environmental benefits. • Directive No. 2009/29/EC: improves and extends to the third phase (2013-2020) the greenhouse gas emission allowance trading scheme of the European Community to provide for a more efficient, homogeneous and fair system. It defines criteria and targets for cutting GHG emissions from the sectors covered by the system (energy and manufacturing industries) by 21% by 2020 compared with levels in 2005. The Auctioning Regulation contains a set of rules for the auctioning processes that should be undertaken for the auction of allowances from 2013. On December 14, 2010, Climate Change Committee voted the benchmark decision, which describes the rules for the free allocation from 2013. • Directive No. 2009/30/EC: defines the fuel quality and places an obligation on suppliers to reduce greenhouse gases from the entire fuel life cycle of 6% by 2020, mostly by an increased use of bio-fuels. • Decision 2011/278/EU: implements transitional Union-wide rules for harmonized free allocation of emission allowances pursuant to Article 10a of Directive No. 2003/87/EC: legislation that set the benchmark for the quantification of the free allowances allocated to the industry. For industry and heating sectors, allowances will be allocated for free based on ambitious (greenhouse gas performance-based) benchmarks. Installations that meet the benchmarks (and thus are among the most efficient installations in the EU) will in principle receive all allowances they need. • Directive No. 2009/31/EC: defines a scenario in order to promote the development and safe use of Carbon Capture & Storage (CCS), a suite of technologies that allows the carbon dioxide emitted by industrial processes to be captured and stored underground. Regulation 443/2009/EC: sets emissions standards for new passenger cars and targets a reduction to an average of 120 g CO2/km by 2015, decreasing to a stringent long-term target of 95 g CO2/km by 2020. • • Decision 406/2009/EC: defines, for sectors not included in the EU ETS, such as transport, housing, agriculture and waste, emissions reduction target of 10% from 2005 levels by 2020 (the Italian reduction target is fixed at 13%). • Decision 540/2011/EC: amending Decision 2007/589/EC as regards the inclusion of monitoring and reporting guidelines for greenhouse gas emissions from new activities and gases. Directive No. 2008/1/EC contains the new IPPC and rationalizes all existing regulations on this issue. Member States of the EU have to communicate their national values of emissions into the atmosphere, wastes produced and managed and discharges of compounds into waste that are to be included in the European Pollutant Release and Transfer Register (E-PRTR). According to the E-PRTR, Eni installations shall report data on the Italian Register website, by the end of March of each year. In 2010, Eni completed the implementation of an Integrated Environmental Information System, able to gather, manage and report the data on all the pollutants released and off-site transferred as requested by PRTR Regulations. On November 24, 2011 the Commission Regulation (EU) No. 1210/2011 of November 23, 2011 amending Regulation (EU) No. 1031/2010 in particular to determine the volume of greenhouse gas emission allowances to be auctioned prior to 2013 was published in the Official Journal of the European Union No. 308. On December 14, 2011 the Commission Decision of December 7, 2011 concerning a guide on EU corporate registration, third country and global registration under Regulation (EC) No. 1221/2009 of the European Parliament and of the Council on the voluntary participation by organizations in a Community eco-management and audit scheme 92 (EMAS) was published in the Official Journal of the European Union No. 330. The Decision provides guidelines and additional information on EMAS registration for those organizations with multiple sites located in one or more Member States or third (non-EU) countries. On December 17, 2010, the Directive No. 2010/75/EC on industrial emissions (IED) was published in the Official Journal of the European Union No. 334. The objective of the new directive is to avoid or to minimize polluting emissions in the atmosphere, water and soil, as well as waste from industrial and agricultural installations, and to achieve a high level of environmental and health protection. The Directive brings together the IPPC Directive (Directive No. 2008/1/EC) and six other sector-specific Directives (Large Combustion Plants, VOC – Volatile Organic Compounds – emissions, incineration of waste and titanium industry). The Directive contains special provisions for the combustion plants with thermal input below 50 MW. Any industrial installation which carries out the activities listed in Annex I must meet certain obligations, as preventive measures taken against pollution, minimum emission values, apply the best available techniques (BAT), monitoring rules and permit and reporting conditions. The Article 14 of the new Directive defines the permit necessary measures (as emission limit values for polluting substances, rules guaranteeing protecting of soil, water and air, suitable emission monitoring measures, waste monitoring and management measures, communication of monitoring results to the competent national authorities, requirements concerning the maintenance and surveillance of soil and groundwater, measures relating to exceptional circumstances as leaks, malfunctions, momentary or definitive stoppages, etc.). The Directive defines more restricting emission limits to be observed by the end of 2012, although includes some derogation, as the TNP Transitional National Plan and the option Opt-Out for those installations that are going to shut down their operations by 2023. On February 28, 2011, the European IPPC Bureau started the review process of the Reference Documents on Best Available Techniques for Large Combustion Plants “BREF-LCP” and reactivated the Technical Working Group (TWG); the new documents will be published in 2012. Moreover, in 2011 the European Commission worked on the rules concerning the transitional national plans (PNT), as stabilized in the Article 41 of IED Directive. The Member States should transpose the IED Directive into national legislation by December 2012. On November 22, 2008 the new Directive on waste (Directive No. 2008/98/EC) was published in the Official Journal of the European Union. The new Directive simplifies the existing legislative framework by clarifying definitions, streamlining provisions and integrating the Directives on hazardous waste (No. 1991/689/EC) and on waste oils (No. 1975/439/EC). The Directive introduces a life-cycle approach, focuses on waste policy by improving the way of resources consumption. The scope is to improve the recycling market by setting environmental standards, specifying under which conditions certain recycled waste are no longer considered such. The Directive requires that Member States take appropriate measures to encourage the prevention or reduction of waste production and its harmfulness. This can be done by a combination of several strategies particularly through the development of clean technologies, the technical development and marketing of products designed so to contribute as little as possible to increasing the amount of waste. The Directive also sets new recycling targets. The core of the Directive is the introduction of a waste management hierarchy. This hierarchy is as follows: 1. Waste prevention, 2. Re-use, 3. Recycling, 4. Recovery (including energy recovery), 5. Disposal. Moreover the Directive bolsters the importance of the extended producer responsibility in the future waste management measures. With the aim of taking the lead in the negotiations on the Climate Agreement after 2012, on March 15, 2011 the European Commission presented a Roadmap for transforming the European Union into the worldwide forerunner of low carbon economy by 2050. The Roadmap objective is cutting greenhouse gas emissions by 80-95% vs. 1990 levels within 2050, by implementing cost effective measures aiming mostly at improving energy efficiency. The analysis takes into consideration costs and savings related to potential measures such as sector policies, national and regional low- carbon strategies and long-term investments. On December 15, 2011 the European Commission adopted the Communication “Energy Roadmap 2050”. This Communication takes into account “decarbonization scenarios”: • • • • • energy efficiency scenario; diversified supply technologies scenario; high renewable energy scenario; delayed carbon capture and storage (CCS) scenario (a ‘high nuclear’ pathway); and low nuclear scenario (a ‘high CCS’ pathway). Following the incident at the Macondo well in the Gulf of Mexico the U.S. Government and other governments have adopted or are likely to adopt more stringent regulations targeting safety and reliable oil and gas operations in the United States and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. Eni’s operations in the Gulf of Mexico did not experience any material delays or interruptions following a stricter regime of permit assignment from U.S. Authorities. Italian Authorities too have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons, that are still in place. Also the European institutions have increased their activities in the area of environmental protection in the field of hydrocarbon extraction. 93 Following a resolution of the European Parliament of one year earlier rejecting a moratorium on new oil platforms and requiring a single European system for prevention and response to intra-community oil spills, on October 27, 2011 the European Parliament proposed a new law which will ensure that European offshore oil and gas production will respect the world’s highest safety, health and environmental standards everywhere in the EU. The new draft regulation sets clear rules that cover the whole lifecycle of all exploration and production activities from design to the final removal of an oil or gas installation. It introduces requirements for effective prevention and response of a major accidents through the licensing, verification of the technical solutions by the independent third party (prior the license and periodically after the installation starts operating), obligatory ex ante emergency planning (Major Hazard Report), inspections, transparency (information available to citizens and competent authorities), emergency response plans, liability (environmental liability is extended up to about 370 km from the coast – covers EU marine waters including the exclusive economic zone), EU Offshore Authorities Group. Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices could trigger cost increases to comply with new HSE standards which the Company might adopt either on a mandatory or voluntary basis. Also our exploration and development plans to produce hydrocarbons reserves and drilling programs could be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil and gas industry will likely trend higher in future years. In order to achieve the highest safety standards of our operations in the Gulf of Mexico, we entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. HSE Activity for the Year 2011 Eni is committed to continuously improve its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations. In 2011, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 294 (266 in 2010), of which 103 certifications according to the ISO 14001 standard, 9 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 73 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements). In 2011, Eni total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to (cid:1)1,622 million, up 13% from 2010. Environment. In 2011, Eni incurred total expenditures amounting to (cid:1)1,007 million for the protection of the environment, as in 2010. Current environmental expenses increased by approximately 5% from 2010, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure decreased by 6% and mainly related to plant upgrading to increase energy efficiency, reduce carbon emissions and clean-up industrial discharge water. Eni expects to continue incurring amount of environmental expenditures and expenses in line with or above 2011 levels in future years. Safety. We are committed to safeguard the safety of our employees and contractors as well as of all people living in the areas where our activities are conducted and our assets located. In 2011, the new legislation didn’t have significant impact on the procedures already in place for safety in the workplace. The improvement and dissemination of safety awareness through all levels of the Company’s organization continued in 2011; this is one of the foundations of Eni’s safety strategy, through a large communication campaign with the target of improving the conduct of employees/workers in the specific field of safety in the workplace. The campaign will be completed this year and will involve 35,000 employees and 25,000 contractor workers. From the end of 2009 and throughout 2010, a number of safety seminars involving the top and middle management of various business units have taken place, with the aim of sharing the experiences coming from the implementation of process safety audits in the downstream sector and asset integrity verification tools in the upstream sector. The process safety knowledge improvement effort has continued in 2011 with courses targeted at specific areas like functional safety and alarms management. Results of efforts to achieve a better safety in all activities has brought an improvement of Eni lost time injury frequency to 0.73 and of the severity rate to 0.026, both decreasing from 2010 (down 18% and 10%, respectively) and representing the best results ever. 94 Costs incurred in 2011 to support the safety levels of operations and to comply with applicable rules and regulations were (cid:1)349 million, up 23% from 2010. Eni expects to continue incurring amounts of expenses for safety which will be in line with or above 2011 levels in future years. Health. Eni’s activities for protecting health aim at the continuous improvement of work conditions. Results have been achieved through: • • • • • • • efficiency and reliability of plants; promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment; certification programs of management systems for production sites and operating units; identified indicators in order to monitor exposure to chemical and physical agents; strong engagement in health protection for workers operating outside Italy, identifying international health centers capable of guaranteeing a prompt and adequate response to any emergency; identification of an effective organization of health centers, in Italy and abroad; and training programs for medics and paramedics. To protect the health and safety of its employees, Eni relies on a network of more than 300 health care centers located in its main operating areas. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies. Eni is engaged to the elaboration of Health Impact Assessment (HIA) and relative standards to be applied to all new projects of evaluation of working exposure in foreign environment. HIA is usually carried out as part of or in conjunction with the Environmental and a Social Impact Assessment process. The results are used to develop appropriate mitigation measures and an improvement plan with the host community. The principal aim of Health Impact Assessment is to avoid any negative impacts and maximize any positive impacts of the project on the host community. In 2011, Eni incurred a total expense of (cid:1)81 million, up 41% from 2010, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health which will be in line with or above 2011 levels in future years. Managing GHG emissions and Implementation of the Kyoto Protocol On February 16, 2005, the Kyoto Protocol entered into force along with commitments provided by Annex I to the Protocol which was ratified by the same parties who joined the Protocol, including the EU and Italy. According to Law No. 120/2002, Italy committed itself to reduce greenhouse gas (GHG) emissions by 6.5% in the period 2008-2012, as compared to GHG levels emitted in 1990. Reductions can be achieved through both internal measures and complementary initiatives. The latter include the so-called flexible mechanisms, which enables a Party to carry out projects in developing countries (CDM - Clean Development Mechanism) and in industrial countries with transition economies (JI - Joint Implementation) in order to obtain emission credits to fulfill the Kyoto compliance. Italy is a party to the EU Emission Trading Scheme (“ETS”) that was established by Directive No. 2003/87/EC. Effective from January 1, 2005, ETS is the largest virtual market in the world for exchanging emission allowances targeting industrial installations with high carbon dioxide emissions. As foreseen by the Directive, Italy has issued two National Allocation Plans (NAP) covering the periods 2005- 2007 and 2008-2012 which set out the allowances awarded to each sector and installation. The ETS EU Directive provides that each member state shall ensure that any operator, who produces GHG emissions in excess of the amounts entitled on the base of national allocation plan, is required to provide allowances to cover excess emissions and to pay a penalty. The excess emissions penalty amounts to (cid:1)100 ((cid:1)40 for the first period 2005-2007) for each tonne of carbon dioxide equivalent produced in excess of entitled amounts. All companies are expected to identify and carry out projects for emission reductions. Eni participates in the ETS scheme with 55 plants in Italy and 4 outside Italy, which collectively represent more than 40% of all greenhouse gas emissions generated by Eni’s plants worldwide. In the period 2005-2007 Eni was entitled to allowances equal to 77.2 mmtonnes of carbon dioxide for existing and new installations. In the period 2008- 2012 Eni was entitled to allowances equal to 126.4 mmtonnes of carbon dioxide for existing installations and further 2.0 mmtonnes in relation to new installations for the 2008-2012 period. Based on the implementation of projects designed to reduce emissions, particularly the start-up of high efficiency combined cycles for the cogeneration of electricity and steam, the amount of carbon dioxide emitted by Eni’s plants has complied with mandatory limits in each of the reported periods up to 2011. 95 Moreover, Eni monitors the opportunities deriving the Kyoto Flexible Mechanisms. In fact, due to its presence in about 70 Countries, Eni is an elective partner for carrying out CDM and JI projects thus contributing to the Italian program of greenhouse gas emissions reduction. In December 2003, during the Conference of Parties to the Kyoto Protocol - COP9, Eni and the Ministry for the Environment signed a Voluntary Agreement for using flexible mechanisms, promoting CDM and JI and contributing to the sustainable development of host countries. Management believes that the best solution for complying with the Kyoto Protocol makes recourse to low emission energy sources and adoption of highly efficient technologies. To address the greenhouse gas challenge, Eni performed a detailed analysis for defining its strategy to respond to climate change and to participate in the European emissions trading system, identifying a number of projects for energy saving and emission reductions from its plants. In addition, management is targeting to reduce GHG emissions by implementing certain gas projects designed to exploit associated gas in foreign countries where such gas is flared due to lack of infrastructures or market opportunities. The elimination of flaring and the use of associated gas for the development of local economies enable sustainable development while reducing greenhouse gas emissions. More projects are being assessed or implemented in order to economically exploit gas associated with the production of liquids or reduce flaring gas. The Company plans to invest approximately (cid:1)4.1 billion over the next four years in Algeria, Libya, Angola, Congo, Iraq, Italy, Nigeria, Norway and Turkmenistan to execute projects intended to monetize the reserves of associated gas and cut volumes of flared gas. Particularly in the period 2012-2015, Eni plans to cut by 80% the volumes of gas flaring compared to 2007 levels. In order to achieve a reduction in the trend of GHG emissions, management plans to implement measures targeting energy efficiency at various Eni’s installations and facilities including refineries, petrochemicals plants and electricity plants, and actions to better manage gas emissions in transport and distribution activities. However, due to stricter rules of current rules granting emission allowances for no consideration, management believes that Eni’s GHG emissions under the ETS scheme will exceed the entitled allowances in the next four-year period resulting in the incurrence of higher operating expenses to acquire emission allowances on the marketplace estimated at (cid:1)0.7 billion in the four-year period. Most of those projected expenses are expected to be incurred in the years 2013-2015, which correspond to the third Phase of Emission Trading. To ensure comprehensive, transparent and accurate reporting for GHG emissions, Eni introduced in 2005 its own Protocol for accounting and reporting greenhouse gas emissions (GHG Accounting and Reporting Protocol), which is an essential requirement for emission certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the assessment of progress. The Eni GHG Protocol has been updated during 2009 to be in compliance with the European and Italian regulation (as the new Monitoring and Reporting Guideline) and with the best practices reference document (American Petroleum Industry Compendium - August 2009). For safer and more accurate management of GHG emissions and with a view to supporting effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs. In the medium-term, work is underway on the separation of carbon dioxide and its permanent storage in geologic reservoirs, a part of the CO2 Capture Project, an international R&D program carried out in conjunction with other oil companies. Eni is currently implementing Italy’s first CO2 injection project in Cortemaggiore. In both the medium and long-term, management believes that compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Eni’s commitment to the transition to a lower-carbon economy may create expectations for our activities and related liabilities, and the level of participation in alternative energies carries reputational, economic and technology risks. Regulation of Eni’s Businesses Overview The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. 96 Regulation of Exploration and Production Activities Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil and gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See “Regulation of the Italian Hydrocarbons Industry” and “Environmental Matters” for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. In Product Sharing Agreements (PSA), entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (Profit Oil). A similar scheme to PSA applies to Service and “Buy-Back” contracts. In general, Eni is required to pay income tax on income generated from production activities (whether under a license or production sharing agreement). The taxes imposed upon oil and gas production profits and activities may be substantially higher than those imposed on other businesses. Regulation of the Italian Hydrocarbons Industry The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Exploration & Production The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”). Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are the property of the State. Exploration activities require an exploration permit, while production activities require a production concession, in each case granted by the Ministry of Productive Activities through competitive auctions. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three year extensions, 25% of the area under exploration must be relinquished to the State. The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the field depletes. Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Law No. 99 of July 23, 2009 royalties are equal to 10% and 4%, respectively, for onshore and offshore production of oil and 10% and 7%, respectively, for onshore and offshore production of natural gas. 97 Gas & Power Natural gas market in Italy Legislative Decree No. 130 August 13, 2010 containing measures for increasing competition in the natural gas market and transferring the ensuing benefits to final customers according to Article 30, lines 6 and 7, of Law July 23, 2009, No. 99 In 2011, Legislative Decree No. 130 of August 13, 2010 titled “New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers” (Legislative Decree No. 130/2010) became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni has committed itself to build (by its subsidiary Stogit) new storage capacity for 4 BCM within five years from the enactment of the decree; as a consequence the cap provided by the Legislative Decree No. 130/2010 to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni will be obliged to execute gas release measures at regulated prices up to 4 BCM over a two-year period following the ascertainment of the breach. Access to the new storage capacity is reserved to industrial customers and their consortium (3 BCM, already allocated) and to gas fired power plants (1 BCM).Furthermore, the decree establishes that upon request, industrial customers are granted, for the new storage capacity which is not yet at their disposal: • • up to March 2012, a financial anticipation of the benefit they will have once disposing of the new storage capacity (i.e. the gap between summer and winter gas prices minus the cost of storage services); and starting from April 2012 a “virtual storage service”, which consists of the possibility to deliver gas in summer to a “virtual storage operator at a European hub – TTF, Zeebrugge or PSV – and to be re-delivered equivalent gas quantities in winter at the Italian PSV, paying for the service a fee equivalent to the cost of storage plus transmission costs, if any. The Italian Gestore of Servizi Energetici has elected certain virtual storage operators to be the providers of those services. Industrial investors will then benefit from the price differentials due to the seasonal swings of gas demand. Eni, in compliance with Legislative Decree No. 130/2010 provisions, participated to the tender procedure for the selection of “virtual storage operators” for 50% of the requested quantities, bidding a price fixed by the Italian Regulator (AEEG). Eni’s management is monitoring this issue with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that this new gas regulation will increase competition in the wholesale natural gas market in Italy leading to further margin pressures. Law No. 239 of August 23, 2004 on the restructuring of the energy sector in Italy The main aspects of this law are described below. • It established a derogation to the general rule of third party access to infrastructures by granting a waiver to companies that make direct or indirect investments for the construction of new infrastructure or the upgrading of existing ones such as: (i) interconnections between EU Member States and national networks; (ii) interconnections between non-EU States and national networks for importing natural gas to Italy; (iii) LNG terminals in Italy; and (iv) underground storage facilities in Italy. Investing companies can obtain priority on the assignment of the new capacity resulting from new investment up to 80% of the new capacity installed for a period of at least 20 years. It established that all concessions for natural gas distribution activities in urban areas existing at June 21, 2000 awarded through competitive bids are set to expire on December 31, 2012. In 2011, a specific Decree issued by the Italian Government established 177 territorial basins representing the lowest levels of aggregation of municipalities. The new concessions will be granted based on these new territorial basins for a maximum term of 12 years. When an existing concession expires, the new operator who takes over the concession will award the previous operator a compensation for the distribution network based on an industrial assessment of the asset value. • Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy Law Decree No. 1 enacted by the Italian Government on January 24, 2012 (the so called “Decree on Liberalizations”) is expected to have major impacts on the Italian gas sector, including an obligation on part of Eni to divest its interest in Snam SpA (see below). Other areas of interest to Eni are certain proposed measures to: • • enhance competitiveness in gas tariffs to residential customers and in the distribution of refined products; and reduce the cost of natural gas for industrial customers by giving them direct access to storage capacity. This will be possible with a redefinition of the binding modulation for residential customers in case of rigid winter conditions and by freeing up a percentage of strategic storage volumes. Further details are provided in the following paragraphs. 98 Mandatory disposal of Eni’s interest in Snam The mandatory disposal of Eni’s interest in Snam SpA was originally provided by Italian Law No. 290/2003 which prohibits vertically-integrated companies operating in the natural gas and power industries to retain an interest in excess of 20% in the share capital of companies owning and managing national networks for the transmission of natural gas and power. The term by which interested companies would have to comply with this provision, was initially fixed as of December 31, 2008 and was then rescheduled to a 24-month period deadline following enactment of a specific decree by the Italian Prime Minister which would establish terms and conditions of the divestments. On June 1, 2011, the Italian Council of Ministers approved a Legislative Decree intended to enact European Directive No. 2009/72EC, No. 2009/73/EC, and No. 2008/92/EC (the so-called Third Energy Package) into Italian legislation. The Decree established the adoption of functional unbundling, in order to realize the so-called Independent Transmission Operator (ITO) model for Snam Rete Gas which is the main Italian gas transport operator. On the basis of this Legislative Decree, Eni could retain control of Snam Rete Gas by ensuring the decisional and functional independence of its subsidiary. As of December 31, 2011, Eni complied with the regime of functional unbundling for Snam Rete Gas as set by Decision 11/2007 and updated by Resolution No. 253/2007 of the Authority for Electricity and Gas. With the intent to build an organizational model meeting these legal provisions, on December 5, 2011 with effect from January 1, 2012, “Snam Rete Gas SpA” changed its official denomination in “Snam SpA”, a new company holding a 100% interest in the four companies operating the transport, re-gasification, storage and distribution of natural gas. This name change was followed by the transfer of the “transportation, dispatching and metering of natural gas” business unit to a new company that continuously from January 1, 2012, took the name of Snam Rete Gas SpA. On January 24, 2012, the above mentioned prescriptions have been partially superseded by the enactment of Law Decree No. 1 by the Italian government which has opened up a procedure calling for the mandatory divestment of Eni’s interest in Snam. This Decree, which has been converted into law on March 24, 2012 provides that the President of the Council of Ministers pass a specific decree setting criteria, terms and conditions of the divestment of Eni’s interest in Snam by May 2012. The deadline to comply with this provision is due 18 months after the promulgation of the Law converting the above mentioned decree of the Council of Ministers. The Decree must also define if Eni is to retain an interest in Snam and its maximum amount. In 2011, consolidated financial statements, Snam accounted for approximately 13% of the Group’s total assets, 2% of the Group’s total revenues, 12% of the Group’s operating profits and 40% of the Group consolidated net borrowings. Negotiation Platform for gas trading In compliance with the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry for Economic Development published a Decree that implements a trading platform for natural gas starting from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform are entrusted to an independent operator, the GME (Gestore dei Mercati Energetici). On this platform are traded also volumes of gas corresponding to the legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. Under these provisions, importers were expected to supply given amounts of gas (from 5% to 10% of total gas import) to the virtual exchange in order to receive permission to import, as well as volumes corresponding to royalties due by owners of mineral rights to the Italian state (and to Basilicata and Calabria Regions). Eni was required to offer at that platform about 200 mmCM related to the residual obligation for volumes imported in thermal year October 1, 2008-September 30, 2009, and to the offer obligation for the October 1, 2009-September 30, 2010 thermal year, as well as approximately 215 mmCM related to royalties due for 2009 full year. Operators, also non-importers, are allowed to negotiate additional gas volumes over the compulsory amounts on the platform according to the supply rules determined by the AEEG. Since December 2010, the GME is also trader’s counterparty in transactions on the spot market for natural gas (divided into day-ahead market and intraday market). We believe that these measures have increased the level of liquidity in the Italian spot market of gas. Natural gas prices Following the liberalization of the natural gas sector introduced in 2000 by Decree No. 164, prices of natural gas sold to industrial and power generation customers as well as to wholesalers are freely negotiated. However the AEEG holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the AEEG) and Legislative Decree No. 164/2000. Furthermore, the AEEG has been entrusted by the Presidential Decree dated October 31, 2002 with the power of regulating natural gas prices to residential and commercial customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which engage in selling 99 natural gas through local networks are currently required to offer to those customers the regulated tariffs set by AEEG beside their own price proposals. Clients who are currently eligible to the safeguard regime set by the Authority are those residential clients who did not opt for choosing a supplier at the opening of the market in 2003 (including those who consume less than 200,000 CM/y and residential buildings). The above mentioned Legislative Decree No. 130/2010 enlarged this category by including all customers consuming less than 50,000 CM/y and certain public services (for example hospitals and other assistance facilities). The pricing mechanism established by the AEEG basically indexes the cost of gas to a preset basket of hydrocarbons for the purpose of tariff setting to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. In its latest intervention on this issue, the Authority for Electricity and Gas with Resolution ARG/gas No. 89/2010 amended the current mechanism by introducing for thermal year October 1, 2010-September 30, 2011, a fixed reduction of 7.5% of the raw material cost component in the final price of supplies to residential users. In addition with Resolution ARG/gas No. 77/2011, the AEEG provided for the thermal year October 1, 2011-September 30, 2012 a reduction of 6.5% of the raw material cost component. These resolutions will negatively affect Eni’s results of operations and cash flows in 2012 and have penalized Eni’s results in 2011, considering the negative impact on unit margins in sales to residential customers. The Company believes that it is possible that in the near future the AEEG could enact new measures impacting the indexation mechanism of the cost of gas in supplies to that kind of customers. Particularly the above mentioned 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 segments; AEEG, in fact, has just proposed in a specific public consultation (DCO No. 68/2012/R/gas) introduction of a percentage linked to the European hub prices (in particular for 2012, 5% since second quarter, 6% since third quarter). The same decree on liberalizations provides a measure intended to reduce the supply cost of gas to businesses by enabling them to directly access certain new storage capacity. This new capacity would be available as a result of new mechanisms for determining the volumes of strategic storage and storage capacity that operators engaged in natural gas marketing are obliged to set aside to cover demand peaks from households and residential clients during wintertime. This additional flexibility would make available an integrated set of services from transport to storage to businesses in compliance with the public criteria of supply security. Regulation of gas sale tariff in Europe In France, starting from June 1, 2011, tariffs have been blocked by a new ministerial measure that cancelled tariff increases for the year for residential customers and allowed a lower increase than the one resulting from the application of the indexation formula for professional customers. In December 2011, the French Government passed a new indexation formula to be applied to tariff updates from January 1, 2012 that significantly increases (from 9.5% to 26%) the share related to spot prices. Similar measures concerning a block on tariffs paid by retail customers have been approved in Hungary. Fully-Regulated Businesses in the Italian Gas Market Transport Transport tariffs. The AEEG set transport criteria companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transport networks, for each regulatory period made up of four years, as provided for by Decree No. 164/2000. Tariffs are subject to approval by the Authority, which ensures their compliance with preset criteria. Criteria established by the AEEG set allowed revenues that are calculated as the sum of: (i) operating costs including storage and modulation costs; (ii) amortization and depreciation of transport assets; and (iii) return on net capital employed. With Resolution ARG/gas No. 184/2009, published on December 2, 2009, the Authority set the criteria regulating the tariffs for natural gas transport on the national and regional gas pipeline network for the third regulatory period (January 1, 2010-December 31, 2013). The Regulated Asset Base (RAB) is calculated with the re-valuated historical cost methodology. 100 The allowed pre-tax rate of return (WACC) on the Regulatory Asset Base (RAB) has been set equal to 6.4% in real terms. The new tariff structure confirms recognition in tariff of expenditures incurred for network upgrading, providing for a higher remuneration than WACC, in a measure ranging from one to three percentage points of additional remuneration in relation to the nature of expenditures and for a period of 5 to 15 years. Depreciation charges of gas transport infrastructures (gas pipelines) are determined on a 50-year useful technical life and are excluded from the price cap mechanism. Operating costs are defined with reference to operating costs incurred during 2008 and increased by a 50% rate to factor in productivity gains achieved in the second regulatory period. Fuel gas is excluded from the price cap mechanism and treated as a pass-through cost which is payable in kind by users. The revenue component related to volumes transported is determined on the basis of operating costs recognized in tariff and amounts to approximately 15% of revenue cap. Network Code. From 2003, Snam Rete Gas Network Code is in force, regulating entitlements of transport capacity, obligations on part of both the transporter and the customer and the procedures through which customers can resell capacity to other users. Transport capacity at entry points to the national gas pipeline network (point of interconnection with import gas lines) is entitled on an annual basis with duration of up to five thermal years. Capacity products with duration shorter than one year are also available. The Network Code, approved by the AEEG with Resolution No. 75 of July 1, 2003, is based on the criteria set by the same Regulator with Resolution No. 137/2002. This resolution 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 purchase contracts, as in such as Eni, are entitled to a priority in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes are not entitled to any priority and, case of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity entitlements. The ability of Eni to collect gas volumes exceeding average daily volumes as provided by its take-or-pay purchase contracts represents an important operational flexibility that the Company uses to satisfy demand peaks. In planning its commercial flows, the Company normally assumes to fully utilize its contractual flexibility and to obtain the necessary capacity entitlements at the entry points to the national transport network. Eni believes that Resolution No. 137/2002 is in contrast with the rationale of the European regulatory framework on the gas market as provided in Directive No. 2003/55/EC. Based on that belief, the Company has opened an administrative procedure to repeal it before an administrative court which has recently confirmed in part Eni’s position. An upper grade court also confirmed the Company’s position. Specifically, the Administrative Court stated that the purchase of contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Administrative Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in the access to the network, also 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. Balancing service. On April 14, 2011, with Resolution ARG/gas No. 45/2011 effective from December 1, 2011, the Authority for Electricity and Gas introduced economic criteria for balancing services. Being the major Italian transportation company, Snam Rete Gas is qualified as the “Responsible for balancing services” in Italy and is required to ensure a constant balance of the national network providing necessary resources for the safe and efficient management of movements of gas from entry to exit points. In a first application phase, the resolution provides for a simplified balancing mechanism in which Snam Rete Gas will be required to daily ensure the national grid equilibrium covering potential imbalances through purchases of storage capacity at market prices as determined on the negotiation platform organized and managed by the GME. From April 2012, further changes in the relevant regulatory framework for balancing services are expected to be set by the Regulator. Re-gasification Re-gasification tariffs. The AEEG has set the criteria regulating the tariffs for the use of LNG terminals in the 3rd regulatory period (October 2008-September 2012) with its Resolution ARG/gas No. 92/2008. The Regulatory Asset Base (RAB) is calculated with the re-valuated historical cost methodology. The yearly adjustment of revenues and tariffs will follow the same methodologies applied in the previous regulatory period, except for depreciation that will be adjusted on a yearly basis and excluded from the price cap mechanism. The allowed rate of return (WACC) on Regulatory Asset Base has been set equal to 7.6% in real terms pre-tax. 101 Furthermore, it established an additional remuneration, up to 3% above WACC, for new capital expenditures for a maximum of 16 years. Operating costs will be adjusted every year taking into account inflation and efficiency gains (X-factor) set by the Authority at 0.5% in real terms. Resolution ARG/gas No. 92/2008 also established that the allocation of reference revenues between re-gasification capacity and the commodity component is fixed at 90:10 (compared to 80:20 ratio in the second regulated period). Re-gasification Code. From 2007 GNL Italia Re-gasification Code is in force, defining rules and regulations for the operation and management of the re-gasification plant of Panigaglia in North-West Italy. The Code, approved with the Resolution VIS No. 8/2009, is based on the criteria for access to LNG re-gasification services set by the same Regulator with Resolution No. 167/2005 (August 1, 2005) in accordance with Legislative Decree No. 164/2000. The decision also defines criteria for the allocation of re-gasification capacity. In particular it establishes that take-or- pay contracts entered into before 1998, as in the case of Eni, are awarded priority access limited to the minimum amount of volumes that have been re-gasified in the period starting from thermal year 2001-2002. Eni filed a claim against this decision with the Regional Administrative Court of Lombardy that rejected the claim. Subsequently, Eni filed a claim with a higher degree administrative court. Distribution Distribution is the activity of delivering natural gas to residential and commercial customers in urban centers through low pressure networks. Distribution is considered a public service operated in concession and is regulated on the basis of Law Decree No. 164/2000. Distribution tariffs. With Resolution ARG/gas No. 159/2008, the AEEG defined a new methodology for determining revenues for natural gas distribution activity. Starting from January 1, 2009 and for the duration of a four- year regulated period, i.e. until December 31, 2012, the resolution provides for the recognition of total revenues for each regulated year amounting to a value that the Authority will set at the time of approving the operators’ requests for distribution tariffs and defined as Total Revenue Constraint (TRC), representing the maximum remuneration recognized by the AEEG to each operator for covering costs borne. In previous years, revenues were determined by applying tariffs set by the AEEG to volumes actually distributed to selling companies in the relevant year. The resolution also provides for any positive or negative difference between TRC and revenues resulting from invoices for actually distributed volumes to be regulated through an equalization device making use of credit/debit cards lodged with the Electricity Equalization Exchange. As a result of the new mechanism, revenues are no longer related to the seasonality of volumes distributed but are constantly apportioned during the year. The introduction of this new mechanism does not cause a decline in total revenues on a yearly basis. Storage of natural gas Storage activities in Italy are regulated by Decree No. 164/2000, as amended by Legislative Decree No. 93/2011. The most important aspects of Decree No. 164 concerning storage activities are the following: (i) in vertically integrated enterprises, storage is to be carried out by a separate company not operating in other gas activities (such as Eni’s subsidiary Stoccaggi Gas Italia SpA) or by companies engaged only in transport and dispatching activities, provided the accounts of these two activities are clearly separated from the accounts of storage; (ii) storage activity is exercised pursuant to concessions granted by the Ministry of Productive Activities. The duration of a concession is 20 years, with the possibility of obtaining two ten-year extensions if operators complied with the storage programs and other obligations deriving from applicable laws. Existing storage concessions are subject to the decree. Their original term was confirmed and includes relevant production concessions; (iii) the need for strategic storage in Italy is defined explicitly; the burden of strategic storage is imposed upon companies that perform gas production activities and companies that perform gas importation activities from EU or non-EU countries, which have to provide a strategic storage capacity in Italy corresponding to an amount defined yearly by Decree of Ministry of Economic Development according to the natural gas imported and supply infrastructure; (iv) holders of storage concessions are required to provide storage capacity for domestic production, for strategic use and for modulation to eligible users without discriminations, where technically and economically viable; (v) modulation storage costs are charged to shippers which have to provide modulation services adequate to the requirements of their final customers; (vi) storage tariffs criteria are determined by the AEEG in order to ensure a preset return on capital employed, taking into account the typical risk inherent in this activity, as well as volumes stored for ensuring peak supplies and the need to incentive capital 102 expenditure for upgrading the storage system; and (vii) the AEEG establishes the criteria and priority of access storage operators have to include in their own storage codes. In compliance with the provisions of Article 21 of Decree No. 164/2000, on October 21, 2001 all storage activities carried out within the Eni Group were conferred to Stoccaggi Gas Italia SpA (“Stogit”), which holds ten storage concessions. Storage tariffs. On August 3, 2010, the AEEG with Resolution ARG/gas No. 119/2010 published the criteria for determining storage tariffs for the 2011-2014 regulated period. According to this resolution, the storage company calculates revenues for the determination of unit tariffs for storage services by adding the following cost elements: (i) a return on the capital employed by the storage company equal to 6.7% real pre-tax (7.1% in the second regulated period); (ii) depreciation and amortization charges; (iii) dismantling costs; and (iv) operating costs. In the years following the first year of the new regulated period, reference revenues are updated to take account of variations of capital employed and the impact of the indexation of depreciation charges and operating costs to consumer price inflation lowered by a preset rate of productivity recovery set at 0.6% (2% on operating costs and 1.5% on amortization and depreciation in the previous regulatory period). Applicable regulation provides for incentives to capital expenditures intended to develop and upgrade storage capacity by recognizing an additional rate of return of 4% on the basic rate to capital expenditure projects aiming at developing new storage deposits and increasing existing capacity. Such incentives are applicable for a sixteen-year period and an eight-year period, respectively. Storage Code. From November 1, 2006 Stoccaggi Gas Italia (Stogit) Storage Code is in force. This Code regulates access to and provision of storage services during normal operational conditions, regulates procedures for conferring storage capacities, fees to be charged to customers in case they uplift from or input to storage sites volumes in excess or uses higher input/uplift capacity with respect to scheduled and operating programs. On the basis of these provisions, Eni may incur significant charges for storage services should the Company fail to use storage services in accordance with scheduled operating programs. The storage company offers services according to the access priority established by the AEEG as follows: (i) mandatory services, including modulation storage, mineral storage, and strategic storage services; and (ii) services for operating needs of transport companies, including hourly modulation. The modulation storage service is geared towards satisfying modulation needs of natural gas users in terms of peak consumption and daily or seasonal trends in consumption. The shippers who provides final clients consuming less than 200,000 CM on an annual basis are entitled to a priority when satisfying their modulation requirements. To that end, the storage company makes available its capacity for space, injection and off-take on an annual basis in accordance with its storage code. The mineral storage service aims to allow natural gas producers to perform their activity under optimal operating conditions, according to criteria determined by the Ministry for Economic Development. The strategic storage service aims to satisfy certain obligations of natural gas importers in accordance with Article 3 of Legislative Decree No. 164/2000, as amended by Legislative Decree No. 93/2011. The relevant storage capacity dedicated to this service is determined by the Ministry for Economic Development. The first requests to be met are those for strategic storage and for the operating balancing of the system. The residual capacity available and the maximum daily uplift capacity is awarded according to the following order of priority to: (i) holders of production concessions requesting mineral storage services; (ii) natural gas selling operators who are held to provide a modulation service of their supply to their customers according to Article 18, paragraphs 2 and 3 of Legislative Decree No. 164/2000, for maximum volumes corresponding to a seasonal demand peak with average temperatures, on the terms and conditions established by a procedure to be issued by the Regulatory Authority for Electricity and Gas; (iii) to the entities mentioned in (ii) above only for those additional maximum volumes related to a seasonal demand peak in case of certain low temperatures measured on a 20-year period, under the terms and conditions of the procedure mentioned in (ii) above; and (iv) the entities requesting access for services different from the ones mentioned above. 103 From November 2009, according to the Resolution No. 165/2009 set by the Regulator, monthly based storage services are available for gas-network users (Shippers). Storage capacities are sold on auction basis. From April 2011, according to the Legislative Decree No. 130/2010 and to the Resolution ARG/gas No. 13/2011, the storage capacity is offered also to the industrial and power generation clients which have committed to fund the development plan of storage capacity. The duration of these contracts are multi annual and the industrial and power generation clients can use the capacity gradually available. Eni held natural gas for strategic reserve purposes in its storage business, as established by Decree No. 164/2000. The strategic reserves of gas are defined as “stock destined to meet situations of deficit/decrease of supply or crisis of the gas system”. The Ministry for Economic Development determines quantities and usage criteria of such reserves. As of December 31, 2011, Eni held approximately 177 BCF of strategic reserves of natural gas (177 BCF at year end 2010). Refining and Marketing of Petroleum Products Refining. The regulations introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s that required that any refining activity be handled under a concession from the state. Today an authorization is required to set up new processing and storage plants and for any change in the capacity of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measure has been introduced by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic settlements” that need authorization from the State, in agreement with the relevant Region, and imposes a single process of authorization that must be closed within 180 days. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term. Marketing. Following the enactment of the above mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The norms regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012 principals will be allowed to supply freely up to 50% of their requirements. In such case the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels and to reduce opportunities of increasing Eni’s market share in Italy. Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products. With the same goal of renewing the Italian distribution network, Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network, and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012 all service stations must be provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. 104 Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations which might prejudice the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours. Management believes that those measures will favor competition in the Italian retail market and support efficient operators. Petroleum product prices. Petroleum product prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Productive Activities; such recommendations are considered by service station operators in establishing retail prices for petroleum products. Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 (“Decree 22/2001”) enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil company on a site-by-site basis. Law No. 96 of June 4, 2010 requires the government to follow some principles and criteria in drafting the Legislative Decree that shall implement, by December 31, 2012, Directive No. 2009/119/EC (imposing an obligation on Member States to maintain minimum stocks of crude oil and/or petroleum products), in particular: (a) keep a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks; and (b) provide for the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development – with the mandatory participation of entities who have imported oil or petroleum products – that should be in charge of: (i) the holding and transport of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually; and (iv) the provision of a storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products to final clients not vertically integrated in the oil chain. As of December 31, 2011, Eni owned 6.7 mmtonnes of oil products inventories, of which 4.1 mmtonnes as “compulsory stocks”, 2.2 mmtonnes related to operating inventories in refineries and depots (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.4 mmtonnes related to specialty products. Eni’s compulsory stocks (as of December 31, 2011) were held in term of crude oil (31%), light and medium distillates (49%), fuel oil (16%) and other products (4%) and they were located throughout the Italian territory both in refineries (76%) and in storage sites (24%). Competition Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (“EU Regulation 139”). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self assessment by the undertakings that such conducts does not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of Authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The competition authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions: • requiring that an infringement be brought to an end; 105 • • • ordering interim measures; accepting commitments; and imposing fines, periodic penalty payments or any other penalty provided for in their national law. National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority. In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers. Property, Plant and Equipment Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10 per cent or more of the Company’ worldwide proved oil and gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas. Organizational Structure Eni SpA is the parent company of the Eni Group. As of December 31, 2011, there were 264 fully consolidated subsidiaries and 72 associates that were accounted for under the equity or cost method. For a list of subsidiaries of the Company, see “Exhibit 8. List of Eni’s fully consolidated subsidiaries for year 2011”. Item 4A. UNRESOLVED STAFF COMMENTS None. 106 Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the IASB. This section contains forward-looking statements which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii. Executive Summary Eni reported net profit of (cid:1)6,860 million for the year ended December 31, 2011, representing an increase of 8.6% from 2010. That amount represented net profit attributable to Eni’s shareholders. The Group operating profit for the year ended December 31, 2011 amounted to (cid:1)17,435 million, up 8.2% from 2010. The main drivers of this increase were: (i) a positive operating performance reported by the Exploration & Production segment due to higher oil&gas realizations in dollar terms. The better performance was achieved in spite of the disruption in the production flows from Eni’s activities in Libya caused by the conflict in that country which materially impacted our activities from February through September 2011. The Company has achieved a production recovery in Libya in the last part of the year which is currently underway targeting to restore the pre-crisis production levels aiming at full ramp up by the second half of 2012; and (ii) higher results of the Engineering & Construction segment which were driven by revenue growth and increased profitability of acquired orders. In contrast, the downstream businesses incurred sharply lower results. The Marketing business of the Gas & Power segment was impacted by weak demand and rising competitive pressures fuelled by oversupply which negatively impacted selling margins and reduced volumes opportunities. The performance was also impacted by the disruption in the Libyan gas availability which affected both the supply mix and sales to shippers which import Libyan gas to Italy. Results of the Marketing business did not take into account the full economic benefits of the ongoing renegotiation of gas supply contracts as certain renegotiations were rescheduled thus postponing the recognition of the economic effect. A preliminary agreement on such renegotiations has been achieved early in 2012; management believes that the closing will take place shortly and expects to recognize the associated benefits in 2012 profit. Those benefits will be retroactive from the beginning of 2011. The downstream refining and petrochemical businesses reported deeper operating losses which were impacted by sharply lower margins and weak sales volumes due to the downturn. Operating profit benefited from the recognition of an inventory holding gain amounting to (cid:1)1,113 million ((cid:1)881 million in 2010), reflecting the impact of rising prices of crude oil and products on year-end valuation of inventories according to the average-cost method of inventory accounting. These gains were partly offset by impairment losses of (cid:1)1,021 million ((cid:1)698 million in 2010) which were recorded to write down the book values of certain tangible and intangible assets to their lower values-in-use mainly in the refining and gas marketing businesses. In performing the impairment review, management assumed a reduced profitability outlook in these businesses driven by a deteriorating macroeconomic environment, volatility of commodity prices, and rising competitive pressures. Other impairment losses regarded a number of oil&gas properties in the Exploration & Production segment reflecting a changed gas prices scenario and downward reserve revisions, as well as a marginal line of business in the Petrochemical segment due to lack of profitability perspectives. Group results for the year also benefited from a gain of (cid:1)1,044 million recorded on the divestment of Eni’s interests in the international pipelines engaged in the international transport of gas from Northern Europe and Russia. Net cash provided by operating activities amounted to (cid:1)14,382 million for the year ended December 31, 2011 and proceeds from divestments amounted to (cid:1)1,912 million, mainly relating to the divestment of the Company’s interests in the above mentioned entities engaged in the international transport of gas from Northern Europe and Russia. These inflows were used to partially fund the cash outflows relating to capital expenditures totaling (cid:1)13,438 million and dividend payments to Eni’s shareholders amounting to (cid:1)3,695 million. Dividends paid to non-controlling interests amounted to (cid:1)552 million, mainly relating to Saipem and Snam Rete Gas. As of December 31, 2011 net borrowings amounted to (cid:1)28,032 million, an increase of (cid:1)1,913 million from December 31, 2010. In 2011, oil and natural gas production available for sale averaged 1,523 KBOE/d compared to 1,757 KBOE/d in 2010 (down by 13.3%). Lower production was driven by a disruption in Eni’s activities in Libya, which were affected by the shut down of almost all the Company plants and facilities including the GreenStream pipeline throughout the peak of the country’s internal crisis (approximately 8 months). Performance was also negatively impacted by lower entitlements in the Company’s PSAs due to higher oil prices with an overall effect estimated at approximately 30 107 KBOE/d compared to the previous year. When excluding these negative effects, the production was unchanged. The ramp-up of the fields started in 2010 and the 2011 start-ups offset a lower-than-anticipated growth in Iraq and the impact of planned facility downtimes. Eni’s worldwide gas sales in 2011 amounted to 96.76 BCM, substantially unchanged from 2010 as lower volumes supplied to importers of natural gas in Italy (down 5.20 BCM or 61.6%) reflecting the disruption in the Libyan gas were offset by growth achieved in the Italian market (up 0.39 BCM, or 1.1%) and in a number of European markets (up by 3.66 BCM, or 7.9%). In 2011, capital expenditures amounted to (cid:1)13,438 million ((cid:1)13,870 million in 2010) and related mainly to: • oil and gas development activities ((cid:1)7,357 million) deployed mainly in Norway, Kazakhstan, Algeria, the Unites States, Congo and Egypt; exploratory projects ((cid:1)1,210 million) of which 97% was spent outside Italy, primarily in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway; upgrading of the fleet used in the Engineering & Construction segment ((cid:1)1,090 million); development and upgrading of Eni’s natural gas transport network in Italy ((cid:1)898 million) and distribution network ((cid:1)337 million), the development and the increase of storage capacity ((cid:1)294 million), as well as the ongoing development of power generation plants ((cid:1)87 million); and projects aimed at improving the conversion capacity and flexibility of refineries ((cid:1)629 million), as well as building and upgrading service stations in Italy and outside Italy ((cid:1)228 million). • • • • During the 2012-2015 four-year period, Eni expects to invest approximately (cid:1)59.6 billion in capital expenditures and exploration projects to implement its growth strategy, based on the assumptions discussed below under “Management’s Expectation of Operations”. Trading Environment Average price of Brent dated crude oil in U.S. dollars (1).................................................... Average price of Brent dated crude oil in euro (2)................................................................ Average EUR/USD exchange rate (3).................................................................................... Average European refining margin in U.S. dollars (4) ......................................................... NBP gas price in U.S. dollars (5) ........................................................................................... Euribor - three month euro rate % (3) .................................................................................... 61.51 44.16 1.393 3.13 4.78 1.2 79.47 111.27 79.94 59.89 1.392 1.327 2.06 2.66 9.03 6.56 1.4 0.8 2009 2010 2011 ________ (1) (2) (3) (4) (5) Price per barrel. Source: Platt’s Oilgram. Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB). Source: ECB. Price per barrel. FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data. Price per million BTU. Source: Platt’s Oilgram. When the term margin is used in the following discussion, it refers to 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 petrochemicals products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability. Eni’s results of operations and the year to year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. Conflicts and unrests in producing countries can also affect production significantly. See “Item 3 – Risk Factors”. In 2011, Eni’s results were helped by stronger oil and gas realizations (up by 30% on average) reflecting a 40% increase in the price of the Brent crude benchmark compared to 2010. Refining margins remained at unprofitable levels (the marker Brent margin was $2.06 per barrel; down 22.6% from 2010) due to high feedstock costs which were only partially transferred to prices at the pump pressured by weak demand and excess capacity. Eni’s margins were also negatively impacted by narrowing light-heavy crude differentials in the Mediterranean area dragging down the profitability of Eni’s high conversion refineries. In Europe, gas spot prices increased by 37.7% compared with the depressed levels registered in 2010. This positive trend was not reflected in Eni’s gas sale margins due to higher oil- linked supply costs and rising competitive pressure. 108 Group results were also negatively affected by the appreciation of the euro vs. the U.S. dollar (+4.9%). Key Consolidated Financial Data 2009 2010 2011 ((cid:1) million) Net sales from operations ..................................................................................................... 83,227 98,523 109,589 Operating profit ...................................................................................................................... 12,055 16,111 17,435 6,860 Net profit attributable to Eni ................................................................................................ Net cash provided by operating activities ............................................................................ 11,136 14,694 14,382 Capital expenditures .............................................................................................................. 13,695 13,870 13,438 Acquisitions of investments and businesses (1)..................................................................... 360 Shareholders’ equity including non-controlling interest at year end ................................. 50,051 55,728 60,393 Net borrowings at year end ................................................................................................... 23,055 26,119 28,032 Net profit attributable to Eni basic and diluted ............................................. ((cid:1) per share) 1.89 Dividend per share (2) ...................................................................................... ((cid:1) per share) 1.04 Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) (3)................................................................... 1.74 1.00 1.21 1.00 0.46 2,323 6,318 4,367 0.46 0.47 410 ________ (1) (2) (3) This item includes acquired net borrowings. As resolved by the Annual General Shareholders’ Meeting. The dividend is ordinarily paid in two tranches: an interim dividend is paid in a given reference year, the balance is paid in the next year following shareholders’ approval. For a discussion of the usefulness of and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see - “Liquidity and Capital Resources - Financial Conditions” below. Critical Accounting Estimates The company’s Consolidated Financial Statements are prepared in accordance with IFRS. 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 notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant 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 in 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. A summary of significant estimates follows. Oil and gas activities Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be designated as “proved”, the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves are classified as proved undeveloped. Volumes are subsequently reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural as 109 that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment. Impairment of assets Tangible assets and intangible assets, including goodwill, are impaired when there are events or changes in circumstances that indicate that the carrying values of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred costs – see also item “Current assets”) related to natural gas volumes not collected under long-term purchase contracts with take-or-pay clauses. The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. Oil, natural gas and petroleum product prices (and prices of products which are derived from there) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows. Goodwill and other intangible assets with an indefinite useful life are not subject to amortization. The Company tests for impairment such assets at the cash-generating unit level on an annual basis and whenever there is an indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed to that cash generating unit is impaired up to that difference; if the carrying amount of goodwill is less than the amount of impairment, assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference. Asset Retirement Obligations Obligations to remove tangible equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. Estimating future asset retirement obligations is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The subjectivity of these estimates is also increased by the accounting method used that requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically, at the time the asset is installed at the 110 production location). When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are increased with the passage of time (i.e. interest accretion) and any change in the estimates following the modification of future cash flows and discount rate adopted. The recognized asset retirement obligations are based on future retirement cost estimates and incorporate many assumptions such as: expected recoverable quantities of crude oil and natural gas, abandonment time, future inflation rates and the risk-free rate of interest adjusted for the Company’s credit costs. Business Combinations Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. Any positive residual difference is recognized as “Goodwill”. Negative residual differences are credited to the profit and loss account. Management uses all available information to make these fair value determinations and, for major business acquisitions, typically engages an independent appraisal firm to assist in the fair value determination of the acquired assets and liabilities. Environmental liabilities Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability has been incurred and the amount can be reasonably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by Decree No. 471/1999 of the Ministry for the Environment concerning the remediation of contaminated sites; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible insurance recoveries. Employee benefits Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds. The inflation rates reflect market conditions observed country by country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved; and (v) determination of the expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equity and cash and their specific average expected rate of return is taken into account. Differences between expected and actual costs and between the expected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. Eni applies the corridor method to amortize its actuarial losses and gains. This method amortizes on a pro-rata basis the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period that exceed the greater of 10% of: (i) the present value of the defined benefit obligation; and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan. Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions. The effects of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety. 111 Contingencies In addition to accruing the estimated costs for environmental liabilities, asset retirement obligation and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining the appropriate amount to accrue is a complex estimation process that includes subjective judgments of the management. Revenue recognition in the Engineering & Construction segment Revenue recognition in the Engineering & Construction segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to the geographical region where the activity is carried out, market conditions in that region and any assessment that is necessary to estimate with sufficient precision the total future costs as well as the expected timetable to the end of the contract. Additional income, derived from a change in the scope of work, is included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them. 2009-2011 Group Results of Operations Overview of the Profit and Loss Account for Three Years Ended December 31, 2009, 2010 and 2011 The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. Year ended December 31, 2009 2010 2011 ((cid:1) million) Net sales from operations ..................................................................................... Other income and revenues (1) .............................................................................. 83,227 1,118 98,523 956 109,589 933 Total revenues ....................................................................................................... Operating expenses ............................................................................................... Other operating (expense) income (2) ................................................................... Depreciation, depletion, amortization and impairments ..................................... 84,345 (62,532) 55 (9,813) 99,479 (73,920) 131 (9,579) 110,522 (83,940) 171 (9,318) OPERATING PROFIT ...................................................................................... Finance income (expense) .................................................................................... Income (expense) from investments .................................................................... PROFIT BEFORE INCOME TAXES ............................................................ Income taxes .......................................................................................................... NET PROFIT ....................................................................................................... Attributable to: - Eni ....................................................................................................................... - non-controlling interest ...................................................................................... 12,055 (551) 569 12,073 (6,756) 16,111 (727) 1,156 17,435 (1,129) 2,171 16,540 (9,157) 18,477 (10,674) 5,317 7,383 7,803 4,367 950 6,318 1,065 6,860 943 _______ (1) (2) Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income. The Company reports gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and settled transactions, as items of operating profit. 112 The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated. Operating expenses ............................................................................................... Depreciation, depletion, amortization and impairments ..................................... OPERATING PROFIT ....................................................................................... Year ended December 31, 2009 75.1 11.8 14.5 2010 (%) 75.0 9.7 16.4 2011 76.6 8.5 15.9 2011 compared to 2010. Net profit attributable to Eni’s shareholders in 2011 was (cid:1)6,860 million, an increase of (cid:1)542 million from 2010, or 8.6%. This increase was driven by: (i) an improved operating performance (up by 8.2% from 2010) which was mainly reported by the Exploration & Production segment (up by 14.6%), reflecting a favorable trading environment and by the Engineering & Construction segment due to strong business trends. These positive factors were partly offset by sharply lower results reported by the Gas & Power, the Petrochemicals and the Refining & Marketing segments due to a downturn in demand and unprofitable unit margins; (ii) recognition of higher inventory holding gains in particular in the Refining & Marketing segment; and (iii) higher profits reported from equity-accounted and cost-accounted entities, mainly reflecting the gains recorded on the divestment of international pipelines (approximately (cid:1)1,000 million). These increases were partly offset by higher income taxes (up (cid:1)1,517 million compared to 2010 full year) currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. The Company also recognized an adjustment to deferred taxation ((cid:1)573 million) due to a changed tax rate applicable to a production sharing agreement in the Exploration and Production segment; and incurred higher income taxes currently payable ((cid:1)221 million) following enactment of new tax provisions for Italian subsidiaries whereby the Italian windfall tax levied on energy companies (the so-called Robin Tax) was increased by 4 percentage points to 10.5% and its scope enlarged to include gas transport and distribution companies (for more details on these items see “Taxation” below). 2010 compared to 2009. Net profit attributable to Eni’s shareholders in 2010 was (cid:1)6,318 million, an increase of (cid:1)1,951 million from 2009, or 44.7%. This increase was driven by: (i) an improved operating performance (up by 33.6% from 2009) which was mainly reported by the Exploration & Production segment (up by 52%), reflecting a favorable trading environment. Improved operating results were also reported by the Engineering & Construction segment due to strong business trends, while the Petrochemicals and the Refining & Marketing segments achieved an improved performance in spite of difficult market conditions. Those gains were partly offset by sharply lower results recorded by the Gas & Power segment which was hit by a weak trading environment, and higher environmental charges up by approximately (cid:1)1.1 billion mainly due to the recognition of a provision to account for the proposed global environmental settlement with the Italian Ministry for the Environment as discussed in the paragraph “Significant Transactions”; (ii) recognition of higher inventory holding gains in particular in the Gas & Power segment. This increase is associated with rising gas prices which resulted in an increased carrying amount of gas inventories recorded under the weighted average cost method; and (iii) higher profits reported from equity-accounted and cost-accounted entities, including certain gains on divestments of assets (approximately (cid:1)300 million). These increases were partly offset by higher income taxes (up (cid:1)2,401 million compared to 2009) mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. 113 The table below sets forth, for the periods indicated, detail of gains and charges included in net profit attributable to Eni’s shareholders. Eni’s Group Profit (loss) on stock .............................................................................................. Expected settlement of TSKJ proceeding............................................................. Settlement/payments on Antitrust and other Authorities proceedings .............. Environmental charges .......................................................................................... Asset impairments.................................................................................................. Net gains on disposal of assets .............................................................................. Risk provisions....................................................................................................... Provision for redundancy incentives..................................................................... Re-measurement gains/losses on commodity derivatives .................................. Other ....................................................................................................................... Year ended December 31, 2009 2010 2011 345 (250) (298) (1,162) 277 (128) (134) 287 (4) ((cid:1) million) 881 1,113 246 (1,369) (702) 248 (95) (423) 2 19 (69) (186) (1,022) 61 (88) (209) (15) (124) (1,067) (1,193) (539) Analysis of the Line Items of the Profit and Loss Account a) Total Revenues Eni’s total revenues were (cid:1)110,522 million, (cid:1)99,479 million and (cid:1)84,345 million for the year ended December 31, 2011, 2010 and 2009, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to (cid:1)109,589 million, (cid:1)98,523 million and (cid:1)83,227 million for the year ended December 31, 2011, 2010 and 2009, respectively, and its other income and revenues totaled (cid:1)933 million, (cid:1)956 million and (cid:1)1,118 million, respectively, in these periods. Net sales from operations The table below sets forth, for the periods indicated, the net sales from operations generated by each of Eni’s business segments including intra-group sales, together with consolidated net sales from operations. Exploration & Production ..................................................................................... Gas & Power .......................................................................................................... Refining & Marketing ........................................................................................... Petrochemicals ...................................................................................................... Engineering & Construction ................................................................................. Other activities ...................................................................................................... Corporate and financial companies ...................................................................... Impact of unrealized intragroup profit elimination (1).......................................... Consolidation adjustment (2) .................................................................................. Year ended December 31, 2009 2010 2011 23,801 30,447 31,769 4,203 9,664 88 1,280 (66) (17,959) ((cid:1) million) 29,497 29,576 43,190 6,141 10,581 105 1,386 100 (22,053) 29,121 34,731 51,219 6,491 11,834 85 1,365 (54) (25,203) NET SALES FROM OPERATIONS................................................................ 83,227 98,523 109,589 ________ (1) (2) This item mainly concerned intragroup sales of goods, services and capital assets recorded at period end in the assets of the purchasing business segment. Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The most substantial intragroup sales are recorded by the Exploration & Production segment. See “item 18 – Note 35 to the Consolidated Financial Statements” for a breakdown of intragroup sales by segment for the reported years. 2011 compared to 2010. Eni’s net sales from operations (revenues) for 2011 ((cid:1)109,589 million) increased by (cid:1)11,066 million from 2010 (or up 11.2%) primarily reflecting higher realizations on oil, products and natural gas in dollar terms. 114 Revenues generated by the Exploration & Production segment ((cid:1)29,121 million) were down by (cid:1)376 million (down by 1.3%) due to a disruption in production flows from Eni’s activities in Libya. This negative was partly offset by higher realizations in dollar terms (oil up 40.3%; natural gas up 7.7%). The settlement of certain commodity derivatives relating to the sale of 9 mmBBL in 2011 lowered Eni’s average liquid realizations by 1.50 $/BBL to 102.11 $/BBL (see page 119). Revenues generated by the Gas & Power segment ((cid:1)34,731 million) increased by (cid:1)5,155 million (or up 17.4%) mainly due to higher spot and oil-linked gas prices which are reflected in Eni’s revenues and increased volumes sold in Italy (up 0.39 BCM, or 1.1%) and in key European markets (up 3.66 BCM, or 7.9%). Revenues generated by the Refining & Marketing segment ((cid:1)51,219 million) increased by (cid:1)8,029 million (or up 18.6%) mainly reflecting higher average selling prices of refined products partly offset by lower sales volumes (down by 1.78 mmtonnes, or 3.8%). Revenues generated by the Petrochemical segment ((cid:1)6,491 million) increased by (cid:1)350 million (up 5.7%) due to an average 20% increase in prices of petrochemical commodities which were partly offset by a decline in volumes sold (down 15%, in particular polyethylene) due to weak demand. Revenues generated by the Engineering & Construction business ((cid:1)11,834 million) increased by (cid:1)1,253 million, or 11.8%, from 2010, as a result of increased activities in the Onshore and Offshore Engineering & Construction businesses. 2010 compared to 2009. Eni’s net sales from operations (revenues) for 2010 ((cid:1)98,523 million) increased by (cid:1)15,296 million from 2009, or 18.4% from 2009, primarily reflecting higher realizations on oil, refined products and natural gas in U.S. dollar terms and the positive impact of the depreciation of the euro against the U.S. dollar. Revenues generated by the Exploration & Production segment ((cid:1)29,497 million) increased by (cid:1)5,696 million, or 23.9%, mainly due to higher realizations in U.S. dollar terms (oil up 27.8%; natural gas up 7.1%) and the depreciation of the euro vs. the U.S. dollar. Eni’s average liquids realizations decreased by 1.33 $/BBL to 72.76 $/BBL due to the settlement of certain commodity derivatives relating to the sale of 28.5 mmBBL. The latter trend is going to continue in 2011 due to current trends in Brent oil prices. Revenues generated by the Gas & Power segment ((cid:1)29,576 million) decreased by (cid:1)871 million (or 2.9%) due to lower sales volumes in Italy (down 5.75 BCM, or 14.4%), partly offset by the positive impact of a slight recovery in spot and oil-linked gas prices due to a less unfavorable pricing environment compared to 2009 which are reflected in Eni’s revenues. Increased sales volumes were also recorded in key European markets. Revenues generated by the Refining & Marketing segment ((cid:1)43,190 million) increased by (cid:1)11,421 million (or 36%) reflecting higher selling prices of refined products. Revenues generated by the Petrochemical segment ((cid:1)6,141 million) increased by (cid:1)1,938 million (up 46.1%) mainly reflecting higher average selling prices (up 35.6%) and a recovery in sales volumes (up 10.9%, mainly in the elastomers business area) following stronger demand on end-markets compared to the particularly weak trading environment of the previous year. Revenues generated by the Engineering & Construction business ((cid:1)10,581 million) increased by (cid:1)917 million, or 9.5%, from 2009, as a result of increased activities in the onshore and drilling business units. b) Operating Expenses The table below sets forth the components of Eni’s operating expenses for the periods indicated. Purchases, services and other ............................................................................... Payroll and related costs ....................................................................................... 58,351 4,181 69,135 4,785 79,191 4,749 Operating expenses ............................................................................................. 62,532 73,920 83,940 Year ended December 31, 2009 2010 2011 ((cid:1) million) 115 2011 compared to 2010. Operating expenses for the year ((cid:1)83,940 million) increased by (cid:1)10,020 million from 2010, up 13.6%, reflecting primarily higher supply costs of purchased gas, and refinery and petrochemical feedstock reflecting trends in the oil environment. Purchases, services and other costs included environmental and other risk provisions amounting to (cid:1)344 million. Particularly, the Group took a provision of (cid:1)69 million relating to an antitrust proceeding in the area of elastomers based on an adverse ruling of the European Court of Justice which is disclosed in more detail in section “Legal Proceedings”, under Note 40 “Guarantees, commitments and risks” in the notes to the consolidated financial statements. Payroll and related costs ((cid:1)4,749 million) were substantially in line with the previous year (down by 0.8%). Higher per-employee labor costs in Italy and outside Italy (mitigated by the positive impact of exchange rates), and an increased average number of employees outside Italy (following higher activity levels in the Engineering & Construction business), were partly offset by a reduction in the average number of employees in Italy and a lower provision for redundancy incentives. 2010 compared to 2009. Operating expenses for the year ((cid:1)73,920 million) increased by (cid:1)11,388 million from 2009, up 18.2%, reflecting primarily higher supply costs of purchased oil, gas and petrochemical feedstocks reflecting trends in the trading environment, the depreciation of the euro against the U.S. dollar, as well as higher operating expenses reported by the upstream activities. Purchases, services and other costs include environmental and other risk provisions for an overall amount of (cid:1)1,291 million mainly associated with an environmental provision recorded to account for a proposed global settlement on certain environmental issues ((cid:1)1,109 million) filed with the Italian Ministry for the Environment, which is disclosed in the paragraph “Significant Transactions” below. Payroll and related costs ((cid:1)4,785 million) increased by (cid:1)604 million, or 14.4%, mainly due to higher unit labor cost in Italy and outside Italy, partly due to exchange rate translation differences, the increase in the average number of employees outside Italy (following higher activity levels in the Engineering & Construction business), as well as increased provisions for redundancy incentives ((cid:1)423 million in 2010) including a provision representing the charge to be borne by Eni as part of a personnel mobility program in Italy for the period 2010-2011. These increases were partly offset by a decrease in the average number of employees in Italy. c) Depreciation, Depletion, Amortization and Impairments The table below sets forth a breakdown of depreciation, depletion, amortization and impairments by business segment for the periods indicated. Exploration & Production (1).................................................................................. Gas & Power ......................................................................................................... Refining & Marketing ........................................................................................... Petrochemicals ...................................................................................................... Engineering & Construction ................................................................................. Other activities ...................................................................................................... Corporate and financial companies ...................................................................... Impact of intragroup profits elimination (2) .......................................................... Total depreciation, depletion and amortization .............................................. Impairments............................................................................................................ Year ended December 31, 2009 2010 2011 ((cid:1) million) 6,789 981 408 83 433 2 83 (17) 8,762 1,051 9,813 6,928 963 333 83 513 2 79 (20) 8,881 698 9,579 6,251 955 351 90 596 2 75 (23) 8,297 1,021 9,318 ________ (1) (2) Exploratory expenditures of (cid:1)1,165 million, (cid:1)1,199 million and (cid:1)1,551 million are included in these amounts relative to the years 2011, 2010 and 2009, respectively. This item concerned mainly intra-group sales of goods, services and capital assets recorded at period end in the equity of the purchasing business segment. 2011 compared to 2010. In 2011, depreciation, depletion and amortization charges ((cid:1)8,297 million) decreased by (cid:1)584 million from 2010, or 6.6%, mainly in the Exploration & Production segment (down (cid:1)677 million) 116 reflecting a lower output in Libya and currency translation differences due to the appreciation of the euro over the dollar (up 4.9%). The Engineering & Construction business recorded higher charges (up (cid:1)83 million) as new vessels and rigs were brought into operation. In 2011, impairments charges of (cid:1)1,021 million mainly regarded impairment losses of refining plants ((cid:1)488 million) based on management’s medium term forecasts that point to continuing weak fundamentals and unprofitable margins resulting in the projection of lower future cash flows of those assets. Impairment charges of oil&gas properties in the Exploration & Production segment ((cid:1)189 million) were triggered by a changed gas price scenario and downward reserve revisions due to lower technical recoverability which mainly pertained to gas properties in the United States. An impairment charge amounting to (cid:1)149 million was recognized on the goodwill allocated to the European Market cash generating unit in the Gas & Power Marketing business segment. In performing the impairment review of the business, management revised downward the profitability expectations driven by continuing margin pressure and declining sales opportunities against the backdrop of weak fundamentals. Other impairment losses related to marginal lines of business in the Petrochemical segment ((cid:1)160 million). 2010 compared to 2009. In 2010, depreciation, depletion and amortization charges amounted to (cid:1)8,881 million, representing an increase of (cid:1)119 million from 2009, or 1.4%. The Exploration & Production segment recorded higher charges (up (cid:1)139 million) due to increased development activities as new fields were brought into production and higher expenditures were made in order to support production levels in producing fields. Those were partly offset by lower exploration expenditures. Also the Engineering & Construction business recorded higher charges (up (cid:1)80 million) as new vessels and rigs were brought into operation. The decrease recorded in the Refining & Marketing segment reflected a review of the residual useful lives of refineries and related facilities, with an impact of (cid:1)76 million. In doing so, the Company believes that it aligned with practices prevailing among integrated oil companies, particularly the European companies. In the Gas & Power segment, the impact of new investments entered into operation was offset by the revision of the useful lives of gas pipelines (from 40 to 50 years), as revised by the Authority for Electricity and Gas for tariff purposes, from January 1, 2010, with an impact of (cid:1)31 million. In 2010, impairment charges of (cid:1)698 million mainly regarded an impairment charge of goodwill allocated to the European gas marketing cash generating unit in the Gas & Power segment. The impaired goodwill derived from the acquisition of the Belgian company Distrigas that was made in 2009. In the 2010 Consolidated Financial Statements, management recognized an impairment loss amounting to (cid:1)426 million associated with goodwill of the European gas business unit considering weak 2010 results and a reduced outlook for profitability as discussed above. Impairment charges of oil and gas properties in the Exploration & Production segment were triggered by a changed pricing environment and downward reserve revisions which mainly pertained to gas properties in the United States with proved and unproved reserves. Minor impairment losses were recorded on assets impaired in previous reporting periods in the Refining & Marketing and Petrochemical segments as capital expenditures made in 2010 were completely written-off as Eni does not expect improving profitability in the underlying business units. For further information see “Item 18 – Consolidated Financial Statements – Note 14 – Tangible and Intangible assets”. d) Operating Profit by Segment The table below sets forth Eni’s operating profit by business segment for the periods indicated. Exploration & Production ..................................................................................... Gas & Power ......................................................................................................... Refining & Marketing ........................................................................................... Petrochemicals ...................................................................................................... Engineering & Construction ................................................................................. Other activities (1) ................................................................................................... Corporate and financial companies (1) .................................................................. Impact of unrealized intragroup profit elimination ............................................. Year ended December 31, 2009 2010 2011 9,120 3,687 (102) (675) 881 (436) (420) ((cid:1) million) 13,866 2,896 149 (86) 1,302 (1,384) (361) (271) 15,887 1,758 (273) (424) 1,422 (427) (319) (189) Operating profit .................................................................................................. 12,055 16,111 17,435 ________ (1) 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” rather than the segment “Corporate and financial companies”. Data for 2009 have been restated accordingly for (cid:1)54 million. 117 The table below sets forth operating profit for each of Eni’s business segments as a percentage of each segment’s net sales from operations (including intragroup sales) for the periods presented. Exploration & Production ..................................................................................... Gas & Power ......................................................................................................... Refining & Marketing ........................................................................................... Petrochemicals ...................................................................................................... Engineering & Construction ................................................................................. Other activities ...................................................................................................... Corporate and financial companies ...................................................................... Year ended December 31, 2009 38.3 12.1 (0.3) (16.1) 9.1 2010 (%) 47.0 9.8 0.3 (1.4) 12.3 2011 54.6 5.1 (0.5) (6.5) 12.0 (32.8) (26.0) (23.4) Group .................................................................................................................... 14.5 16.4 15.9 Exploration & Production. Operating profit in 2011 amounted to (cid:1)15,887 million, up (cid:1)2,021 million from 2010, or 14.6%. The increase in operating profit was driven by higher liquids and gas realizations in dollar terms (up by 40.3% and 7.7%, respectively). The negative drivers were: (i) a disruption in the Company’s output from Libya due to the conflict that occurred in that country in 2011 (an estimated loss of production of 200 KBOE/d); and (ii) the appreciation of the euro against the U.S. dollar for an estimated amount of (cid:1)490 million. The impact on operating profit of higher oil and gas dollar realizations outweighed the negative drivers; however revenues for the year were mainly impacted by those negative factors and we reported a decline compared to the prior year (down by 1.3%). The operating profit of the Exploration & Production segment included the following gains and charges: Asset impairments ................................................................................................. Net gains on disposal of assets .............................................................................. Provision for redundancy incentives..................................................................... Fair value gains/losses on embedded derivatives ................................................ Other ....................................................................................................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) (127) 241 (97) (35) (18) (618) 270 (31) 15 (364) (190) 63 (44) (1) (18) (190) In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. In 2011, the Company’s liquids and gas realizations increased on average by 30% in dollar terms, driven by higher oil prices for market benchmarks (Brent crude price increased by 40%). Eni’s average oil realizations increased on average by 40.3%. Eni’s average liquids realizations were reduced on average by 1.50 $/BBL due to the settlement of certain commodity derivatives relating to the sale of 9 mmBBL in the year at contractually fixed prices. This was the last portion of a multi-year derivative transaction the Company entered into in order to hedge exposure to the variability in cash flows on the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmBBL in the 2008-2011 period. 118 Liquid realizations and the impact of commodity derivatives were as follows: Sales volumes ............................................................................ Sales volumes hedged by derivatives (cash flow hedge) ...... Total price per barrel, excluding derivatives .................... Realized gains (losses) on derivatives .................................... (mmBBL) ($/BBL) Full Year 2009 2010 2011 373.5 42.2 56.98 (0.03) 357.1 28.5 74.09 (1.33) 297.4 9.0 103.61 (1.50) Total average price per barrel ............................................. 56.95 72.76 102.11 The Company’s average gas realizations increased by 7.7% due to the time lags in oil-linked pricing formulae and weak spot price in some areas (in particular the United States). Operating profit in 2010 amounted to (cid:1)13,866 million, up (cid:1)4,746 million from 2009, or 52%, due to higher liquids and gas realizations in dollar terms (up by 27.8% and 7.1%, respectively). The result also reflected: (i) a positive impact associated with the depreciation of the euro against the U.S. dollar, for an estimated amount of (cid:1)400 million; and (ii) the recognition of lower asset impairments and by lower exploration expenditures. These positives were partly offset by increased operating expenses and amortizations charges reflecting new fields entered into operation and activities to improve production rates in existing fields, and higher provisions for redundancy incentives (up (cid:1)66 million). In 2010, the Company’s liquids and gas realizations increased on average by 18.6% in dollar terms, driven by higher oil prices for market benchmarks (Brent crude price increased by 29.2%). Eni’s average oil realizations increased on average by 27.8% driven by a favorable market environment. Eni’s average liquids realizations were impacted for an amount of 1.33$/BBL on average due to the settlement of certain commodity derivatives relating the sale of 28.5 mmBBL in the year at contractually fixed prices. This was part of a derivative transaction the Company entered into to hedge exposure to variability in future cash flows expected from the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmBBL in the 2008-2011 period. As of December 31, 2010, the residual amount of that hedging transaction was 9 mmBBL. Gas & Power. In 2011 the Gas & Power segment reported an operating profit of (cid:1)1,758 million, a decrease of (cid:1)1,138 million from 2010, down by 39.3%, due to an operating loss of (cid:1)710 million incurred by the Marketing business compared to the prior-year profit of (cid:1)555 (down by (cid:1)1,265 million). This negative was partly offset by a better performance achieved by the Italian regulated businesses (up by 4.3%) and the International Transport business (up by 12.0%). The negative performance in the Marketing business was driven by a demand downturn and escalating competitive pressures fueled by oversupplies in the marketplace which impacted our operations both in Italy and outside Italy. Those trends explained the very strong contraction reported in selling margins due to rising costs of gas supplies indexed to the price of oil and certain refined products which increases were only in part absorbed by selling prices at continental spot markets capped by competition. Another important factor which influenced the loss was the disruption in the supplies of Libyan gas, which negatively impacted both the supply mix and sales to shippers. Finally, there were negative trends in the energy parameters and exchange rates to which gas purchase costs and selling prices are indexed considering the time lags of contractual formulas and unusual winter weather conditions impacting seasonal sales, as well as a tariff freeze to residential customers in certain European countries. The results of the Marketing business did not fully benefit from the ongoing renegotiation of gas supply contracts as certain renegotiations were rescheduled thus postponing the recognition of the economic effect. A preliminary agreement on such renegotiations has been achieved early in 2012; management believes that the closing will take place shortly and expects to recognize the associated benefits in 2012 profit. Those benefits will be retroactive from the beginning of 2011. In 2010, the Gas & Power segment reported an operating profit of (cid:1)2,896 million, a decrease of (cid:1)791 million from 2009, down 21.5%, due to a lower performance delivered by the Marketing business which was down by 63.7%. This was partly offset by a better performance achieved by the Italian regulated businesses (up by 12.7%). The negative performance in marketing operations was mainly due to: (i) increasing competitive pressures in Italy, due to oversupply conditions in the marketplace and sluggish demand growth, resulting in both sharply lower gas sales (down by 14.4% and 19.5% to Italian customers and Italian wholesalers importers, respectively) and price reductions to customers during the marketing campaign for the new thermal year beginning on October 1, 2010; (ii) outside Italy, the persistence of unprofitable differentials between oil-linked gas purchase costs provided in Eni’s long-term gas supply contracts and spot prices recorded at European hubs which have become a prevailing reference benchmark for selling prices; (iii) the impairment of goodwill attributed to the European marketing cash generating unit ((cid:1)426 million), based on 2010 results and a reduced profitability outlook for this business; and (iv) negative mark-to-market evaluation of certain commodity derivatives which are recorded against profit as they lack formal requirements to be designated as 119 hedges under applicable accounting standards. These negatives were partly offset by: (i) the recording of higher inventory holding gains due to the impact of rising gas prices on inventories stated at the weighted average cost of supplies or the net realizable value, whichever is lower; and (ii) a non-recurring gain amounting to (cid:1)270 million related to the favorable settlement of an antitrust proceeding resulting in a provision accrued in previous reporting periods being reversed almost entirely to 2010 profit. The provision was originally accrued to take into account a resolution of the Italian Antitrust Authority, who charged Eni with anti-competitive behavior for having allegedly refused third party access to the pipeline for importing natural gas from Algeria. The table below sets forth the break-down of operating profit by businesses in the Gas & Power segment: Marketing................................................................................................................ Regulated businesses in Italy ................................................................................ International transport............................................................................................ Operating profit of the Gas & Power segment ............................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) 555 1,998 343 2,896 1,530 1,773 384 3,687 (710) 2,084 384 1,758 The operating profit of the Gas & Power segment included the following gains and charges: Profit (loss) on stock ............................................................................................. Reversal of a risk provision on an Antitrust proceeding .................................... Environmental charges .......................................................................................... Asset impairments.................................................................................................. Risk provisions....................................................................................................... Provision for redundancy incentives..................................................................... Re-measurement gains/losses on commodity derivatives .................................. Other ....................................................................................................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) (326) (19) (27) (115) (25) 292 6 (214) 117 270 (25) (436) (78) (75) (30) 34 (223) 166 (10) (145) (77) (40) (45) (37) (188) In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Management believes that fair value gains and losses on commodity derivatives entered into for speculative purposes are part of the business’ underlying performance. In 2011, we reported a fair value gain on those derivatives of (cid:1)53 million which were entered into to optimize the business’ margins in line with our revised risk management strategy. Refining & Marketing. In 2011, the Refining & Marketing segment reported an operating loss of (cid:1)273 million, compared to the prior-year profit of (cid:1)149 million. The segment suffered from unprofitable refining margins due to rising costs of oil-based feedstock and energy utilities that could not be transferred to final prices pressured by weak demand and excess capacity in the Mediterranean Basin. In addition, Eni’s complex refineries were hit by shrinking price differentials between light and heavy crudes which reduced the conversion premium. These negatives were offset in part by efficiency enhancement measures, the optimization of supply activities and lower throughputs at the weakest refineries. The Marketing results albeit positive, declined due to lower retail and wholesale demand for gasoline and gasoil, and other products destined to industries affected by the economic downturn, and competitive pressures. In 2010, the Refining & Marketing segment reported an operating profit of (cid:1)149 million, reversing a prior-year loss of (cid:1)102 million. The improvement reflected a less unfavorable refining scenario with Eni’s complex refineries helped by widening price differentials between sour and sweet crudes and better spreads of middle distillates to heating fuel. Refining margins still remained unprofitable as high oil feedstock prices were only partially transferred to final prices of refined products pressured by weak industry fundamentals. The Eni Refining business also benefited from cost efficiencies, and integration of refinery cycles whereby the Gela refinery began processing heavy residues from Taranto throughputs thus enabling to reap cost savings and margins improvements. The Marketing business was affected by rapidly rising supply costs that were only partially transferred to prices at the pump, and lower retail sales in Italy. These negatives were partly offset by higher sales on European networks. 120 The operating profit of Refining & Marketing segment included the following gains and charges: Profit (loss) on stock ............................................................................................. Environmental charges .......................................................................................... Asset impairments.................................................................................................. Risk provisions....................................................................................................... Provision for redundancy incentives..................................................................... Re-measurement gains/losses on commodity derivatives .................................. Other ....................................................................................................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) 792 (72) (389) (17) (22) (39) 2 255 659 (169) (76) (2) (113) 10 11 320 907 (34) (488) (8) (81) 3 (37) 262 In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. We note that losses listed above include material impairment losses of refining plants due to the management’s business outlook that points to continuing weak fundamentals and unprofitable margins resulting in the projection of lower future cash flows. Furthermore, rising crude oil and products prices increased by (cid:1)907 million the carrying amount of year-end inventories of raw materials and products reflecting the impact of the weighted-average cost method of inventory accounting. We regard this inventory holding gain as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies. Petrochemicals. In 2011, the Petrochemical segment incurred a deeper operating loss, down by (cid:1)338 million from a year-earlier (from a loss of (cid:1)86 million in 2010 to a loss of (cid:1)424 million in 2011). This trend was negatively impacted by falling product margins, with the cracker margin severely hit by higher supply costs of oil-based feedstock which were not recovered in sales prices on end markets pressured by weak demand for commodities particularly in the final quarter of the year as the economic activity registered a sharp contraction. Also sale volumes were lower (down 14.6% compared to 2010). In 2010, the Petrochemical segment achieved a sharp reduction in its operating loss which was down by 87.3% from a year-earlier (from a loss of (cid:1)675 million in 2009 to a loss of (cid:1)86 million in 2010). This positive result reflected better market conditions and a recovery in demand which drove improved product margins and higher sales (up by 10.9% mainly in the elastomers business area). Profitability was also supported by cost efficiencies. An inventory holding gain amounting to (cid:1)105 million was recognized (compared with a loss of (cid:1)121 million in 2009) reflecting the impact of higher oil-based feedstock and commodity prices on year-end valuation of inventories according to the average-cost method of inventory accounting, as well as lower asset impairments (down by (cid:1)69 million). The operating profit of the Petrochemical segment included the following gains and charges: Profit (loss) on stock ............................................................................................. Risk provision on an Antitrust proceeding .......................................................... Asset impairments.................................................................................................. Provision for redundancy incentives..................................................................... Other ...................................................................................................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) (121) 105 (121) (10) 3 (249) (52) (26) 27 40 (10) (160) (17) (1) (148) In reviewing the performance of the Company’s business segments, management generally excludes the gains and losses listed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. 121 Engineering & Construction. Operating profit in 2011 amounted to (cid:1)1,422 million, an increase of (cid:1)120 million, or 9.2% compared to 2010. This improvement was driven by revenue growth and a higher profitability of acquired orders, primarily in the Engineering & Construction Onshore and Offshore businesses, reflecting higher level of activities in Middle East, Canada and Australia, and in the offshore drilling business due to the full operation of the drillships Saipem 10000 and 12000 and of the Perro Negro 8, which partly offset the negative impact of the Scarabeo 5 planned maintenance. Operating profit in 2010 amounted to (cid:1)1,302 million, an increase of (cid:1)421 million, or 47.8% compared to 2009. This increase was driven by the positive operating performance reported by the Onshore Construction and Offshore Drilling business areas reflecting higher level of activities and higher margins of the work performed. The utilization rate of the Perro Negro 6 jack-up and the semi-submersibles Scarabeo 3 and 4 increased. In addition, the comparison with 2009 benefited from the circumstance that in 2009 a charge amounting to (cid:1)250 million was recorded to account for a transaction to settle the TSKJ legal proceeding. See “Item 8 Financial Information – Legal Proceedings” for further details. The operating profit of Engineering & Construction segment included the following gains and charges: Expected settlement of the TSKJ proceeding....................................................... Settlement/payments on Antitrust and other Authorities proceedings .............. Asset impairments.................................................................................................. Net gains on disposal of assets .............................................................................. Provision for redundancy incentives..................................................................... Re-measurement gains/losses on commodity derivatives .................................. Year ended December 31, 2009 2010 2011 ((cid:1) million) (250) (2) (3) 16 (239) (24) (3) (5) (14) 22 (24) (35) (4) (10) 28 (21) Other activities. This reporting segment includes the results of operations of Eni’s subsidiary Syndial which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or liquidated in past years. This subsidiary reported operating losses of (cid:1)427 million for 2011, (cid:1)1,384 million for 2010 and (cid:1)436 million for 2009. The magnitude of losses was mainly influenced by the recognition of environmental provisions and, to a lesser extent, other risk provisions whose break-down is provided below. See “Item 4 – Environmental regulation” for further details. Risk provision on an Antitrust proceeding .......................................................... Environmental charges ......................................................................................... Asset impairments ................................................................................................. Risk provisions ...................................................................................................... Provision for redundancy incentives .................................................................... Other ...................................................................................................................... Year ended December 31, 2009 2010 2011 ((cid:1) million) (207) (5) 4 (8) 38 (1,145) (8) (7) (10) (9) (178) (1,179) (59) (141) (4) (9) (8) 20 (201) In addition to above listed charges, losses in the reporting periods presented derived from a marginal line of business that the Company is planning to shut down. Corporate and financial companies. These activities are mainly cost centers which comprise corporate activities and central treasury departments and financial and other subsidiaries that provide a range of financial and business support services to Group companies, including financing of Eni’s projects around the world, information technology, employee selection, training and retention, real estate and other general purposes services. The aggregate Corporate and financial companies reported an operating loss of (cid:1)319 million for 2011, representing a reduction of (cid:1)42 million, compared to the loss recorded in 2010 ((cid:1)361 million), mainly reflecting the implementation of cost efficiency measures. 122 The aggregate Corporate and financial companies reported an operating loss of (cid:1)361 million for 2010, representing a reduction of (cid:1)59 million, compared to the loss recorded in 2009 ((cid:1)420 million), mainly reflecting the implementation of cost efficiency measures. e) Net Finance Expense The table below sets forth a breakdown of Eni’s net financial expense for the periods indicated: Gain (loss) on derivative financial instruments ................................................... Exchange differences, net ..................................................................................... Interest income ...................................................................................................... Finance expense on short and long-term debt ..................................................... Finance expense due to the passage of time ........................................................ Income from equity instruments .......................................................................... Other finance income and expense, net ............................................................... Finance expense capitalized ................................................................................. Year ended December 31, 2009 2010 2011 ((cid:1) million) (4) (106) 33 (753) (218) 163 111 (774) 223 (551) (131) 92 18 (766) (251) 124 (914) 187 (112) (111) 22 (922) (247) 92 (1,278) 149 (727) (1,129) 2011 compared to 2010. In 2011, net finance expense increased by (cid:1)402 million to (cid:1)1,129 million from 2010. Higher finance charges (up by (cid:1)154 million) were recorded, driven by the increased level of average net borrowings and higher borrowing costs driven by movements in both key market benchmarks and spreads applicable to the Company, particularly on euro-denominated loans (the Euribor rate was up by 0.6 percentage points). We expect that our finance expense will continue increasing in 2012 due to movements in our corporate spreads and an ongoing shift in the composition of our finance debt targeting to lengthen the duration. See “Management’s Expectations of Operations” below. Higher losses were recognized in connection with the fair value valuation through profit and loss of certain derivative instruments on interest rates (down by (cid:1)102 million) which did not meet all formal criteria to be designated as hedges under IFRS. Lower negative exchange differences net (down by (cid:1)203 million) were partly offset by gains on exchange rate derivatives (from a loss of (cid:1)111 million to a gain of (cid:1)29 million) recognized through profit and loss as lacking the formal criteria for hedge accounting. 2010 compared to 2009. In 2010, net finance expense increased by (cid:1)176 million to (cid:1)727 million from 2009, mainly due to the circumstance that in 2009 a finance gain of (cid:1)163 million was recorded due to the contractual remuneration on the 20% interest in OAO Gazprom Neft, calculated until it was divested on April 24, 2009. Higher losses were recognized in connection with the fair value valuation through profit and loss of certain derivative instruments on exchange rates (up (cid:1)127 million) that did not meet all formal criteria to be designated as hedges under IFRS. Those losses were offset by net positive exchange differences ((cid:1)198 million). The item “Exchange differences, net” includes a currency adjustment, amounting to (cid:1)33 million, related to the loss provision accrued in the 2009 financial statements to take account of the TSKJ proceeding. Finance charges on finance debt were substantially in line with the previous year, as the impact associated with increased average net borrowings was offset by lower interest rates on both euro-denominated and dollar loans (down 0.4 percentage points the Euribor and the Libor rate). f) Net Income from Investments 2011 compared to 2010. Net income from investments in 2011 was a net gain of (cid:1)2,171 million and mainly related to: (i) gains on disposal of assets ((cid:1)1,125 million) mainly related to a gain of (cid:1)1,044 million recorded on the divestment of Eni’s interests in the international pipelines which transport gas from Northern Europe and Russia and in Gas Brasiliano Distribuidora ((cid:1)50 million); (ii) dividends received by entities accounted for at cost ((cid:1)659 million), mainly relating to Nigeria LNG Ltd; (iii) Eni’s share of profit of entities accounted for with the equity method ((cid:1)544 million), mainly in the Gas & Power, Exploration & Production and Refining & Marketing segments; and (iv) an impairment loss of an interest in a refinery plant in Eastern Europe reflecting a reduced profitability outlook ((cid:1)157 million). 123 2010 compared to 2009. Net income from investments in 2010 was a net gain of (cid:1)1,156 million and mainly related to: (i) Eni’s share of profit of entities accounted for with the equity method ((cid:1)537 million), mainly in the Gas & Power and Exploration & Production segments; (ii) dividends received by entities accounted for at cost ((cid:1)264 million), mainly relating Nigeria LNG Ltd; and (iii) gains on disposal of interests ((cid:1)332 million) related to the full divestment of Società Padana Energia ((cid:1)169 million), a 25% stake in GreenStream ((cid:1)93 million) including a gain from revaluing the residual interest in the venture, a 100% interest in the Belgian company DistriRE SA ((cid:1)47 million) as well as a non-strategic interest of the Engineering & Construction segment ((cid:1)17 million). g) Taxes 2011 compared to 2010. In 2011, income taxes amounted to (cid:1)10,674 million, up by (cid:1)1,517 million from a year ago, or 16.6%, mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. The Group consolidated tax rate increased compared to 2010, up from 55.4% to 57.8% (up 2.4 percentage points). This increase was due to: (i) the recognition of higher deferred taxes ((cid:1)573 million) due to a changed tax rate applicable to a production sharing agreement, including an adjustment to deferred taxation which was recognized upon allocation of the purchase price as part of a business combination when the mineral interest was acquired by Eni; and (ii) higher income taxes currently payable ((cid:1)221 million) following enactment of new tax provisions for Italian subsidiaries as per Law No. 148 of September 2011, converting the Law Decree No. 138/2011. This Law increased the Italian windfall tax levied on energy companies (the so-called Robin Tax) by 4 percentage points to 10.5% and enlarged its scope to include gas transport and distribution companies. These negatives were partly offset by the afore mentioned gains on international transport interests ((cid:1)1,044 million) which were non-taxable items, as well as lower non-deductible tax charges (in particular impairment of goodwill). 2010 compared to 2009. In 2010, income taxes amounted to (cid:1)9,157 million, up (cid:1)2,401 million from a year ago, or 35.5%, mainly reflecting higher income taxes currently payable by subsidiaries in the Exploration & Production segment operating outside Italy due to higher taxable profit. The Group consolidated tax rate was lower compared to 2009, down from 56% to 55.4% (down 0.6 percentage points). This reduction was due to: (i) the recognition of a gain amounting to (cid:1)270 million reflecting the favorable outcome of an antitrust proceeding which was a non-taxable item; and (ii) the circumstance that in 2009 a non-recurring charge amounting to (cid:1)250 million was recorded to settle the TSKJ legal proceedings which was a non-deductible tax item. In addition, the payment of a balance for prior- year income taxes amounted to (cid:1)230 million in Libya as new rules came into effect which reassessed revenues for tax purposes and a lower capacity for Italian companies to deduct the cost of goods sold associated with lower gas inventories at year end ((cid:1)64 million) was incurred, partly offset by net tax gains of (cid:1)150 million. Those positive effects on the Group tax rate were partly offset by a higher percentage of taxable income reported by foreign subsidiaries in the Exploration & Production segment which bore a higher tax rate than the Italian statutory tax rate. h) Non-controlling Interest 2011 compared to 2010. Net profit pertaining to non-controlling interest was (cid:1)943 million and concerned primarily Saipem SpA ((cid:1)552 million) and Snam Rete Gas SpA ((cid:1)385 million). 2010 compared to 2009. Net profit pertaining to non-controlling interest was (cid:1)1,065 million and concerned primarily Snam Rete Gas SpA ((cid:1)537 million) and Saipem SpA ((cid:1)503 million). 124 Liquidity and Capital Resources Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-strategic assets. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and well-balanced financing structure. The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated. This table has been derived from the Group’s Consolidated Financial Statements prepared in accordance with IFRS. Net profit ............................................................................................................... Adjustments to reconcile net profit to net cash provided by operating activities: - amortization and depreciation charges, impairment losses and other non monetary items ............................................................................ - net gains on disposal of assets ............................................................................ - dividends, interest, taxes and other changes accrued in net profit .................. Changes in working capital related to operations ............................................... Dividends received, taxes paid, interest (paid) received during the period ....... Year ended December 31, 2009 2010 2011 ((cid:1) million) 5,317 7,383 7,803 9,117 (226) 6,843 (1,195) (8,720) 9,024 (552) 9,368 (1,720) (8,809) 9,095 (1,170) 10,651 (2,176) (9,821) Net cash provided by operating activities ....................................................... 11,136 14,694 14,382 Capital expenditures .............................................................................................. Investments and purchases of consolidated subsidiaries and businesses .......... Disposals................................................................................................................. Other cash flow related to investing activities (*) ................................................. Changes in short and long-term finance debt ...................................................... Dividends paid and changes in non-controlling interests and reserves ............. Effect of changes in consolidation and exchange differences ............................ (13,695) (2,323) 3,595 101 3,841 (2,956) (30) (13,870) (410) 1,113 202 2,272 (4,099) 39 (13,438) (360) 1,912 668 1,104 (4,327) 10 Change in cash and cash equivalent for the year ........................................... (331) (59) (49) Cash and cash equivalent at the beginning of the year ....................................... Cash and cash equivalent at year end .................................................................. 1,939 1,608 1,608 1,549 1,549 1,500 _______ (*) Net cash used in investing activities included investments in certain financial assets to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investments were as follows: ((cid:1) million) 2009 2010 2011 Financing investments: - securities .................................................................................................................................... - financing receivables ................................................................................................................ Disposal of financing investments: - securities ..................................................................................................................................... - financing receivables ................................................................................................................. Net cash flows from financing activities ................................................................................ (2) (36) (38) 123 311 434 396 (50) (13) (63) 5 32 37 (26) (21) (26) (47) 71 17 88 41 125 The table below sets forth the principal components of Eni’s change in net borrowings (1) for the periods indicated. Net cash provided from operating activities ................................................... Capital expenditures............................................................................................... Acquisitions of investments and businesses ........................................................ Disposals ................................................................................................................ Other cash flow related to capital expenditures, investments and divestments Net borrowings (1) of acquired companies ........................................................... Net borrowings (1) of divested companies ............................................................ Exchange differences on net borrowings and other changes ............................. Dividends paid and changes in minority interest and reserves .......................... Year ended December 31, 2009 2010 2011 11,136 (13,695) (2,323) 3,595 (295) ((cid:1) million) 14,694 (13,870) (410) 1,113 228 (33) (141) (2,956) (687) (4,099) 14,382 (13,438) (360) 1,912 627 (192) (517) (4,327) Change in net borrowings (1)............................................................................... (4,679) (3,064) (1,913) Net borrowings (1) at the beginning of the year .................................................... Net borrowings (1) at year end................................................................................ ________ 18,376 23,055 23,055 26,119 26,119 28,032 (1) Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below. Analysis of Certain Components of Eni’s Change in Net Borrowings In 2011, adjustments to reconcile net profit to net cash provided by operating activities mainly related to non- monetary charges and gains amounting to (cid:1)9,095 million, which primarily regarded depreciation, depletion amortization and impairment charges of tangible and intangible assets ((cid:1)9,318 million). Adjustments to net profit also included gains on disposals ((cid:1)1,170 million), movements in net working capital ((cid:1)2,176 million), income taxes ((cid:1)10,674 million) and interest expenses ((cid:1)737 million) accrued in the year as opposed to amounts actually paid. In 2010, adjustments to reconcile net profit to net cash provided by operating activities mainly related non- monetary charges and gains amounting to (cid:1)9,024 million, which primarily regarded depreciation, depletion amortization and impairment charges of tangible and intangible assets ((cid:1)9,579 million), gains on disposals and movements in net working capital. Adjustments to net profit also included income taxes ((cid:1)9,157 million) and interest expenses ((cid:1)571 million) accrued in the year as opposed to amounts actually paid. a) Changes in Working Capital related to Operations In 2011, changes in working capital absorbed cash flows amounting to a negative (cid:1)2,176 million as a result of: (i) increasing oil, gas and petroleum products inventories (up (cid:1)1,422 million) due to the impact of rising oil prices on inventories stated at the weighted average cost; (ii) cash pre-payments amounting to (cid:1)324 million made to the Company’s suppliers of gas under long-term gas supply contracts whereby the Company has the contractual obligation to lift minimum annual quantities of gas or in case of failure, pre-pay the whole price or a fraction of those quantities as provided by the so-called take-or-pay clause. The amount was net of certain limited volumes make-up in the year. For further details on that asset see “Item 18 – Note 14 – Other non current assets – of the Notes to the Consolidated Financial Statements”; and (iii) an increasing balance of trade receivables vs. payables towards certain joint venture partners in the Exploration & Production segment. These negatives were partly offset by a reduced balance between trade payables and receivables also resulting from a higher volume of trade receivables due beyond the balance sheet date which were transferred without recourse to factoring institutions, amounting to (cid:1)1,779 million in 2011 compared to (cid:1)1,279 million at December 31, 2010. In 2010, changes in working capital absorbed cash flows amounting to a negative (cid:1)1,720 million as a result of: (i) increasing oil, gas and petroleum products inventories (up (cid:1)1,150 million) due to the impact of rising oil prices on inventories stated at the weighted average cost; (ii) cash pre-payments amounting to (cid:1)1,238 million made to the Company’s suppliers of gas under long-term gas supply contracts whereby the Company has the contractual obligation to lift minimum annual quantities of gas or in case of failure, pre-pay the whole price or a fraction of those quantities as provided by the so-called take-or-pay clause. For further details see “Item 18 – Note 9 – Trade and other receivables – of the Notes to the Consolidated Financial Statements”. The Company recognized among its assets a 126 deferred cost to account for those pre-paid volumes of gas. For further details on that asset see “Item 18 – Note 14 – Other non current assets – of the Notes to the Consolidated Financial Statements”. These negatives were partly offset by the increased balance between trade payables and receivables also resulting by the reduction of trade receivables relating to the transfer of certain receivables without recourse to factoring institutions, amounting to (cid:1)1,279 million due in 2011, increasing group cash inflows. b) Investing Activities Exploration & Production ..................................................................................... Gas & Power ......................................................................................................... Refining & Marketing ........................................................................................... Petrochemicals ...................................................................................................... Engineering & Construction ................................................................................. Other activities ...................................................................................................... Corporate and financial companies ...................................................................... Impact of unrealized intragroup profit elimination ............................................. Capital expenditures ........................................................................................... Acquisitions of investments and businesses .................................................... Disposals ............................................................................................................... Year ended December 31, 2009 2010 2011 9,486 1,686 635 145 1,630 44 57 12 13,695 2,323 16,018 (3,595) ((cid:1) million) 9,690 1,685 711 251 1,552 22 109 (150) 13,870 410 14,280 (1,113) 9,435 1,721 866 216 1,090 10 128 (28) 13,438 360 13,798 (1,912) Capital expenditures totaled (cid:1)13,438 million, (cid:1)13,870 million and (cid:1)13,695 million, respectively in 2011, 2010 and 2009. For a discussion of capital expenditures by business segment and a description of year-on-year changes see below “Capital Expenditures by Segment”. Acquisitions of investments and businesses totaled (cid:1)360 million, (cid:1)410 million and (cid:1)2,323 million, respectively in 2011, 2010 and 2009. In 2011, disposals amounted to (cid:1)1,912 million and mainly related to: (i) the divestment of the Company’s interests in the entities engaged in the international transport of gas from Northern Europe and Russia ((cid:1)1,463 million); (ii) the divestment of the 100% stake in Gas Brasiliano Distribuidora, engaged in the distribution activities in Brazil ((cid:1)167 million); and (iii) non-strategic assets in the Exploration & Production segment ((cid:1)154 million). In 2010, disposals amounted to (cid:1)1,113 million and mainly related to: (i) the second tranche of the divestment to Gazprom of the 51% stake in the joint venture Severenergia by the shareholder Artic Russia (Eni and Enel were partners with a stake of 60% and 40% respectively), following exercise of a call option by the Russian company. The cash consideration of this second tranche was (cid:1)526 million; (ii) divestment of non-strategic oil&gas properties in the Exploration & Production segment, for an overall amount of (cid:1)456 million, including divestment of the entire stake in the subsidiary Società Padana Energia ((cid:1)179 million); (iii) the divestment of a 25% stake in GreenStream BV ((cid:1)75 million). c) Dividends paid and Changes in Non-controlling Interests and Reserves In 2011, dividends paid and changes in non-controlling interests and reserves ((cid:1)4,327 million) mainly related to: (i) cash dividends to Eni shareholders ((cid:1)3,695 million, of which (cid:1)1,811 million related to the balance for the dividend relating the fiscal year 2010 and (cid:1)1,884 million as an interim dividend for fiscal year 2011); and (ii) the distribution of dividends to non-controlling interests by Snam Rete Gas SpA and Saipem SpA ((cid:1)518 million) and other consolidated subsidiaries ((cid:1)34 million). In 2010, dividends paid and changes in non-controlling interests and reserves ((cid:1)4,099 million) mainly related to: (i) cash dividends to Eni shareholders ((cid:1)3,622 million, of which (cid:1)1,811 million as an interim dividend for 127 fiscal year 2010); and (ii) the distribution of dividends to non-controlling interests by Snam Rete Gas SpA and Saipem SpA ((cid:1)506 million) and other consolidated subsidiaries ((cid:1)8 million). Financial Condition Management assesses the Group capital structure and capital condition by tracking net borrowings, which is a non- GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities. Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds vs. funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies. The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure. 2009 2010 2011 As of December 31, Short-term Long-term Total Short-term Long-term Total Short-term Long-term Total ((cid:1) million) Total debt (short-term and long-term debt) ... Cash and cash equivalents ..... Securities not related to operations ................. Non-operating financing receivables .................... 6,736 18,064 24,800 7,478 20,305 27,783 6,495 23,102 29,597 (1,608) (1,608) (1,549) (1,549) (1,500) (1,500) (64) (73) (64) (73) (109) (6) (109) (6) (37) (28) (37) (28) Net borrowings ........... 4,991 18,064 23,055 5,814 20,305 26,119 4,930 23,102 28,032 As of December 31, 2009 2010 2011 Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS ............................................. Ratio of total debt to total shareholders’ equity including non-controlling interest ............................................................................ Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest ..... Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) .......................................................... ((cid:1) million) 50,051 55,728 60,393 0.50 0.50 0.49 (0.04) (0.03) (0.03) 0.46 0.47 0.46 In 2011, net borrowings amounted to (cid:1)28,032 million, representing a (cid:1)1,913 million increase from 2010. This increase was mainly due to the large amount of capital expenditures made in the year and dividend payments to shareholders. These outflows were partially funded with cash flows from operations and divestments. However, the Group leverage was 0.46 at December 31, 2011 declining from 0.47 as of end of 2010 due to the fact that the higher 128 level of net borrowings was balanced by a greater total equity. The Group total equity increased due to net profit for the year and currency translation differences recorded in translating to euro amounts the net equity of subsidiaries whose functional currency is the U.S. dollar due to the dollar revaluation in exchange rates recorded at year end (up by 3.1% due to the exchange rate recorded on December 31, 2011 at 1 (cid:1) = 1.294 US$ compared to 1 (cid:1) = 1.336 US$ at December 31, 2010). Total debt of (cid:1)29,597 million consisted of (cid:1)6,495 million of short-term debt (including the portion of long-term debt due within twelve months equal to (cid:1)2,036 million) and (cid:1)23,102 million of long-term debt. Total debt included bonds for (cid:1)15,049 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to (cid:1)1,705 million (including accrued interest and discount). Bonds issued in 2011 amounted to (cid:1)1,493 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (88%), U.S. dollar (8%), pound sterling (2%) and 2% in other currencies. In 2010, net borrowings amounted to (cid:1)26,119 million, representing a (cid:1)3,064 million increase from 2009. This increase was mainly due to the large amount of capital expenditures made in the year, dividend payment to shareholders executed in the year and pre-payments to the Company’s suppliers of gas under long-term contracts upon triggering the take-or-pay clause. These outflows were only partially funded with cash flows from operations, divestments for the year and cash inflow from transferring certain account receivables without recourse to factoring institutions, amounting to (cid:1)1,279 million due in 2011. As a result of an increased level of net borrowings, the Group leverage inched higher to 0.47 at December 31, 2010 from 0.46 as of end of 2009. Total debt of (cid:1)27,783 million consisted of (cid:1)7,478 million of short-term debt (including the portion of long-term debt due within twelve months equal to (cid:1)963 million) and (cid:1)20,305 million of long-term debt. More information about the composition of short-term and long-term finance debt is disclosed under “Item 18 – Notes 21 and 26 to the Consolidated Financial Statements”. Capital Expenditures by Segment Exploration & Production. In 2011, capital expenditures of the Exploration & Production segment amounted to (cid:1)9,435 million, representing a decrease of (cid:1)255 million, or 2.6%, from 2010 mainly due to the development of oil and gas reserves ((cid:1)7,357 million). Significant expenditures were directed mainly outside Italy, in particular Norway, Kazakhstan, Algeria, the Unites States, Congo and Egypt as well as blocks and interests in licenses awarded amounting to (cid:1)754 million, mainly in Nigeria. Development expenditures in Italy concerned well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to (cid:1)1,210 million were directed outside Italy in particular in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway. In 2010, capital expenditures of the Exploration & Production segment amounted to (cid:1)9,690 million, representing an increase of (cid:1)204 million, or 2,2%, from 2009 mainly due to the development of oil and gas reserves ((cid:1)8,578 million). Significant expenditures were directed mainly outside Italy, in particular Egypt, Kazakhstan, Congo, the United States and Algeria. Development expenditures in Italy concerned well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to (cid:1)1,012 million were directed outside Italy in particular to Angola, Nigeria, the United States, Indonesia and Norway. In Italy, exploration activities were directed mainly to the offshore of Sicily. Gas & Power. In 2011, capital expenditures in the Gas & Power segment totaled (cid:1)1,721 million and mainly related to: (i) development and upgrading of Eni’s natural gas transport network in Italy ((cid:1)898 million) and distribution network ((cid:1)337 million), the development and the increase of storage capacity ((cid:1)294 million), as well as and the ongoing development of power generation plants ((cid:1)87 million). In 2010, capital expenditures in the Gas & Power segment totaled (cid:1)1,685 million and mainly related to: (i) developing and upgrading Eni’s transport network in Italy ((cid:1)842 million); (ii) developing and upgrading Eni’s distribution network in Italy ((cid:1)328 million); (iii) developing and upgrading Eni’s storage capacity in Italy ((cid:1)250 million); (iv) completion of construction of the combined cycle power plants at the Ferrara site, upgrading and other initiatives to improve flexibility ((cid:1)115 million); and (v) the upgrading plan of international pipelines ((cid:1)17 million). Refining & Marketing. In 2011, capital expenditures in the Refining & Marketing segment amounted to (cid:1)866 million and regarded mainly: (i) refining, supply and logistics in Italy and outside Italy ((cid:1)629 million), with projects designed to improve the conversion rate and flexibility of refineries, in particular the Sannazzaro refinery, as well as expenditures on health, safety and environmental upgrades; and (ii) upgrade and rebranding of the refined product retail network in Italy ((cid:1)168 million) and in the rest of Europe ((cid:1)60 million). 129 In 2010, capital expenditures in the Refining & Marketing segment amounted to (cid:1)711 million and regarded mainly: (i) refining, supply and logistics in Italy ((cid:1)446 million), with projects designed to improve the conversion rate and flexibility of refineries, in particular Sannazzaro and at the Taranto refineries, as well as expenditures on health, safety and environmental upgrades; and (ii) upgrade of the refined product retail network in Italy and in the rest of Europe ((cid:1)246 million). Expenditures on health, safety and the environment amounted to (cid:1)143 million. Petrochemicals. In 2011, capital expenditures in the Petrochemical segment amounted to (cid:1)216 million ((cid:1)251 million in 2010) and regarded mainly (i) up keeping ((cid:1)59 million); (ii) plant upgrades ((cid:1)53 million), mainly regarding the project “Management of fugitive emissions” aimed at identifying the number of sites of potential emissions where the Company operates, putting Polimeri Europa in a leading position at international level; (iii) environmental protection, safety and environmental regulation ((cid:1)46 million); and (iv) energy recovery project ((cid:1)42 million), mainly related to energy savings projects aimed at reducing CO2 emissions. In 2010, capital expenditures in the Petrochemical segment amounted to (cid:1)251 million ((cid:1)145 million in 2009) and regarded mainly plant upgrades ((cid:1)116 million), up-keeping ((cid:1)59 million), energy recovery ((cid:1)45 million) and environmental protection, safety and environmental regulation compliance ((cid:1)29 million). Engineering & Construction. In 2011, capital expenditures in the Engineering & Construction segment ((cid:1)1,090 million) mainly regarded: (i) construction of a new pipelayer, the ultra-deep Field Development Ship FDS 2, activities for the conversion of a tanker into an FPSO and the construction of a new fabrication yard in Indonesia; (ii) activities for the completion of Saipem 12000, a new ultra-deep water drilling ship, construction of the Scarabeo 8 and 9 semi-submersible rigs and of the Perro Negro 6 jack-up; (iii) realization/development of operating structures in the onshore drilling business unit. In 2010, capital expenditures in the Engineering & Construction segment ((cid:1)1,552 million) mainly regarded: (i) Offshore: the construction of a new pipelayer and the ultra-deep water Field Development Ship FDS 2, the activities for the conversion of a tanker into an FPSO, and the development of a new fabrication yard in Indonesia; (ii) Offshore drilling: the activities of completion of the new ultra-deep water drill ship Saipem 12000, the two semi-submersible rigs Scarabeo 8 and 9, and the jack-up Perro Negro 6; (iii) Onshore drilling: development of operating structures; and (iv) Onshore: maintenance of the existing asset base. Recent Developments The table below sets forth certain indicators of the trading environment for the periods indicated: Three months ended March 31, 2011 2012 Average price of Brent dated crude oil in U.S. dollars (1).................................................................... 104.97 118.49 Average price of Brent dated crude oil in euro (2)................................................................................ 76.79 90.38 Average EUR/USD exchange rate (3).................................................................................................... 1.367 1.311 Average European refining margin in U.S. dollars (4) ......................................................................... 2.92 1.74 EURIBOR - three month euro rate % (3)............................................................................................... 1.0 1.1 ________ (1) (2) (3) (4) Price per barrel. Source: Platt’s Oilgram. Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB). Source: ECB. Price per barrel. FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data. Significant Transactions 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 we expect to recognize those benefits through profit in 2012. The parties also discussed the execution of detailed plan targeting commencement of the construction of the offshore section in the Black Sea of the South Stream gas pipeline with a final investment decision (FID) expected by November 2012. For further details on the matter see “Item 4 – Gas & Power segment”. 130 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. The agreements will enable Eni to divest its residual interest in Galp Energia in accordance to certain terms and time schedule. The Company’s Annual General Shareholders Meeting scheduled on April 30 and May 8, 2012 on first and second call, respectively, is due to approve the full year dividend proposal. Eni expects to pay the balance of the dividend for fiscal year 2011 amounting to (cid:1)0.52 per share in May. Total cash out is estimated at (cid:1)1.88 billion. Management’s Expectations of Operations Management expects the 2012 outlook to be a difficult one due to continuing signs of an economic slowdown, particularly in the Euro-zone, and volatile market conditions. Management expects international oil prices to be supported by robust demand growth from China and other emerging economies, as well as ongoing geopolitical risks and uncertainties, partly offset by a recovery in the Libyan output. For investment planning purposes and short-term financial projections, Eni assumes a full-year average price of $90 a barrel for the Brent crude benchmark. Recovery perspectives look poor in the gas sector. Gas demand is expected to be soft due to slow economic activity and increasing competition from renewable sources; in the meantime the marketplace appears well supplied. Against this backdrop, management expects ongoing margin pressures to continue in 2012, and reduced sales opportunities due to rising competition. Management foresees the persistence of a depressed trading environment in the European refining business. Refining margins are anticipated to remain at unprofitable levels due to high costs of oil supplies, sluggish demand and excess capacity. Against this backdrop, management expectations about the main trends in the Company’s businesses for 2012 and beyond are disclosed below. Exploration & Production • The outlook for production of liquids and natural gas is favorable in 2012, as the Company’s activities in Libya are staging a recovery towards the pre-crisis production plateau. 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. Outside Libya, management expects to drive growth by ramping-up fields started in 2011 and new field start-ups mainly in Algeria and Angola and the joint gas development in Siberia. Based on these ongoing trends, we expect that oil and gas production will grow substantially in 2012 compared to 2011 (in 2011 we reported oil and gas production available for sale at 1,523 KBOE/d). According to management’s plans, production growth will continue in the coming years as the Company is targeting an annual growth rate of over 3% in the 2012-2015 period to achieve a production plateau of 2.03 mmBOE/d by 2015. This production forecast has been made under management’s assumptions for oil prices at 90 $/BBL in 2012 and 2013 and then 85 $/BBL in the subsequent years and in the long-term, as well as a normalized level of Libyan output to calculate the 2011 production baseline. Oil price assumptions are particularly significant when it comes to assess the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. For the current year, the Company estimates that production entitlements in its PSAs will decrease on average by approximately 1,000 BBL/d for a $1 increase in oil prices compared to current Eni’s assumptions for oil prices. This sensitivity analysis only applies to small deviations from the adopted scenario and the impact on Eni’s production may increase more than proportionally as the deviation increases. However, management believes that the sensitivity of production volumes for each U.S. dollar price increase described above broadly continues to apply up to the current oil price environment with Brent prices hovering at around 125 $/BBL as of the date of this filing, based on the Company’s current portfolio of assets. This sensitivity analysis relates to the existing Eni portfolio and might vary in the future. Management estimates that should oil prices stay at the level of 100 $/BBL in the next four years covered by our plan, production growth will still hold an average rate of approximately 3% in the same period. Management expects that a number of factors will drive cost increases in the Exploration & Production operations over future years. Those factors include: (i) the growing complexity and scale of the Company’s planned development projects due to the circumstance that several planned or ongoing projects will be executed offshore or in remote/hostile environments where the Company has been experiencing above- average cost increases; (ii) increasing investing activities that are necessary to support production plateaus at existing fields and counteract natural depletion; and (iii) steady trends in costs for purchasing upstream goods and services. Due to those trends, operating costs and depreciation and amortization charges might trend higher in future years. However management expects that the pace of cost increases will slow down compared 131 to the most recent cost trends incurred by the Company. We believe that a number of actions will help the Company absorb inflationary and cost pressures including tighter cost control, operation efficiency and increasing exposure to large fields which enable the Company to benefit from economies due to scale of operations. In addition, management plans to increase the share of operated production in the Company’s portfolio. Project operatorship enables the Company to better schedule and control project execution, expenditures and timely achievement of project milestones. In addition, the Company plans to seek cost efficiencies due to greater deployment of proprietary technologies designed to maximize the rate of hydrocarbon recovery from reservoirs and reduce drilling costs as well as continuing operational improvement. Gas & Power • The outlook for natural gas sales is uncertain in 2012 due to macroeconomic headwinds, weak demand growth and continuing oversupplies. Against this backdrop, management expects to achieve stable natural gas sales compared to 2011 (in 2011, worldwide gas sales were reported at 96.76 BCM and included sales of both consolidated subsidiaries and equity-accounted entities, as well as upstream direct sales in the United States and the North Sea). Management intends to seek to increase sales volumes and market share in Italy and particularly to retain and develop its retail customer base; outside Italy the main drivers of growth will be sales expansion in the key markets of France, Germany-Austria and Benelux and opportunities in the Far East. Those increases will offset lower sales elsewhere. We expect that two developments will help improve the profitability of the Company’s gas marketing activity in 2012. First, management achieved a preliminary agreement to renegotiate terms and conditions of its supply agreement with Gazprom in the first quarter of 2012. The economic effects of the renewed agreement are expected to be retroactive from beginning of 2011. Therefore, the Company expects to recognize a sizeable gain relating the previous reporting period in the 2012 operating profit. Second, the restart of the supplies of gas from Libya will enable the Company to regain full availability of the Libyan gas to properly manage its supply portfolio and fuel sales to Italian buyers of that gas. We note that in 2011 the disruption in the Libyan supply severely hit the profitability of the Company’s gas marketing business. Apart from these positives, management still expects that continuing margin pressures will erode the business’s profitability in 2012 and beyond. A weaker-than-anticipated demand growth over the short-term and rising competitive pressures fuelled by ongoing oversupply in the European market will reduce sales opportunities and trigger further pricing competition. Unit margins are expected to remain under pressure due to depressed spot prices at continental hubs which have become the contractual benchmark in selling formulas outside Italy, whereas the cost of gas supplies to the Group remains indexed to oil prices. Therefore, the Company is exposed to the risk of rising oil prices. In Italy we expect that gas margins will weaken too, due to a number of catalysts including competitive pressure, an ongoing shift to index selling prices to hub benchmarks in large client segments, measures by the Italian administration to cut the gas tariffs to residential customers as well as the other risk factors described in Item 3. Management plans to counteract those negative factors by leveraging a more competitive Company’s cost structure thanks to the economic and operational benefits associated with the renegotiations of its main long- term arrangements with the Company’s gas suppliers. Through these measures, management will seek to preserve unit margins and recover sales volumes. Difficult market conditions in the European gas sector are expected to continue over the next two to three years. Looking beyond, management expects that a number of positive trends will help rebalance the European market. European gas demand is expected to recover in the long run driven by continuing expansion in the use of gas in electricity production and macroeconomic stability; excess supplies of LNG will be absorbed by growing energy needs from the developing economies of China and other emerging countries; the pace of capacity additions to LNG processing is expected to slowdown in the future; finally production rates from European fields are projected to decline thus increasing the need for gas import requirements. However, there exist a number of risks to this outlook, particularly the possible long-term impacts to gas demand associated with the current economic downturn, an ongoing shift to renewable sources in the production of electricity and home heating and the other risk factors described in Item 3. Eni believes that by the end of the plan period a convergence between spot prices of gas and oil-linked gas costs provided by long- term gas purchase contracts will take place. Management plans to drive volume growth in Italy, key European markets and international sales of LNG in the years subsequent to 2012. Volume growth is expected to be supported by the improved competitiveness of the Company’s offering due to the economic benefits associated with the renegotiation of the Company’s long-term supply contracts, as well as effective marketing actions whereby the Company intends to regain market share in Italy and increase sales volumes in certain European markets. The Company intends to boost sales to business clients, including thermoelectric utilities, large industrial accounts and medium and small enterprises, leveraging the Company’s multiple presence across various markets; brand awareness and expertise in delivering innovative and tailor-made offering structures to best suit customers’ needs (see “Item 4 – Gas & Power”). Company’s marketing effort will also address retail customers across Europe seeking to enhance the ongoing strong customer base. The drivers to achieve this will be a strategy of customer retention centered on brand identity, a distinctive offer and competitive cost to serve. We plan to deploy a wide range 132 of sale channels and continuing innovation in processes, promotion and customer care and post-sale assistance in order to boost sales. Based on the above outlined trends and industrial actions, management believes that profitability in the Company’s gas marketing business will gradually recover along the plan period, albeit the visibility into future results of operations is constrained by the ongoing volatility in marketing margins. Our profitability outlook is subject to the risk of revision in the tariffs to residential customers in Italy associated with the possible impacts of the Italian Government’s decree on liberalizations, as well as the other risk factors described in Item 3. Management will also seek to improve profitability by means of cost efficiencies, streamlining business support activities and reducing marketing and general and administrative costs. In addition, 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 those 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. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosures About Market Risk” and “Item 18 – Note 34 to the Consolidated Financial Statements”. Considering that current imbalances between demand and supply on the European market are expected to continue for some time, management factored in its planning assumptions the risk that the Company sales may fall below the annual minimum take provided by our long-term gas supply contracts thus triggering the take-or-pay clause in the next two to three years. In light of management assumptions for long-term growth in gas demand, the Company believes that in the long-term it will be in the position to recover volumes of gas which have been pre-paid from 2009 to 2011 due to the take-or-pay clause and the expected volumes which might be pre-paid over the next future years due to ongoing uncertainties and weak conditions in the gas market. For more information see the specific risk paragraph in “Item 3 – Risk Factors”. For a discussion of certain risks relating to the impact of the evolution of Italian regulation of the natural gas sector on Eni’s take-or-pay contracts see “Item 3 – Risk Factors – Natural Gas Market”. Regulated businesses in Italy are planned to benefit from the pre-set, regulatory return on new capital expenditures and cost savings from integrating the whole chain of transport, storage and distribution activities. • Refining & Marketing • Management forecasts that the trading environment will show limited improvement throughout the next four years covered by the industrial plan. Particularly we expect refining margins to remain at unprofitable levels in 2012 due to a combination of rising feedstock costs and weak industry fundamentals relating to low fuel demand and excess capacity in the Mediterranean area. Furthermore, compressed differentials between heavy and light crudes will continue eroding Eni’s advantage of having complex refining capacity in place. We note that in the 2011 management recognized substantial impairment losses relating the Company’s refining plants ((cid:1)645 million before tax) due to reduced cash flow projections in the refining business reflecting the persistence of the current industry downturn. Management plans to maintain refinery processed volumes in line with 2011 (in 2011 refining throughputs on own account were reported at 31.96 mmtonnes) in response to a negative trading environment. Management is planning to pursue process optimization measures by improving yields, cycle integration and flexibility, as well as efficiency gains by cutting fixed and logistics costs and energy savings in order to reduce the business exposure to the market volatility and achieve immediate benefits on the profit and loss. Retail sales of refined products in Italy and the rest of Europe are forecast to come in slightly lower than in 2011 (in 2011, retail sales volumes in Italy and Rest of Europe were reported at 11.37 mmtonnes). In Italy where fuel consumption is anticipated to continue on a downward trend and a new wave of liberalization promises to spur competition, management intends to preserve the Company’s market share and profitability by leveraging marketing initiatives tailored to customers’ needs, the strength of the eni brand targeting to complete the rebranding of the network, and an excellent service. Outside Italy, the Company will grow selectively targeting stable volumes. Engineering & Construction • The Engineering & Construction business is expected to see solid results due to a robust order backlog. This business unit has managed through the years to progressively reduce its exposure to the more volatile segments of the industry leveraging on portfolio diversification and an established competitive position in the segment of large upstream projects in frontier areas and complex environments with an important technological content that have shown a good level of resiliency throughout the industry cycles. The entry into operations of new distinctive assets in 2010 and 2011 coupled with the size and quality of the backlog and the strong operating performance in terms of project executions, underpin management’s expectations for 133 further significant strengthening of Saipem’s competitive position in the medium term, ensuring a good level of result stability. Petrochemicals • Eni’s petrochemical operations are exposed to volatile costs of oil-based feedstock and the cyclicality of demand due to the commoditized nature of Eni’s product portfolio and underlying weaknesses in the industry. In 2011 Eni’s petrochemicals business reported wider operating losses due to sharply lower margins reflecting rising oil costs and as demand for petrochemicals commodities plunged in the last quarter of the year dragged down by the economic downturn. Short to medium term perspectives remains uncertain due to a weak macroeconomic outlook which will weigh on a rebound in demand for petrochemicals products and ongoing trends in crude oil prices. To cope with the structural challenges of the Company’s petrochemicals business, management is planning to implement a strategic shift targeting to restore the economic equilibrium of Polimeri Europa over the medium term. This new strategy features a gradual reduction of the exposure to unprofitable, commoditized businesses in favor of growing the Company’s presence in niche productions, particularly elastomers and styrene, which showed a good resilience during the downturn, as well as starting innovative productions in the field of biochemistry. An example in point is the launch of the “green chemistry” project at the Porto Torres plant which envisages restructuring an obsolete, unprofitable plant into a modern facility to produce bio-plastics for which attractive grow rates are seen. Capital Expenditure plans Over the next four years, the Company plans to invest (cid:1)59.6 billion in its businesses to support continued organic growth; approximately 75%, 13%, 5%, 4% and 3% of planned capital expenditures is expected to be directed to the Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction and Petrochemicals segments, respectively. The planned amounts of expenditures also include capital allocation to join venture projects and associates. We plan to allocate the largest portion of resources amounting to some (cid:1)37.6 billion to continuing development activities in our Exploration & Production business to fuel production growth. Project start-ups and plateau enhancement at existing fields will be executed mainly in Norway, Iraq, Angola, Nigeria, Kazakhstan, Mozambique, Italy and Congo. Other important development projects will be executed through joint venture agreements in Venezuela and Russia. Exploration items will attract some (cid:1)5.5 billion to appraise the latest discoveries made by the Company and to support continuing reserve replacement. 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 (Liberia, Ghana) and on unconventional plays. In the Gas & Power business the main investment projects will target the upgrading of gas transport pipelines and the expansion of storage sites and distribution networks. In the Refining & Marketing business we will selectively upgrade refinery conversion capacity and flexibility as well as plant reliability and security. The network of service stations will be upgraded and modernized. In the Petrochemicals business we plan to selectively expand capacity in the best positioned lines of business (namely elastomers), while targeting plant efficiency, reliability and energy savings in other areas. Finally, in the Engineering & Construction business segment we plan to complete the construction of certain rigs and vessels and continuously enhance our fleet and logistic centers. Eni’s capital expenditure program is expected to increase by approximately 12% compared to the previous industrial plan due to planned expenditures for developing new upstream projects that will fuel our long-term production plateau, particularly those associated with reserves development in Mozambique, Nigeria, Indonesia, the Barents Sea and Venezuela and higher exploration expenses. Those increases will be partly offset by the assumption of a slightly weaker U.S. dollar exchange rate vs. the euro compared to the previous industrial plan. In the year 2012, management expects a capital budget almost in line with 2011 (in 2011 capital expenditure amounted to (cid:1)13.44 billion, while expenditures incurred in joint venture initiatives and other investments amounted to (cid:1)0.36 billion). Management plans to continue spending on exploration to appraise the mineral potential of recent discoveries (Mozambique, Norway, Ghana and Indonesia) and investing large amounts on developing growing areas and maintain field plateaus in mature basins. Other investment initiatives will target the upgrading of the gas transport and distribution networks, the completion of the EST project in the refining business, and strengthening selected petrochemicals plants. Management expects to pursue strict capital discipline when assessing individual capital projects. Management assumed an oil price of 90-85 $/BBL in the next four-year period; longer term, management assumed an oil price of 85 $/BBL that is adjusted to take account of expected inflation from 2016 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital to the Group. In 2011, management assessed that the cost of capital to the Group decreased by 0.5 percentage points on average from the 134 previous year reflecting a reduced market risk premium for Eni’s shares. Such trend was partially offset by an increase in the other financial parameters used for determining the cost of capital: cost of borrowings to Eni determined by expected trends for spreads and management’s estimates for the composition of the Company’s finance debt in the next four-year plan, increased risk-free yields reflecting the higher risk premium for Italy and an appreciation of the country risk of Eni’s portfolio which factors in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework as well as the consensus outlook; and (ii) a premium for the business risk. Liquidity and leverage In the foreseeable future, management is strongly focused on preserving a solid balance sheet and an adequate level of liquidity taking into account macroeconomic uncertainties and tight financial markets. For planning purposes, management projected the Company’s expected cash flows assuming a scenario of Brent prices at 90-85 $/BBL for the years 2012-2015 to assess the financial compatibility of its capital expenditures programs and dividend policy with internal targets of ratio of net borrowings to total equity. We note that the Brent price in the period January 1 to March 30, 2012 was 118.49 $/BBL on average. However, we believe that the positive effects associated with higher oil prices on the Company’s results and liquidity in its upstream operations may be short-lived as higher oil prices could trigger a demand downturn which could in turn lead to lowering prices. In addition, rapidly escalating oil prices have an adverse impact on the profitability of our downstream businesses. See “Item 3 – Risk Factors”. In 2012 the ratio of net borrowings to total equity – leverage – is projected to be roughly in line with the level achieved at the end of 2011 assuming a Brent price of $90 a barrel. Looking forward, management will seek to progressively reduce this ratio to below 40% by the end of the plan period leveraging on the projected future cash flow from operations which are estimated to generate enough resources to fund both capital expenditures and dividends to Eni’s shareholders. Management is currently assessing any impact on the Group financial profile associated with the possible finalization of the divestment of certain Eni’s non strategic interests, namely the 52.53% stake in Snam and the 33.34% stake in Galp Energia SGPS SA. On March 29, 2012 the Company signed an agreement with Galp’s reference shareholders which will enable the Company to progressively divest its interest in Galp, thus removing a great deal of uncertainty around this transaction. See “Recent Developments – Significant Transactions”. The outlook for the divestment of Eni’s interest in Snam is uncertain as of the filing date because is subject to enactment of a specific decree by the Italian Government which is a matter out of the control of management. For more details on this issue see “Item 3 – Risk Factors” and “Item 4 – Regulation of Eni’s Businesses”. For planning purposes, management assumed an average exchange rate of approximately 1.35 U.S. dollars per euro in the 2012-2015 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty. See “Item 3 – Risk Factors”. Dividend policy In the next four-year period management intends to maintain its progressive dividend policy. Management plans to pay a dividend of (cid:1)1.04 a share for 2011 subject to approval from the Annual General Shareholders’ Meeting scheduled on May 8, 2012. Of this, (cid:1)0.52 per share was paid in September 2011 as an interim dividend with the balance of (cid:1)0.52 per share expected to be paid late in May 2012. The dividend for fiscal year 2011 represents an increase of 4% compared to the 2010 dividend and was in line with management plans to grow the dividend to shareholders to take into account the expected rate of inflation in OECD countries. We plan to continue increasing the dividend in future years in accordance to this guideline. This dividend policy is based on management’s planning assumptions for oil prices at 90-85 $/BBL in the 2012-2015 period. If management assumptions on oil prices were to change, management may revise the dividend and reset the basis for progressive dividend increases. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. The expectations described above are subject to risks, uncertainties and assumptions associated with the oil and gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, risks in political instability in certain our countries of operations, crude oil and natural gas prices; demand for oil and gas in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climates in countries and regions where Eni operates; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and 135 sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to “Item 3 – Risk Factors”. Off-Balance Sheet Arrangements Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – Note 34 to the Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under “Contractual Obligations” below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses. Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources. Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in “Item 18 – Note 34 to the Consolidated Financial Statements”. 136 Contractual Obligations Amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments. 31,751 Total debt ....................................................................... 24,875 Long-term finance debt .................................................. 4,459 Short-term finance debt .................................................. 2,417 Fair value of derivative instruments .............................. 4,890 Interest on finance debt ............................................... 576 Guarantees to banks .................................................... Non-cancelable operating lease obligations (1) .......... 2,479 Decommissioning liabilities (2)...................................... 14,129 Environmental liabilities (3) ......................................... 1,926 Purchase obligations (4) ................................................. 292,370 Natural gas to be purchased in connection with take-or-pay contracts (5) ......................................... 276,947 Natural gas to be transported in connection with ship-or-pay contracts (5) .......................................... Other take-or-pay and ship-or-pay obligations ............. Other purchase obligations (6) ......................................... Other obligations (7)....................................................... of which: - Memorandum of intent relating to Val d’Agri ........... 10,502 1,923 2,998 142 142 Maturity year Total 2012 2013 2014 2015 2016 ((cid:1) million) 3,313 3,010 5,150 5,076 3,023 2,936 2,892 2,840 303 761 74 664 87 553 52 485 2017 and thereafter 9,490 9,378 112 1,595 534 179 306 21,034 440 305 251 20,943 250 95 221 20,131 161 165 81 255 13,287 798 17,743 191,118 7,883 1,635 4,459 1,789 832 576 839 98 269 21,401 19,972 19,688 19,656 18,932 16,587 182,112 1,034 170 225 4 988 165 193 4 919 176 192 4 898 172 129 3 847 161 148 3 5,816 1,079 2,111 124 4 4 4 3 3 124 TOTAL ........................................................................... 348,264 31,903 26,131 27,757 24,276 21,530 216,667 ________ (1) (2) (3) (4) (5) (6) (7) Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings. Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration. Environmental liabilities do not include the environmental charge amounting to (cid:1)1,109 million for the proposal to the Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment cannot be reasonably estimated. Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risk in the Company Gas & Power business segment” for a discussion of nature and importance of Eni’s take-or-pay contracts and the related risks from the evolving competitive and regulatory environment that could negatively impact Eni’s results. Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States. In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plans (see “Item 18 – Note 28 to the Consolidated Financial Statements”). The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment as of December 31, 2011. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown. Committed on major projects .......................................................... Other committed projects ................................................................. 32,986 22,137 6,103 7,411 6,275 5,446 5,013 3,498 3,309 2,709 12,286 3,073 TOTAL ............................................................................................ 55,123 13,514 11,721 8,511 6,018 15,359 Total 2012 2013 2014 2015 2016 and thereafter ((cid:1) million) 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 market place so as to be unable to meet short-term finance requirements and to settle obligations. 137 Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. For a description of how the Company manages the liquidity risk see “Item 18 – Note 34 to the Consolidated Financial Statements”. At December 31, 2011, Eni maintained short-term committed and uncommitted unused borrowing facilities of (cid:1)11,897 million, of which (cid:1)2,551 million were committed, and long-term committed unused borrowing facilities of (cid:1)3,201 million. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial. Eni has in place a program for the issuance of Euro Medium Term Notes up to (cid:1)15 billion, of which about (cid:1)10.5 billion were drawn as of December 31, 2011. Working Capital Management believes that, taking into account unutilized credit facilities, Eni’s credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements. Credit Risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. For a description of how the Company manages the Credit risk see “Item 18 – Note 34 to the Consolidated Financial Statements”. For information about credit losses in 2011 and the allowance for doubtful accounts see “Item 18 – Note 9 to the Consolidated Financial Statements”. Market Risk In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro vs. other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – Note 34 to the Consolidated Financial Statements”. Research and Development For a description of Eni’s research and development operations in 2011, see “Item 4 – Research and Development”. 138 Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES Directors and Senior Management The following lists the Company’s Board of Directors as at April 20126: Name Giuseppe Recchi Paolo Scaroni Carlo Cesare Gatto Alessandro Lorenzi Paolo Marchioni Roberto Petri Alessandro Profumo Mario Resca Francesco Taranto Position Chairman CEO Director Director Director Director Director Director Director Year elected or appointed 2011 2005 2011 2011 2008 2011 2011 2002 2008 Age 48 65 70 63 42 62 55 66 71 In accordance with Article 17.3 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members. The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 5, 2011, which also established the number of Directors at nine for a term of three financial years. The Board’s mandate will therefore expire with the Shareholders’ Meeting approving the financial statements for the year ending December 31, 2013. The Board of Directors is appointed by means of a slate voting system: the lists are presented by the shareholders representing at least 0.5% of the share capital. The third part of the Board is appointed among the candidates of the minority shareholders. Pursuant to Article 6, paragraph 2, letter d) of the By-laws, the Ministry of the Economy and Finances – in agreement with the Minister of Economic Development – may also appoint a Director without voting rights. Giuseppe Recchi, Paolo Scaroni, Carlo Cesare Gatto, Paolo Marchioni, Roberto Petri and Mario Resca were candidates of the Ministry of Economy and Finance. Alessandro Lorenzi, Alessandro Profumo and Francesco Taranto were candidates of Institutional Investors. The Shareholders’ Meeting appointed Giuseppe Recchi as the Chairman of the Board of Directors and, on May 6, 2011, the Board appointed Paolo Scaroni as the Chief Executive Officer of the Company. On the basis of Italian laws regulating the special powers of the State (see “Item 10 – Stock ownership limitation and voting rights restrictions”), the Minister of Economy and Finance, in agreement with the Minister for Economic Development, may appoint another member of the Board of Directors, without voting rights, in addition to those appointed by the Shareholders’ Meeting. On the occasion of the last Board appointment, the Minister of Economy and Finance opted not to exercise that power. On March 15, 2012, the Law Decree No. 21/2012 on “Provisions regarding special powers on companies in defense and national security areas and for activities of strategic importance in energy, transport and communications areas” was published in the Italian Official Gazette. The Law Decree is in force, but subject to conversion into Law within 60 days. The Decree, issued to comply with the European Commission prescriptions, provides for the repeal of the present special powers (set out in the Law No. 474/1994), when the national strategic assets are identified by the Government. The new special powers of the Government include a veto power and the authority to impose specific conditions on the direct and/or indirect dismissal of such assets, on the basis of objective and non discriminatory criteria. Below are some details on the personal and professional profiles of the Directors. Giuseppe Recchi Born in 1964. He is Chairman of the Board of Eni since May 2011. He is Vice Chairman of GE Capital SpA; member of the board of directors, the compensation and audit committees of Exor SpA (listed at Milan Stock Exchange); member of the European Advisory Board of Blackstone and member of the Massachusetts Institute of Technology E.I. External Advisory Board. He is also member of the executive committees of Confindustria (the Confederation of Italian Industries, where he is Chairman of the Foreign Investment Committee), Assonime (Association of Italian Joint Stock Companies), Aspen Institute Italia; member of the Trilateral Commission; member of the board of directors of FEEM-Eni Enrico Mattei Foundation and of the Italian Institute of Technology. He graduated in Engineering at Polytechnic of Turin. In 1989 started his career as entrepreneur at Recchi SpA, a general contractor (6) Until May 5, 2011, the members of the Board of Directors were: Roberto Poli, Paolo Scaroni, Paolo Andrea Colombo, Alberto Clô, Paolo Marchioni, Marco Reboa, Mario Resca, Pierluigi Scibetta and Francesco Taranto. 139 active in 25 countries in the construction of high-tech public infrastructures. From 1994 he served as Executive Chairman of Recchi America Inc., the U.S. branch of the Group and as Managing Director for the overseas activities of Ferrocemento-Recchi Group (now Condotte SpA). In 1999 he joined General Electric, where he held several managerial positions in Europe and in the United States. He served as Director of GE Capital Structure Finance Group; Managing Director for Industrial M&A and Business Development for GE EMEA; President & CEO of GE Italy. Until May 2011 he was President & CEO of GE South Europe. Mr. Recchi was member of the Honorary Committee for the Rome Candidacy to the 2020 Olympic Games, member of the board of Permasteelisa SpA (listed at Milan stock exchange), Advisory Board member of Invest Industrial (private equity) and visiting professor in Structured Finance to Turin University. Mr. Recchi is occasionally editorial commentator for financial papers (Il Sole 24 Ore, Corriere della Sera, MF and Harvard Business Review). Paolo Scaroni He has been Chief Executive Officer of Eni since June 2005. He is currently Non-Executive Director of Assicurazioni Generali, Non-Executive Deputy Chairman of London Stock Exchange Group, Non- Executive Director of Veolia Environnement. Besides he is in the Board of Overseers of Columbia Business School and Fondazione Teatro alla Scala. After graduating in economics at the Università Luigi Bocconi, Milan, in 1969, he worked for three years at Chevron, before obtaining an MBA from Columbia University, New York, and continuing his career at McKinsey. In 1973 he joined Saint Gobain, where he held a series of managerial positions in Italy and abroad, until his appointment as head of the Glass segment in Paris in 1984. From 1985 to 1996 he was Deputy Chairman and Chief Executive Officer of Techint. In 1996 he moved to the UK and was Chief Executive Officer of Pilkington until May 2002. From May 2002 to May 2005 he was Chief Executive Officer and Chief Operating Officer of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro of the Italian Republic. In November 2007 he was decorated as an Officier of the Légion d’honneur. Carlo Cesare Gatto Born in 1941. He has been Director of Eni since May 2011. He graduated in Economics and Business at the Università degli Studi of Turin. He is a registered public auditor. He is currently Chairman of the Board of Statutory Auditors of RAI SpA, Natuzzi SpA and Difesa Servizi SpA, Chairman of the Board of Directors of DeaPrinting Officine Grafiche Novara 1901 SpA, and Chairman of Flenco Fluid System Srl and Director of Arcese Trasporti SpA. He was teacher of Finance, Administration and Control at the Isvor Fiat SpA training institute. In 1968 he was hired by Impresit as Chief Accountant and managed, in Jordan, the finance department of the local branch. He joined the Fiat Group in 1969 where over the years he held a series of increasing responsibility positions in the area of finance, administration and control. From 1979 to 1990 he was Head of Financial Reporting at Fiat Group and also had responsibility for the control of the transport companies (Sapav, Sadem, Sita), run under concession by the Fiat Group and for which he subsequently oversaw the sale. In 1990 he was appointed Joint Manager of Finance and Control of the Fiat Group, before becoming, in 1998, Chief Administration Officer (CAO) of the Fiat Group. From 2000 to 2004, he was Chief Executive Officer and Deputy Chairman of Business Solution, a new sector created by Fiat for the supply of business services. In 1993 he was the Italian Representative at the European Commission for the fiscal harmonization of member States. In 1992 he was decorated as Cavaliere Ordine al Merito of the Italian Republic and, in 1995, as Ufficiale Ordine al Merito of the Italian Republic. Alessandro Lorenzi Born in 1948. He has been Director of Eni since May 2011. He graduated in Political Science at the Università degli Studi of Turin. He is currently a founding partner of Tokos Srl, consulting firm for securities investment and Chairman of Società Metropolitana Acque Torino SpA. He began his career at SAIAG SpA, involved in the implementation of industrial accounting and reporting. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Head of Administration, Finance and Control and Head of Personnel of Orlandi SpA in Modena (1977-1980) and in charge of the project pertaining the system of administration and control for the production areas (1981-1982). In 1983 he joined GFT Group where he was: Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Central Manager, and subsequently Director of Ersel SIM SpA. In 2000 he became Central Manager of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group. In 2006 he became Central Corporate Manager at Lavazza SpA, becoming member of the Board of Directors from 2008 to June 2011. Until this date, he was also Director of LCS Srl as well as Chairman of COFINCAF SpA until May 2011. Paolo Marchioni Born in 1969. He has been Director of Eni since June 2008. He is a qualified lawyer specializing in penal and administrative law, counselor in Supreme Court and superior jurisdictions. He is currently Director of the Provincial Board of the Province of Verbano-Cusio-Ossola. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010. He acts as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola waste water consortium, the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of Stresa city council. From October 2001 to April 2004 he was Director of CIM SpA of Novara (merchandise interport center) and from December 2002 to December 2005 Director and executive committee member of Finpiemonte SpA. 140 From June 2005 to June 2008 he was Director of Consip. He was Provincial Councillor in charge of budget and balance sheet, property, legal affairs and production activities and Vice President of the Province of Verbano-Cusio-Ossola from June 2009 to October 2011. Roberto Petri Born in 1949. He has been Director of Eni since May 2011. He graduated in law at the Università degli Studi “Gabriele D’Annunzio” of Chieti and Pescara. He has been member of the Board of Directors of the Ravenna Festival since 2007 and he has been Chairman of Italimmobili Srl since 2011. In 1976 he was hired by Banca Nazionale del Lavoro (BNL) where he held a series of positions: Head of the “Overdrafts Advisory” of BNL in Busto Arsizio (1982), Deputy Manager for the industrial division at the BNL branch in Ravenna (1983-1987), Area Chief of BNL in Venice (1987-1989) and Joint Manager of the central office of BNL in Rome (1989-1990). In 1990 he was appointed commercial manager at Banca Popolare and in 1994 he moved, with the same position, to Cassa di Risparmio di Ravenna Group (Carisp Ravenna e Banca di Imola). From 2001 to 2006 he was Chief Secretary to the Under- Secretary of Defense, where he was mainly involved in the Department’s contacts with industry and international relations. From 2008 to 2011 he was Chief Secretary at the Ministry of Defense. From 2003 to 2006 he was Director of Fintecna SpA and from 2005 to 2008 Director of Finmeccanica SpA. Alessandro Profumo Born in 1957. He has been Director of Eni since May 2011. He graduated in Business Administration at the Università Luigi Bocconi of Milan. He is currently Chairman of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also member of the Board of Directors of the Bocconi University in Milan and of the Fondazione Arnaldo Pomodoro. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development projects at Bain, Cuneo e Associati firm (now Bain & Company). In 1991 he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà, where he was in charge of General Manager, for the banking and parabanking sectors. He was also in charge of the yield increase of that company’s bank and of the other group companies operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager, responsible for Programming and Control, becoming General Manager in 1995. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On a international level he was Chairman of the European Banking Federation and Chairman of the IMC Washington. In May 2004 he was decorated as Cavaliere del Lavoro. Mario Resca Born in 1945. He has been Director of Eni since May 2002. He graduated in Economics and Business at the Università Luigi Bocconi of Milan. He is currently General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities. He is also Chairman of Confimprese, Chairman of Convention Bureau Italia SpA, Deputy Chairman of Sesto Immobiliare SpA and Director of Mondadori SpA. After graduating he joined Chase Manhattan Bank. In 1974 he was appointed manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner of Egon Zehnder. In this period he was appointed Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonald’s Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners and Chairman of the American Chamber of Commerce. He was decorated as a Cavaliere del Lavoro in June 2002. Francesco Taranto Born in 1940. He has been Director of Eni since June 2008. He is currently Director of Cassa di Risparmio di Firenze SpA and ERSEL S.I.M. He started working in 1959, in a stock brokerage in Milan; from 1965 to 1982, he worked at Banco di Napoli as deputy manager of the stock market and securities department. He held a series of managerial positions in the asset management field, notably he was manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime group (1987 to 2000), he was Chief Executive Officer of the parent company for a long period. He was also a member of the steering council of Assogestioni and of the Corporate Governance committee for listed companies formed by Borsa Italiana. He was a Director of Enel from October 2000 to June 2008. 141 Senior Management The table below sets forth the composition of Eni’s Senior Management, until December 31, 2011. It includes the CEO, as General Manager of Eni SpA, the Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Executives who directly report to the CEO. Name Management position Paolo Scaroni General Manager of Eni Claudio Descalzi Domenico Dispenza (a) Angelo Fanelli Exploration & Production Chief Operating Officer Gas & Power Chief Operating Officer Refining & Marketing Chief Operating Officer Alessandro Bernini Chief Financial Officer Salvatore Sardo Chief Corporate Operations Officer Massimo Mantovani Marco Petracchini (b) Salvatore Meli (c) Stefano Lucchini General Counsel Legal Affairs Senior Executive Vice President Internal Audit Senior Executive Vice President Research and Technological Innovation Executive Vice President Public Affairs and Communication Senior Executive Vice President Roberto Ulissi Company Secretary Corporate Affairs and Governance Senior Executive Vice President Trading Senior Executive Vice President Executive Assistant to the CEO Marco Alverà (d) Raffaella Leone ________ Year first appointed to current position Total number of years of service at Eni 2005 2008 2005 2010 2008 2008 2006 2011 2011 2005 2006 2005 2005 7 31 38 31 16 7 19 13 30 7 6 7 7 Age 65 57 65 59 51 59 48 47 58 49 49 36 49 (a) (b) (c) (d) Until December 31, 2011. As of January 1, 2012, Umberto Vergine has been appointed as Gas & Power Chief Operating Officer. Appointed as Internal Audit Senior Executive Vice President with effect from January 10, 2011 in the position before managed by Rita Marino. As of August 2, 2011. As of January 16, 2012. The Chief Operating Officers, the Chief Financial Officer, the Chief Corporate Operations Officer and the Senior Executive Vice Presidents and the Chief Executive Officer of Polimeri Europa SpA7 are permanent members of the Management Committee8, which advises and supports the CEO. Chief Operating Officers are appointed by the Board of Directors, upon proposal of the CEO in agreement with the Chairman. Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause, except for the Senior Executive Vice President of Internal Audit Department and the Company Secretary, who are appointed by the Board of Directors. Senior Managers Claudio Descalzi Born in Milan in 1955. He graduated in physics in 1979 at the University of Milan. He continued his studies with specialist courses in Petroleum Engineering in France and in the United States. He joined the Eni Group in 1981 as oil-gas field petroleum engineering and project manager, following the development of North Sea, Libya, Nigeria, and Congo fields. In 1990 he was appointed head of operational activities for Italy. In 1994 he was named Director of Agip Recherches Congo, with responsibility for all local upstream operations, and in 1998 become Vice Chairman & Managing Director of Naoc, an Eni subsidiary in Nigeria. From 2000 to 2001 he was Regional Manager for Africa, Middle East and China at the Agip Division, where in 2002 he was appointed Country Manager for Italy. From 2002 to 2005 he was Regional Manager for Italy, Africa, Middle East at the Eni Exploration & Production Division, and in 2006 he has been named Deputy Chief Operating Officer of the Eni Exploration & Production Division. Since 2006 he has been President of Assomineraria. He is Vice President of Confindustria Energy. Since July 30, 2008 he has been Eni SpA Chief Operating Officer of the Exploration & Production Division. (7) (8) From January 2012. Internal Audit Senior Executive Vice President is not a permanent member of the Management Committee. 142 Domenico Dispenza Born in Trieste in 1946. He has a degree in Aeronautical Engineering at the Politecnico of Milan. In 1973 he completed a Master’s degree in Advanced Technology at Sogesta in Urbino. From January 2006 to December 2011 he was Chief Operating Officer of Eni’s Gas & Power Division. He started working in 1974 at the Study Department of Snam SpA, in 1977 he became head of Systems Analysis and from 1980 to 1991 he was Chief Negotiator for Gas Sales and Purchase Agreement. From 1991 to 1999 he was Director of Gas Supplies. On June 30, 1999 he was appointed CEO of Snam SpA. From 2002 to 2004 he was Deputy COO of Eni’s Gas & Power Division. On April 27, 2004 he was nominated Chairman and CEO of Snam Rete Gas. Domenico Dispenza is currently: CEO of Blue Stream Pipeline Co BV, Member of the Board of Eni Trading & Shipping SpA, Member of the Board of the Eni Foundation, Member of the Board of UNI and Member of the Executive Committee of Eurogas. Since January 2012 he has been Chairman of Polimeri Europa SpA. Umberto Vergine Born in Milan in 1957. He is a Chartered Civil Engineer from Politecnico of Milano and joined Eni in 1984. Having started his career in Agip as Petroleum Engineer, he worked between 1985 and 1991 in Norway on the Ekofisk field, in Angola in Cabinda and in Libya in Tripoli. He became Production Manager of the Crema District in the North of Italy. Between 1993 and 2001, he covered various leading positions overseas, managing different Eni E&P companies: District Manager of Agip UK in Aberdeen, District General Manager of Nigerian Agip Oil Co (NAOC) in Port Harcourt and General Manager of Petrobel Co in Egypt. In 2001 he was Managing Director of Lasmo Venezuela in Caracas. At end 2002 he was appointed Managing Director of Ieoc in Cairo. Returned to Italy in 2004, he held in the Eni E&P Division the following positions: Regional Vice President West Africa and Egypt; Senior Vice President for North Sea, Americas, Russia, Far East and Pacific; Senior Vice President Technologies & Services and Executive Vice President for South Europe, Central Asia, Far East and Pacific. In 2010 he was appointed Eni SpA Senior Executive Vice President for Studies and Research. From January 2012 is Chief Operating Officer of the Gas & Power Division. He is member of the Board of Directors of Saipem SpA. Angelo Fanelli Born in Rome in 1952. He has a degree in mechanical engineering at the University La Sapienza in Rome. After gaining experience at other companies, he joined the Eni Group in 1981, and in the first seven years held “field” positions in the Extra-network and Network markets as Technical Assistant, Lubricants and Sales Promoter on the Motorway Network. From 1988 to 1993 he was Head of the Bologna and Florence sales areas. From 1994 to 2004 he held a number of positions in the Network sector. He was appointed Head of Road Network Management, Head of the Ordinary Network and subsequently Head of Business Network Italy and Head of the Agip Road Transport Division, before becoming Head of Retail Business at the R&M Division. From 2003 to 2004 he was Chairman and Managing Director of AgipRete SpA. In 2004 he was appointed Commercial Director Italy, a job he held until 2005 when he took up the position of Head of Logistics at the Genoa headquarters. In 2006 he was appointed Commercial Director (Executive Vice President) of the Refining & Marketing. Since 2008 he has been a member of the board of Europia in Brussels. On April 6, 2010 he was appointed Chief Operating Officer of Eni SpA - Refining & Marketing. Alessandro Bernini Born in 1960 in Borgonuovo Val Tidone, in the province of Piacenza, Italy. He started his career in 1979 at Neutra Revisioni Sas, based in Milan, first as Junior Accountant in the Auditing Activities Department then as Accountant in Charge. In 1981, he joined Ernst & Young thereafter becoming Senior, Supervisor and Manager. On January 1, 1995 he was appointed Partner of the Company and Chartered Accountant Manager for the Areas of Piacenza, Parma and Cremona and Technical Manager for the branch based in Brescia. In the same period he was also engaged as a Lecturer for post graduate Master’s Degree courses at the Universities of Pavia and Parma. On the September 1, 1996 he joined the Eni Group in quality of Administration Department Manager for Saipem SpA. In 2006 he was appointed Group Chief Financial Officer for Saipem SpA. He has covered executive managerial roles in many important companies of the Saipem Group. From August 1, 2008 he is Chief Financial Officer of the Eni Group. Massimo Mantovani Born in Milan in 1963. He has a degree in Law from Università Statale di Milano and a Master in Law (LLM) from the University of London. He is registered to practice law in Italy and in England as solicitor. For around 5 years he worked for a number of law firms in Milan and London before joining the legal department of Snam SpA in 1993. In October 2005 he was appointed as Legal Affairs Senior Executive Vice President of Eni SpA after a period in which he was legal director of the Gas & Power Division of Eni. Since 2005 he has been a member of the Board of Directors of Snam Rete Gas SpA and is a member of the Watch Structure of Eni SpA. Marco Petracchini Born in Rome in 1964. He graduated cum laude in economics at the University La Sapienza in 1989, in Rome. After graduation, he was hired by Esso Italiana where he held a number of positions in the IT, Finance and Auditing sectors. He joined Eni in 1999, where he was rapidly promoted in the Internal Audit Department. Currently is Senior Executive Vice President of the Internal Auditing Department and supervisor of the Internal Control function.. He is also a member of the Control Body and Secretary of the Internal Control Committee of Eni SpA. He holds international qualifications, including that of Certified Internal Auditor (CIA), awarded by the Institute of Internal Auditors with which he also gained an honorable mention, and Certified Fraud Examiner (CFE), awarded by the Association of Certified Fraud Examiners. Salvatore Meli Born in Torre del Greco in 1953. After earning his degree in Chemical Engineering, in 1980 he began his career as a researcher, gradually taking on positions of greater responsibility up to 1992, when he became Head of Applied Research in Engineering at Eni Research. In 1998 he became Head of Research of Eni Technologies and managed the entire Department of Engineering, Modeling and Pilot Systems, a position he retained until 2003. 143 In January 2004 he was appointed Head of Planning Technology and Development at Eni Corporate, and then, in August 2006, he took the position of Director of Research and Technological Innovation of the E&P Division, with the task of enhancing the role of technological innovation as a leverage in strengthening the competitive position of E&P business. On January 1, 2008 he was appointed Head of Technologies in Strategic Management and Research at Eni Corporate, in charge of monitoring the development of technologies of interest to Eni’s activities and for identifying development opportunities for new technologies and new energy sources. In this position, particular emphasis was placed on activities enhancing intellectual property through a significant increase in the number and quality of patents filed. In June 2009, as part of Eni Corporate Management Studies and Research, he was appointed Executive Vice President of Research & Technological Innovation; since August 2011 he has been reporting directly to the Chief Executive Officer under the aegis of the Research & Technological Innovation Department. Stefano Lucchini Born in Rome in 1962. He is married with two children and has a degree in Economics at the LUISS University in Rome. His first job was in the research department at Montedison. After a period as assistant to the President of the Energy and Commerce Commission of the U.S. Congress in Washington D.C., he was director of communications at Montedison USA in New York. Returning to Italy in 1993, he was responsible for financial communications and investor relations for the Gruppo Ferruzzi Montedison. He joined Enel in 1997, initially in financial communications (where he oversaw the company’s IPO) and subsequently as the group’s head of external relations. He has also been the head of external relations for Confindustria, the Italian employers’ federation. In June 2002 he was appointed head of external relations for the Banca Intesa Group. Since July 2005 he has been senior executive vice president of public affairs and corporate communication for the Eni Group. He teaches at the Advanced School of Journalism at the Catholic University of Milan, for which he is also a member of the evaluation committee. He has been a member of the Board of Directors of AGI (the second Italian newswire company) since 2005. He is Grand Officer of Merit of the Italian Republic and was awarded the Silver Cross Medal by the Italian Red Cross. Since 2007 he has been a member of the supervisory Board of Confindustria and the executive board of UPA. He is also a member of the boards of Censis, the Fondazione Eni Enrico Mattei (FEEM) and the Eni Foundation. He is a Member of the Advisory Board MBA Program LUISS and a Member of the Committee of Guarantors for the celebrations of the 150th Anniversary of Italian Unification, member of the Board of Directors of the American Chamber of Commerce in Italy, member of the Board of Directors of Unindustria and member of the Energy Foundation. He is a visiting fellow of Oxford University and President of the Benedict XVI pro Matrimonio et Familia Foundation. Salvatore Sardo Born in 1952. Chief Corporate Operations Officer of Eni SpA since November 2008, reporting directly to the Chief Executive Officer and in charge of the management and control of Procurement, Human Resources and Organization, Information & Communication Technology, Security, Compensation & Benefits systems, Internal Communications and the subsidiary EniServizi. Since April 2009, he has also been the Chairman of Eni Corporate University and since April 2010 Chairman of Snam Rete Gas (renamed Snam SpA as of January 1, 2012). Graduated in Economics at University of Turin. From 1976 to 1981 at Coopers & Lybrand as auditor, rising the position of Supervisor. From 1981 at Stet, Head of Management Control for Manufacturing. In 1991 co-central Director and, from 1992 to 1996, Central Director for Planning and Control. Nominated in 1997 Deputy General Manager for Administration and Control at Telecom Italia. From 1998 to June 2001, Chairman of Seat Pagine Gialle SpA. From 1999 Operational Manager of the Real Estate sector. Chairman of EMSA, Chairman and CEO of EMSA Servizi and Chairman and CEO of IMMSI, a listed company, as well as Operating Chairman of TELIMM, IMSER and Telemaco, companies operating in the same sector. From 2000 Head of the Real Estate and General Services business unit at Telecom Italia. From 2001 Director of the Real Estate and General Services area reporting directly to the Chief Executive Officer of Telecom Italia. From 2003 Head of group Procurement, Services and Security of Enel SpA, reporting directly to the Chief Executive Officer and managing a procurement budget of over (cid:1)3 billion. From 2005 Senior Executive Vice President of Human Resources and Business Services of Eni, reporting to the Chief Executive Officer, while also in charge of the management and control of Information & Communication Technology and the subsidiary EniServizi. Roberto Ulissi Born in Rome in 1962. Lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance, head of the “Banking and Financial System and Legal Affairs Department”. He was a director of Telecom Italia, Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He was also a member of numerous Italian and European commissions representing the Ministry of the Economy, including, at a national level, the Commission for the Reform of Corporate Law and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale of the Italian Republic. Since 2006 he has been Corporate Affairs and Governance Senior Executive Vice President at Eni and Company Secretary of Eni. He is also a director of Eni International BV. Marco Alverà Graduated from the London School of Economics in 1997 in Philosophy and Economics. He is currently an Associate Fellow at the Oxford University Centre for Corporate Reputation, where he specializes in developing and teaching case studies on doing business in Africa. He started his career at Goldman Sachs in London in 1997 in M&A and Private Equity. In 2000 he co-founded Netesi, Italy’s first broadband ADSL company. From 2002 to 2005 he joined Enel as Head of Group Corporate Strategy before becoming in 2004 Chief Financial Officer of Wind Telecom, overseeing the sale of Wind to Orascom. He joined Eni in 2005 as Assistant to the CEO for special initiatives. 144 In 2006 he was appointed Director of Supply & Portfolio Development at Eni Gas & Power Division and Chief Executive Officer of Bluestream and Promgas. In 2008 he moved to Eni Exploration & Production Division where he was appointed Executive Vice President for Russia, North Europe and Americas. In these countries he managed operations and led negotiations with governments and other international oil companies. Since 2010 he has been Chief Executive Officer of Eni trading and shipping, which manages all the commodity trading and shipping activities for Eni. As of January 16, 2012 he is also Senior Executive Vice President of Eni Trading. He has served on the Board of Gazprom Neft and is Chairman of the Board of Eni’s Russian subsidiaries. Raffaella Leone In Eni since 2005, she is the Executive Assistant to the CEO of Eni. She is President of Servizi Aerei SpA, Vice President of Eni Foundation, member of the Board of Directors of the news agency AGI (Agenzia Giornalistica Italia) and of the Board of Directors of the Eni Enrico Mattei Foundation. Previously, she was the Executive Assistant to the CEOs of Enel (from May 2002 to 2005) and of Pilkington (from 1996 to May 2002). Compensation Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors considering relevant proposals made by the Compensation Committee and after consultation with the Board of Statutory Auditors. Main elements of the compensation of the Chairman, the CEO, other Board members and Eni’s three General Managers are described below. CHAIRMAN OF THE BOARD OF DIRECTORS The Shareholders’ Meeting of May 5, 2011 set remuneration of the Chairman of the Board of Directors, envisaging a fixed gross annual compensation for the mandate equal to (cid:1)265,000, unchanged with respect to the previous mandate. In addition, the Shareholders’ Meeting resolved as for the other Directors, an annual bonus conditioned to a performance parameter measured in terms of “Total Shareholders’ Return” (TSR) delivered by Eni, as benchmarked to that achieved by the other seven largest international oil companies in terms of market capitalization (Exxon, Chevron, Conoco, Shell, British Petroleum, Total, and Statoil). The incentive is paid in the amount of (cid:1)80,000 or (cid:1)40,000, unchanged with respect to the previous mandate, in case Eni ranks first or second, or third or fourth, respectively in a given year. Out of these cases, the bonus is not paid. In 2011, the Company did not meet the performance conditions to award the bonus. Remuneration for powers delegated On June 1, 2011, the Board of Directors defined an additional remuneration for the powers delegated to the Chairman in conformity with the Company’s by-laws. To that end, a fixed annual emolument in the amount of (cid:1)500,000 gross was established, unchanged from the previous mandate, as well as a performance bonus based on the economic/financial and operational performance results achieved by Eni during the year prior to that of the disbursement. On-target bonus is set at 60% of the fixed emolument; the maximum bonus is 78% of the fixed emolument. These objectives, also in line with the framework envisaged for the Chief Executive Officer, focus on the economic/financial performance, and the operational/industrial performance of Eni, and on the implementation of the strategic and sustainability guidelines defined in the 2012-2015 four-year Plan. Treatments established in the event of termination of office or employment No specific treatments are envisaged upon the termination of the office of the Chairman or agreements that envisage indemnities in the case of early termination of the mandate. In any case, the Committee reserves itself the faculty to propose to the Board the possible payment of an indemnity, upon completion of the mandate, in line with the amount of the compensation received and the achievement of performance that is particularly important to Eni. Benefits Forms of insurance related benefit are envisaged for the Chairman. NON-EXECUTIVE DIRECTORS Shareholder established remuneration The Shareholders’ Meeting of May 5, 2011 set remuneration of the Directors for the 2011-2014 mandate, envisaging a fixed gross annual compensation for the mandate equal to (cid:1)115,000, unchanged with respect to the previous mandate. In addition, the Shareholders’ Meeting resolved an annual bonus conditioned to a performance parameter measured in terms of “Total Shareholders’ Return” (TSR) delivered by Eni, as benchmarked to that achieved by the other seven largest international oil companies in terms of market capitalization (Exxon, Chevron, Conoco, Shell, British Petroleum, Total, and Statoil). The incentive is paid in the amount of (cid:1)20,000 or (cid:1)10,000, unchanged 145 with respect to the previous mandate, in case Eni ranks first or second, or third or fourth, respectively in a given year. Out of these cases, the bonus is not paid. In 2011, the Company did not meet the performance conditions to award the bonus. Compensation for participation in Board committees For non-executive and/or independent Directors, it is confirmed the payment of additional annual compensation for participation in Board committees: • • • for the Internal Control Committee, compensation equal to (cid:1)45,000 for the Chairman and (cid:1)35,000 for other members was envisaged, as increased with respect to the previous mandate in relation to the more significant role played by the Committee in supervising company risk; for the Compensation Committee and the Oil-Gas Energy Committee compensation was confirmed, equal to (cid:1)30,000 for the Chairman and (cid:1)20,000 for other members, already envisaged in the previous mandate; and for participation on the Nominating Committee, established in July 2011, it is not envisaged any compensation. In the case of participation on more than one Committee (with the exception of the Nominating Committee), it is envisaged a reduction of compensation by 10%. Treatments established in the event of termination of office or employment No specific treatments are envisaged upon the termination of office of the non-executive Directors or agreements that envisage indemnities in the case of early termination of the mandate. CHIEF EXECUTIVE OFFICER AND GENERAL MANAGER The remuneration structure for the Chief Executive Officer and General Manager for the current mandate was approved by the Board of Directors on June 1, 2011, in relation to the powers delegated to him and incorporates both the compensation determined by the Shareholders’ Meeting on May 5, 2011 for Directors, as well as compensation that would possibly be due for positions held at the Board of Directors of subsidiaries or associated companies. Fixed remuneration Fixed remuneration is set at an annual gross amount of (cid:1)1,430,000, of which (cid:1)430,000 for the role of Chief Executive Officer, and (cid:1)1,000,000 for the role of General Manager. These amounts are unchanged with respect to the previous mandate, in consideration of the continuity of the powers delegated to him. In addition, in his role as Eni Executive, the General Manager is also entitled to receive the indemnities due for travel, both in Italy and abroad, in line with applicable provisions in the relevant national collective labor agreement for managers and in the company additional agreements. Short-term variable incentives The annual variable incentive plan envisages compensation determined in reference to a target incentive level (performance = 100) and maximum level (performance = 130), set at 110% and 155% of the total fixed remuneration, respectively, in connection to the economic/financial and operational performance results achieved by Eni during the previous year. These objectives are focused on Eni’s economic/financial performance, its operational/industrial performance, and on the implementation of the strategic and sustainability guidelines defined in the 2012-2015 four- year Plan. The Company’s Compensation Committee has the faculty to propose extra compensation to the Chief Executive Officer and General Manager in the case of achievement of strategic transactions or arrangements that strengthen the Company’s competitive position over the medium-long term. Long-term variable incentives The long-term variable component consists of two distinct plans: • likewise other Company’s manager, he is eligible to participate a Deferred Monetary Incentive Plan that sets three annual awards from 2012, in relation to the performance of the Company, measured in terms of EBITDA which we believe to be a parameter adopted by the oil&gas industry to assess the industrial performance and in line with Eni’s growth/consolidation strategy in each of its business segments. The base incentive to be awarded is determined in relation to the results achieved by the Company in the year previous to the assignment for on target and maximum amounts that are equal to 55% and 71.5% of total fixed remuneration, respectively. The incentive is paid at the end of a three-year vesting period in relation to the results achieved in each of the three years after that of assignment as a percentage between zero and 170% of the granted amount. EBITDA 2011 results for the purposes of 2012 award and 2012 EBITDA results were determined by the Board of Directors on March 15, 2012, based on a proposal from the Compensation Committee, in line with the Strategic Plan. Should the current office not be renewed, the payment of each incentive awarded will occur at the natural expiry of the relative vesting period, in accordance with the performance conditions defined in the Plan; 146 • he is eligible to participate a Long-Term Monetary Incentive Plan that has replaced the previous stock-option plan, with three annual award from 2011. The target amount corresponds to the valorization of the previous stock option plan, to be carried out by an independent consultant, in accordance with the methods and criteria established by the Board. For 2012, the incentive to be paid at the end of a three-year vesting period is determined as a percentage between zero and 130% of the assigned value, in relation to the results achieved in terms of variation of the Adjusted Net Profit + Depletion Depreciation & Amortization (DD&A) parameter recorded in the three-year period in relative terms with respect to other major international oil companies, based on capitalization. The peer group consists of the following companies: Exxon, Shell, British Petroleum, Chevron, Conoco Phillips, and Total. Should the current office be terminated, the payment of each incentive awarded will occur at the natural expiry of the relative vesting period, in accordance with the performance conditions defined in the Plan. Studies regarding possible changes to the current Performance conditions of the Plan are in course, in order to take into account the specific structure of the Eni business portfolio with respect to that of the peer group in question. Treatments established in the event of termination of office or employment For the Chief Executive Officer and General Manager, in accordance with the practices of the reference market and unchanged from the previous mandate, taking into account also the acquired rights deriving from the employment relationship, established before March 31, 2010, and due to which, in accordance with the Corporate Governance Code, the recommendations pursuant to criteria 6.C.1, letter f) of the same Code results not applicable, the following is envisaged: • upon termination of the employment relationship, in connection with the expiry or early termination of the current mandate, it is envisaged, as an addition to the severance pay due upon termination of employment, and in lieu of any obligations regarding prior notice, an indemnity defined in a fixed component, in the amount of (cid:1)3,200.00 and a variable component calculated with reference to the value of the annual monetary incentive calculated with respect to the average of Eni performance in the three-year period 2011-2013; the indemnity is undue should the termination of the employment relationship meets the requirements of due cause, in case of death and of resignation from office other than as the result of an essential reduction of the powers currently attributed; at the end of the mandate, it is recognized a treatment which, in relation to fixed remuneration and to the 50% of the maximum variable remuneration earned for just the administrative role, guarantees a social security, contribution, and severance pay equal to that paid by Eni for the management employment relationship; and in relation to the obligation assumed by the Chief Executive Officer and General Manager to not carry out any type of activities that could be in competition with that performed by Eni for a period of a year after termination of the employment relationship, in all of Italy, Europe, and North America, the payment of a fee equal to (cid:1)2,219,000 is envisaged. • • In any case, the Committee reserves itself the faculty to propose to the Board, upon the conclusion of the mandate, a possible increase to the amounts due upon termination of office, in the case that over the course of the three-year period results of notable size were obtained. Benefits For the Chief Executive Officer and General Manager, unchanged from the previous mandate and the policy enacted in 2011, insurance related benefit are envisaged and, in particular, in respect of that envisaged in the national collective labor agreement and the Company additional agreement for Eni senior managers, enrolment in the complementary retirement fund (FOPDIRE) as well as in the additional health service fund (FISDE) is envisaged, together with the use of a company car. CHIEF OPERATING OFFICERS OF DIVISIONS AND OTHER MANAGERS WITH STRATEGIC RESPONSIBILITIES Fixed remuneration Fixed remuneration is determined on the basis of the role and the responsibilities assigned, considering the average compensation levels seen in the market of large national companies for roles of a similar level of responsibility and complexity and that may be updated periodically, in the context of the annual salary review process that involves all managerial staff. The Guidelines for 2012, in consideration of the reference context and current market trends, envisage selective criteria, while in any case maintaining appropriate levels for competitiveness and motivation. In particular, the actions proposed regard: (i) interventions to update the fixed amount aimed at holders of roles that increased their area of responsibility or with positioning below the average of the reference market; and (ii) one-time extraordinary interventions connected to achieving results or projects or particular importance during the year. In addition, like all other Senior Managers ("Dirigenti"), the Chief Operating Officers of Divisions and other Managers with Strategic Responsibilities are also entitled to receive the indemnities due for travel, both in Italy and abroad, in line with that envisaged in the relevant national collective labor contract for senior managers and additional company agreements. 147 Short-term variable incentives The annual variable incentive plan envisages compensation determined with reference to the Eni, business area, and individual performance results, based on a scale of 70÷130 with a target incentive level (performance = 100) differentiated based on the role held up to a maximum equal to 60% of the fixed remuneration. The objectives of each business area, determined on the basis of those assigned to the Chief Executive Officer and General Managers, are aimed at economic/financial, operational and industrial performance, on internal efficiency, and issues of sustainability. With regards to Managers with strategic responsibilities, the variable incentive is connected to the Company results and a series of individual objectives assigned in relation to the area of responsibility for the role held, in line with that envisaged in the Company’s performance plan. Long-term variable incentives Chief Operating Officers and other Managers with strategic responsibilities, in line with that envisaged for the Chief Executive Officer and General Manager, participate in the Long-Term Incentive Plans approved by the Board of Directors on March 15, 2012, with the following characteristics: • • Deferred Monetary Incentive Plan (DMI) with three annual awards, starting in 2012, in relation to the performance of the Company measured in terms of EBITDA. The said Plan maintains the same performance conditions and characteristics as described above for the Plan of the Chief Executive Officer and General Manager. For Chief Operating Officers and other Managers with Strategic Responsibilities the base incentive to be assigned at target level is differentiated by the grade of the role up to a maximum equal to 40% of the fixed remuneration. The incentive to be paid at the end of the three-year period in question is determined as a percentage between zero and 170% of the value awarded, in relation to the results achieved. Long-Term Monetary Incentive Plan (LTMI), envisaged for critical managerial staff. This Plan maintains the same performance conditions and characteristics as envisaged in the Plan of the Chief Executive Officer and General Manager. For Chief Operating Officers and other Managers with Strategic Responsibilities the base incentive to be awarded at target level is differentiated by the grade of the role up to a maximum equal to 50% of the fixed remuneration. The incentive to be paid at the end of the three-year period in question is determined as a percentage between zero and 130% of the value awarded, in relation to the results achieved. Studies regarding possible changes to the current Performance conditions of the Plan are in course, in order to take into account the specific structure of the Eni business portfolio with respect to that of the peer group in question. Both Plans provide for clauses aimed at promoting retention of employees, envisaging, in the case of consensual contract resolution, or transfer or loss of control on the part of Eni of the Company of which the individual in question is an employee during the course of the vesting period, that the employee in question conserves the right to the incentive in the measure decreased by the period between the award of the base incentive and the occurrence of said events, or no payment in the case of unilateral termination. Treatments established in the event of termination of office or employment For Chief Operating Officers and other Managers with Strategic Responsibilities, the employment termination treatments established in the relevant national collective labor contract are provided, together with any other additional severance indemnity agreed on an individual basis upon termination, according to the criteria established by Eni for cases of voluntary resignation or early retirement and/or specific compensation for cases in which it is necessary to stipulate non-competition agreements. Benefits For the Chief Operating Officers and other Managers with strategic responsibilities, unchanged from the policy enacted in 2011, insurance related benefit are envisaged and, in particular, in respect of that envisaged in the national collective labor agreement and the Company additional agreement for Eni management, enrolment in the complementary retirement fund (FOPDIRE) as well as in the additional health service fund (FISDE) is envisaged, together with the use of a company car. MARKET REFERENCES AND PAY MIX The remuneration benchmarks used for the various types of roles, are indicated as follows: (i) for the Chairman and non-executive Directors, references relative to similar roles in the largest national listed companies for capitalization; (ii) for the Chief Executive Officer and General Manager, benchmarks relative to similar roles in national and European largest listed companies for capitalization and in the main international companies in the Oil sector; and (iii) for Chief Operating Officers of Divisions and Managers with strategic responsibilities, benchmarks relative to roles with the same level of responsibility and managerial complexity at large national industrial companies. The 2012 remuneration policy guidelines lead to a remuneration mix in line with the managerial role held, with greater weight on the variable component, in particular long-term, for roles characterized by greater impact on company results, calculated taking into consideration the valorization of short and long-term incentives in the hypothesis of on- target results. 148 With the exception of the CEO as described above, none of the Directors of Eni has service contracts with the Company or any of its subsidiaries providing for benefits upon termination of employment. Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below reports individual remuneration earned in 2011 by each Member of the Board of Directors, Statutory Auditors, and Chief Operating Officers. The overall amount earned by other Managers with strategic responsibilities is reported too. Following the mentioned amendment, the table reports the total amount of emoluments paid during the year 2011. ((cid:1) thousand) Name Notes Office Term of office Office expiry (*) Fixed remuneration Committee membership remuneration Bonuses and other incentives Profit sharing Non- monetary benefits Other remuneration Total Variable non-equity remuneration 01.01 - 05.05 05.2011 262 (a) 05.06 - 12.31 04.2014 500 (a) 375 637 500 Severance indemnity for end of office or termination of employment Fair Value of equity remuneration (**) 1,000 (b) Roberto Poli Giuseppe Recchi Paolo Scaroni Alberto Clô Paolo Andrea (1) Chairman (2) Chairman CEO and General Manager (3) (4) Director Colombo Paolo Marchioni Carlo Cesare Gatto Alessandro Lorenzi (5) Director (6) Director (7) Director (8) Director (9) Director Roberto Petri Alessandro Profumo (10) Director (11) Director (12) Director (13) Director (14) Director Pierluigi Scibetta Francesco Taranto Board of Statutory Auditors Ugo Marinelli Marco Reboa Mario Resca Roberto Ferranti Paolo Fumagalli Luigi Mandolesi Tiziano Onesti (15) Chairman (16) Auditor (17) Auditor (18) Auditor (19) Auditor 01.01 - 12.31 04.2014 1,430 (a) 40 (a) 01.01 - 05.05 05.2011 05.06 - 12.31 04.2014 05.06 - 12.31 04.2014 01.01 - 05.05 05.2011 40 (a) 75 (a) 75 (a) 05.06 - 12.31 04.2014 01.01 - 12.31 04.2014 115 (a) 75 (a) 75 (a) 40 (a) 01.01 - 05.05 05.2011 01.01 - 12.31 04.2014 115 (a) 40 (a) 01.01 - 05.05 05.2011 01.01 - 12.31 04.2014 115 (a) 05.06 - 12.31 04.2014 01.01 - 12.31 04.2014 01.01 - 12.31 04.2014 115 (a) 80 (a) 52 (a) 28 (a) 05.06 - 12.31 04.2014 01.01 - 05.05 05.2011 01.01 - 05.05 05.2011 Remuneration in the company preparing the financial statements 28 (a) Remuneration from subsidiaries and associates (20) Auditor (21) Auditor Renato Righetti Giorgio Silva Chief Operating Officers Claudio Descalzi (22) E&P Division Total 06.05 - 12.31 04.2014 01.01 - 12.31 04.2014 28 52 (a) 80 (a) 01.01 - 12.31 3,439 (b) 15 4,884 175 1,000 (c) 16 (b) 13 (b) 32 (b) 38 (b) 39 (b) 24 (b) 29 (b) 16 (b) 45 (b) 13 (b) 45 (b) 56 53 107 113 154 99 104 56 160 53 160 115 80 52 28 74 39 113 52 80 46 (b) 39 (c) 85 Remuneration in the company preparing the financial statements 754 (a) 1,167 (b) 15 1,936 24 Remuneration from subsidiaries and associates Total 754 Domenico Dispenza (23) G&P Division (24) R&M Division Angelo Fanelli 01.01 - 12.31 01.01 - 12.31 740 (a) 541 (a) 1,167 1,339 (b) 504 (b) 595 (c) 595 15 595 13 14 2,531 2,092 1,059 24 41 2,844 (c) 14 Other Managers with strategic responsibilities (***) (25) ________ 3,910 (a) 9,377 310 4,988 (b) 11,812 96 120 (c) 9,114 153 800 22,452 166 420 4,844 Notes (*) For directors appointed by the Shareholders’ Meeting of May 5, 2011, the term of office expires with the Shareholders’ Meeting approving the financial statements for the year ending December 31, 2013. This refers to the 2011 pro-rata value (from January 1 to July 30) of the granting of the 2008 stock option plan in accordance with the breakdown provided for by the accounting standards. (**) (***) Managers who, during the course of the year and with the Chief Executive Officer and Chief Operating Officers, were permanent members of the Management Committee and those who report directly to the Chief Executive Officer (ten managers). 149 (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) Roberto Poli - Chairman of the Board of Directors (a) The amount includes the pro-rata up to May 5, 2011 of the fixed remuneration established by the Shareholders’ Meeting of June 10, 2008 ((cid:1)91 thousand) and of the fixed remuneration for the powers granted by the Board of Directors on July 31, 2008 ((cid:1)171 thousand), respectively. (b) Amount approved by the Board of Directors on April 27, 2011, related to the significant professional contribution made in the achievement of Company objectives during the nine years as Chairman of the Company. Giuseppe Recchi - Chairman of the Board of Directors (a) The amount includes the pro-rata from May 6, 2011 of the fixed remuneration established by the Shareholders’ Meeting of May 5, 2011 ((cid:1)174 thousand) and of the fixed remuneration for the powers granted by the Board of Directors on June 1, 2011 ((cid:1)326 thousand), respectively. Paolo Scaroni - CEO and General Manager (a) The amount includes the fixed remuneration of (cid:1)430 thousand for the role of Chief Executive Officer (which incorporates the remuneration established by the Shareholders’ Meeting of May 5, 2011 as Director) and the fixed remuneration of (cid:1)1 million as General Manager of the Company. To this amount are added the indemnities owed for the travel done, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for managers and the Company’s additional agreements, and other remuneration related to the employment relationship for the 2008-2011 three-year period, for a total amount of (cid:1)651 thousand. (b) The amount includes the payment of (cid:1)1,329 thousand relating to the deferred monetary incentive granted in 2008. (c) Amount approved by the Board of Directors on April 27, 2011, in relation to the significant professional contribution made in the achievement of Company objectives, which payment is deferred to the conclusion of the 2011-2014 mandate. To this amount is added the payment for the end of the 2008-2011 mandate, paid in 2011, to guarantee, in relation to the fixed remuneration and to the 50% of the maximum variable remuneration received during the period for just the administrative role, a social security contribution and a severance pay equal to the amount paid by Eni for the management employment relationship ((cid:1)857 thousand). Alberto Clô - Director (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata up to May 5, 2011, (cid:1)6.3 thousand for the participation in the Compensation Committee, and (cid:1)9.4 thousand for the Oil-Gas Energy Committee, respectively. Paolo Andrea Colombo - Director (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata up to May 5, 2011, (cid:1)6.3 thousand for participation in the Compensation Committee, and (cid:1)6.3 thousand for the Oil-Gas Energy Committee, respectively. Carlo Cesare Gatto - Director (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata from May 6, 2011, (cid:1)20.6 thousand for participation in the Internal Control Committee, and (cid:1)11.8 thousand for the Compensation Committee, respectively. Alessandro Lorenzi - Director (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata from May 6, 2011, (cid:1)26.4 thousand for participation in the Internal Control Committee, and (cid:1)11.8 thousand for the Oil-Gas Energy Committee, respectively. Paolo Marchioni - Director (a) The amount corresponds to the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011. (b) The amount includes (cid:1)27.5 thousand for participation in the Internal Control Committee, and (cid:1)11.8 thousand for the Oil-Gas Energy Committee (pro-rata from May 6, 2011). Roberto Petri - Director (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata from May 6, 2011, (cid:1)11.8 thousand for participation in the Compensation Committee, and (cid:1)11.8 thousand for the Oil-Gas Energy Committee, respectively. Alessandro Profumo - Director (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata from May 6, 2011, (cid:1)11.8 thousand for participation in the Compensation Committee, and (cid:1)17.6 thousand for the Oil-Gas Energy Committee, respectively. (11) Marco Reboa - Director (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata until May 5, 2011, (cid:1)9.4 thousand for participation in the Internal Control Committee, and (cid:1)6.3 thousand for the Oil-Gas Energy Committee, respectively. (12) Mario Resca - Director (13) (14) (15) (16) (17) (18) (19) (20) (21) (22) (23) (24) (25) (a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011. (b) The amount includes (cid:1)27 thousand for participation in the Compensation Committee, and (cid:1)18 thousand for the Oil-Gas Energy Committee. Pierluigi Scibetta - Director (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) The amount includes the pro-rata until May 5, 2011, (cid:1)6.3 thousand for participation on the Internal Control Committee, and (cid:1)6.3 thousand for the Oil-Gas Energy Committee, respectively. Francesco Taranto - Director (a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011. (b) The amount includes (cid:1)26.8 thousand for participation in the Internal Control Committee, (cid:1)6.3 thousand for the Compensation Committee (pro-rata until May 5, 2011), and (cid:1)11.8 thousand for the Oil-Gas Energy Committee (pro-rata from May 6, 2011). Ugo Marinelli - Chairman of the Board of Statutory Auditors (a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011. Roberto Ferranti - Auditor (a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011, entirely paid to the Ministry for Economy and Finance. Paolo Fumagalli - Auditor (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. Luigi Mandolesi - Auditor (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. Tiziano Onesti - Auditor (a) Pro-rata amount until May 5, 2011 of the fixed remuneration set by the Shareholders’ Meeting. (b) Amount relative to annual remuneration of (cid:1)75 thousand as an external member of the Watch Structure established pursuant to Company’s Model 231 starting on the date the role was assigned (May 19, 2011). (c) Amount relative to annual remuneration for the service as Chairman of the Board of Statutory Auditors of AGI ((cid:1)19.5 thousand) and Servizi Aerei ((cid:1)19.5 thousand). Renato Righetti - Auditor (a) Pro-rata amount from May 6, 2011 of the fixed remuneration set by the Shareholders’ Meeting. Giorgio Silva - Auditor (a) The amount corresponds with the fixed annual remuneration which was not changed by the Shareholders’ Meeting of May 5, 2011. Claudio Descalzi - Chief Operating Officer E&P Division (a) To the amount of (cid:1)754 thousand as Gross Annual Salary are added the indemnities owed for the travel done, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for managers and the Company’s additional agreements, for a total amount of (cid:1)309 thousand. (b) The amount includes the payment of (cid:1)280 thousand relating to the deferred monetary incentive granted in 2008. (c) Amount related to the remuneration for the position as Chairman of Eni UK. Domenico Dispenza - Chief Operating Officer G&P Division (a) To the amount of (cid:1)740 thousand as Gross Annual Salary are added the indemnities owed for the travel done, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for managers and the Company’s additional agreements, for a total amount of (cid:1)8 thousand. (b) The amount includes payment of (cid:1)501 thousand relating to the deferred monetary incentive granted in 2008 and the pro-rata amounts from the Deferred Monetary Incentive Plans of 2009 and 2010 paid following the termination in relation to the vesting period in accordance with that defined in the respective Regulations. (c) The amount includes the severance pay owed to him under the applicable law and collective contract and severance incentive paid related to the termination of the employment relationship. Angelo Fanelli - Chief Operating Officer R&M Division (a) To the amount of (cid:1)541 thousand as Gross Annual Salary are added the indemnities owed for the travel performed, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for managers and by the Company’s additional agreements, for a total amount of (cid:1)2 thousand. (b) The amount includes the payment of (cid:1)159 thousand relating to the deferred monetary incentive granted in 2008. Other Managers with strategic responsibilities (a) To the amount of (cid:1)3,910 thousand as Gross Annual Salary are added the indemnities owed for the travel done, in Italy and abroad, in line with the provisions of the relevant national collective labor agreement for managers and the company’s additional agreements, for a total amount of (cid:1)290 thousand. (b) The amount includes the payment of (cid:1)1,751 thousand relating to the deferred monetary incentives granted in 2008. (c) Related to the roles held by Managers with strategic responsibilities in the Watch Structure established pursuant to the Company’s Model 231 and the role of Manager responsible for the preparation of the Company’s financial statements. 150 In particular: • the column “Fixed remuneration” reports, following the criteria of competence, fixed remuneration and fixed salary from employment due for the year, gross of social security and tax expenses to be paid by the employee; it excludes lump-sum expense reimbursements and attendance fees, as they are not envisaged. Details on compensation are provided in the notes, as well as separate indication of any indemnities or payments referred to the employment relationship; the column “Committees membership remuneration” reports, following the criteria of competence, the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately; the column “Variable non-equity remuneration - Bonuses and other incentives” reports the incentives paid during the year due to the vesting of the relative rights following the assessment and approval of the relative performance results by the relevant company bodies, in accordance with that specified, in greater detail, in the Table “Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities”; the column “Profit sharing”, does not include any figures, as no form of profit-sharing is envisaged; the column “Non-monetary benefits” reports, in accordance with competence and taxability criteria, the value of fringe benefits awarded; the column “Other remuneration” reports, in accordance with the criteria of competence, any other remuneration deriving from other services provided; the column “Total” reports the sum of the amounts of all the previous items; the column “Fair value of equity remuneration” reports the fair value of competence of the year related to the existing stock option plans, estimated in accordance with international accounting standards which assign the relevant cost in the vesting period; the column “Severance indemnities for end of office or termination of employment” reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of financial year considered or in relation to the end of the office and/or employment. • • • • • • • 2011 Performance bonuses of the CEO and other top managers Short-term variable incentives The incentive for the 2011 annual plan was paid, with regards to the top management positions, in the face of evaluation of the company performance in relation to verification of results regarding the objectives defined for 2010 in accordance with the Strategic Plan and the annual budget, in terms of: (i) implementation of strategic guidelines, taking into account the evaluation expressed by the Compensation Committee; (ii) operations and industrial performance of the Divisions; (iii) business profitability; and (iv) reduction of costs. With regards to the Chief Operating Officers of the Divisions, the incentive was disbursed on the basis of the economic and operational performance obtained in their respective business sectors, including evaluation of the achievement of specific sustainability objectives. With regards to other Managers with strategic responsibilities, the variable incentive disbursed in 2011 was connected to Company results and a series of individual objectives assigned in relation to the area of responsibility for the role held, in line with that envisaged in the Eni 2010 performance Plan. Eni’s results for the 2010 period, evaluated using a constant scenario approved by the Board at the meeting of March 10, 2011, after a proposal by the Compensation Committee, led to the determination of a performance score of 125 points on the measurement scale used, which envisages a target and maximum performance level, at 100 and 130 points, respectively. For the purposes of the variable remuneration to be disbursed, the performance score established determines: • for the outgoing Chairman, the disbursement of a bonus equal to 75% of the fixed remuneration, taking into account the target (60%) and maximum (78%) incentive levels assigned; for the Chief Executive Officer, the disbursement of a bonus equal to 147.5% of the fixed remuneration, taking into account the target (110%) and maximum (155%) incentive levels assigned; for the Chief Operating Officers of Divisions and Managers with strategic responsibilities, the disbursement of bonuses determined in relation to the specific performance achieved, in accordance with incentive levels differentiated on the basis of the role held. • • Deferred Monetary Incentive Plan At its meeting on March 10, 2011, the Board of Directors, following the review and proposal of the Compensation Committee, determined achievement of a 2010 EBITDA result (evaluated using a constant scenario) at the target level. Therefore, for the Chief Executive Officer and Chief Operating Officer General Manager, the Board determined the assignment of the 2011 base incentive in the amount of (cid:1)786,500 (55% of the fixed remuneration). For Chief Operating Officers and other Managers with Strategic Responsibilities, the incentive amounts defined as “target” were assigned, differentiated by the level of the role up to a maximum equal to 40% of the fixed remuneration. In addition, in 2011 the deferred monetary incentive assigned in 2008 to the Chief Executive Officer and Chief Operating Officer, to the Chief Operating Officers of the Divisions, and to other Managers with strategic 151 responsibilities reached maturity. At its meeting of March 10, 2011, the Board of Directors, on the basis of Eni’s EBITDA results during the 2008-2010 period, approved, based on a proposal from the Compensation Committee, the multiplier to be applied to the base incentive assigned for the purposes of calculating the amount to be disbursed, in the amount of 130%, on the incentive scale 0÷170%. Specifically, an incentive equal to (cid:1)1,329,250 was disbursed to the Chief Executive Officer (equal to 130% of the base incentive of (cid:1)1,022,500 assigned in 2008). Long-Term Monetary Incentive Plan At its meeting of October 27, 2011, for the Chief Executive Officer and Chief Operating Officer General Manager, the Board of Directors, in accordance with the verification and proposal of the Compensation Committee, approved the assignment of the 2011 base incentive from the Long-Term Monetary Incentive Plan envisaged in the Board resolution of June 1, 2011, replacing the previous stock option plan, which was not implemented after 2009. The incentive assigned was defined at (cid:1)2,447,102, in accordance with the criteria and the methods of valorization approved by the Board itself and with the assistance of specialized external providers. For Chief Operating Officers and other Managers with Strategic Responsibilities, the amounts were determined in accordance with the target incentive level, differentiated by the level of the role up to a maximum equal to 50% of the fixed remuneration. The table below indicates, by name, the variable incentives of a monetary nature, both short and long-term, envisaged for the Chief Executive Officer and General Manager, the Chief Operating Officers of the Divisions and, at an aggregate level, for other Managers with strategic responsibilities (including all those individuals who, during the course of the period, filled said roles, even if for only a fraction of the year). In particular: • the column “Bonuses of the year - paid/payable” includes the short-term variable incentive disbursed during the year on the basis of the verification of the performance carried out by the relevant company bodies relative to the objectives defined for the previous year; the column “Bonuses of the year - deferred” includes the amount of the base incentive awarded during the year in implementation of the long-term monetary incentive plans; the column “Bonuses of the year - Deferral period” indicates the duration of the vesting period for the long- term incentives granted during the year; the column “Bonuses of previous years - no longer payable” indicates the long-term incentives no longer distributable in relation to the verification of the performance conditions for the vesting period, or the incentives that expired due to events pertaining to the employment relationships governed by the Regulations of the Plans; the column “Bonuses of previous years - paid/payable” indicates the long-term incentives disbursed during the year, matured on the basis of verification of the performance conditions for the vesting period, or the incentive options disbursed due to events pertaining to the employment relationships governed by the Regulations of the Plans; the column “Bonuses of previous years - still deferred” includes incentives awarded in previous years, in implementation of long-term Plans, which have not yet vested. the column “Other Bonuses” includes incentives paid on a one-time extraordinary basis, connected to the achievement of particularly important results of projects during the year. • • • • • • The Total of the columns “Bonuses of the year - paid/payable”, “Bonuses of previous years - paid/payable” and “Other bonuses” is the same as that indicated in the column “Bonuses and other incentives” in the Compensation table. 152 ((cid:1) thousand) Name Office Plan Bonuses of the year Bonuses of previous years paid/ payable deferred deferral period no longer payable paid/ payable (1) still deferred Other bonuses Roberto Poli Total Paolo Scaroni Chairman CEO and General Manager Total Claudio Descalzi Chief Operating Officer E&P Division Total Domenico Dispenza Chief Operating Officer G&P Division Total Angelo Fanelli Chief Operating Officer R&M Division - Annual Monetary Incentive Plan 2011 BoD March 10, 2011 - Annual Monetary Incentive Plan 2011 BoD March 10, 2011 - Deferred Monetary Incentive Plan 2011 BoD March 10, 2011 - Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011 - Deferred Monetary Incentive Plan 2010 BoD July 28, 2010 - Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010 - Deferred Monetary Incentive Plan 2009 BoD July 30, 2009 - Long-Term Monetary Incentive Plan 2009 BoD November 18, 2009 - Deferred Monetary Incentive Plan 2008 Assignment: BoD March 14, 2008 Disbursement: BoD March 10, 2011 375 375 2,110 787 three-year 2,447 three-year 787 2,501 787 2,716 2,110 3,234 1,329 1,329 6,791 - Annual Monetary Incentive Plan 2011 - Deferred Monetary Incentive Plan 2011 BoD March 10, 2011 - Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011 - Deferred Monetary Incentive Plan 2010 BoD July 28, 2010 - Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010 - Deferred Monetary Incentive Plan 2009 BoD July 30, 2009 - Deferred Monetary Incentive Plan 2008 Assignment: BoD March 14, 2008 Disbursement: BoD March 10, 2011 - Annual Monetary Incentive Plan 2011 - Deferred Monetary Incentive Plan 2010 BoD July 28, 2010 - Deferred Monetary Incentive Plan 2009 BoD July 30, 2009 - Deferred Monetary Incentive Plan 2008 Assignment: BoD March 14, 2008 Disbursement: BoD March 10, 2011 - Annual Monetary Incentive Plan 2011 - Deferred Monetary Incentive Plan 2011 BoD March 10, 2011 - Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011 Deferred Monetary Incentive Plan 2010 BoD July 28, 2010 - Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010 - Deferred Monetary Incentive Plan 2009 BoD July 30, 2009 - Deferred Monetary Incentive Plan 2008 Assignment: BoD March 14, 2008 Disbursement: BoD March 10, 2011 - Deferred Monetary Incentive Plan 2011 BoD March 10, 2011 - Long-Term Monetary Incentive Plan 2011 BoD October 27, 2011 - Deferred Monetary Incentive Plan 2010 BoD July 28, 2010 - Long-Term Monetary Incentive Plan 2010 BoD September 9, 2010 - Deferred Monetary Incentive Plan 2009 BoD July 30, 2009 - Deferred Monetary Incentive Plan 2008 Assignment: BoD March 14, 2008 Disbursement: BoD March 10, 2011 537 309 three-year 363 three-year 537 672 453 453 345 224 three-year 263 three-year 275 347 340 280 280 962 350 141 (2) 140 (3) 105 (2) 245 (3) 246 501 886 194 244 126 487 159 159 564 1,310 three-year 1,519 three-year 1,123 1,463 1,391 2,587 2,829 6,407 7,222 1,751 1,751 4,405 246 3,977 650 12,294 1,000 Total ________ (1) (2) (3) (4) Payment relative to deferred monetary incentive granted in 2008 related to EBITDA performance in the three-year period 2008-2010. Pro-rata amount no longer payable, following the consensual termination, in relation to the vesting period, in accordance with that defined in the Plan Regulations. Pro-rata amount paid, following the consensual termination, in relation to the vesting period, in accordance with that defined in the Plan Regulations. Managers who, during the course of the year and with the Chief Executive Officer and Division Chief Operating Officers, were permanent members of the Company Management Committee and the ones who report directly to the Chief Executive Officer (ten managers). 153 345 Total Other Managers with strategic responsibilities (4) - Annual Monetary Incentive Plan 2011 2,587 Stock Option Plans In 2009 Eni terminated any stock option compensation plan. For existing stock option plans, during the course of 2011, the 2008 awarding from the 2006-2008 Plan reached maturity, in terms of the Chief Executive Officer and the critical managerial staff, connected to the performance achieved by Eni shares in terms of Total Shareholders’ Return (TSR) during the three-year period in question, with respect to the other major international oil companies. At its meeting of March 10, 2011, the Board of Directors, on the basis of the results achieved during the vesting period, verified, in accordance with a proposal from the Compensation Committee, and determined the multiplier to be applied to the number of shares granted for the purposes of determining the number of options which could be exercised starting on July 31, 2011, in a measure equal to 55% on the incentive scale 0÷100%. The options which can be exercised by the Chief Executive Officer were then defined at 348,975, with an exercise price of (cid:1)22.540. Severance indemnity for end of office or termination of employment With its decision of April 27, 2011, the Board of Directors, recognizing the significant professional contribution made to the achievement of the Company objectives by the out-going Chairman and the Chief Executive Officer and General Manager, approved the payment to both, of extraordinary compensation of (cid:1)1 million, holding it to be in line with the criteria of suitability and correctness, as well as proportionality with respect to the payments received over the course of their respective mandates. For the Chief Executive Officer and General Manager, said compensation has been deferred to the end of the 2011-2014 mandate. The Chief Executive Officer and General Manager was entitled the amount envisaged in implementation of the conditions for the end of the 2008-2011 mandate, which envisage, in relation to fixed remuneration and 50% of the maximum variable remuneration received for his position as Company’s manager, social security, and pension contribution, and employment termination payment equal to that paid by Eni for the management employment relationship. To the Chief Operating Officer of the Gas & Power Division, Mr. Dispenza, whose office ended at the end of the financial year, it was paid, in addition to amounts due under the applicable law and collective contract, an amount defined in accordance with the Company policies regarding severance incentive. Accrued compensation Total compensation accrued in the year 2011 pertaining to all the Board members amounted to (cid:1)8.4 million; it amounted to (cid:1)513,000 in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company. For the year ended December 31, 2011, remuneration of persons in key positions in planning, direction and control functions of Eni Group Companies, including executive and non-executive Directors, Chief Operating Officers and other Managers with strategic responsibilities amounted to (cid:1)34 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2011. The break-down is as follow: Fees and salaries.................................................................................................................................................... Post employment benefits..................................................................................................................................... Other long-term benefits....................................................................................................................................... Indemnity upon termination of the office............................................................................................................ 2011 ((cid:1) million) 21 1 10 2 34 The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay. As of December 31, 2011, the total amount accrued to the reserve for employee termination indemnities with respect to members of the Board of Directors who were also employees of Eni, the three Divisional Chief Operating Officers and Eni’s senior managers was (cid:1)1,835 thousand. 154 CEO and General Manager of Eni........................................................................ Chief Operating Officer of the E&P Division...................................................... Chief Operating Officer of the G&P Division ..................................................... Chief Operating Officer of the R&M Division.................................................... ................................................................................................................................. ((cid:1) thousand) 177 323 452 233 650 1,835 Name Paolo Scaroni Claudio Descalzi Domenico Dispenza Angelo Fanelli Senior managers (a) ________ (a) No. 8 managers. Stock Options At December 31, 2011, a total of 11,873,205 options were outstanding for the purchase of an equal amount of Eni ordinary shares with a nominal value of (cid:1)1.00 at an average strike price of (cid:1)23.101. The Company discontinued any stock-based compensation scheme in 2009; as such, options outstanding as of the end of the year pertained to stock options schemes adopted in previous reporting periods. The following table shows the evolution of stock option activity in 2010 and 2011. 2010 Weighted average exercise price ((cid:1)) Number of shares Market price (a) ((cid:1)) Number of shares 2011 Weighted average exercise price ((cid:1)) Market price (a) ((cid:1)) Options as of January 1 ..................................... 19,482,330 New options granted ............................................ 88,500 Options exercised in the period ........................... Options cancelled in the period ........................... 3,656,710 Options outstanding as of December 31 ......... 15,737,120 8,896,125 of which exercisable as of December 31 .......... ________ 23.576 17.811 15,737,120 23.005 16.398 14.941 26.242 23.005 23.362 16.048 16.918 16.398 16.398 208,900 3,655,015 11,873,205 11,863,335 14.333 23.187 23.101 23.101 16.623 17.474 15.941 15.941 (a) Market price relating to new rights assigned, rights exercised in the period and rights cancelled in the period correspond to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of grant; (ii) the date of the recording in the securities account of the managers to whom the options have been granted; and (iii) the date of the unilateral termination of employment for rights cancelled). The market share price of grants outstanding as of the beginning and the end of the year, is the price recorded as of December 31. Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below indicates, by name, the stock options assigned to the Chief Executive Officer and General Manager, to the Chief Operating Officers of the Divisions and, at an aggregate level, to other Managers with strategic responsibilities (including all those individuals who, during the course of the 2010 period, filled said roles, even if for only a fraction of the year). In particular, the purchase rights (options) for Eni shares or for subsidiaries, which can be exercised after three years from the date granted are indicated, in relation to the existing stock incentive plans, the last of which was granted in 2008. The data are shown in accordance with the criteria of aggregate representation, as these are incentive plans which are now only residual. 155 In the line “Options relevant to the year” the table provides evidence of the data indicated in the column “Fair value of equity compensation” in the Compensation table. Name Paolo Scaroni Claudio Descalzi Domenico Dispenza CEO and General Manager of Eni Office Chief Operating Officer of E&P Division Chief Operating Officer of G&P Division Angelo Fanelli Chief Operating Officer of R&M Division Other managers with strategic responsibilities (1) Plan Eni Stock Option Plans Eni Stock Option Plans Eni Stock Option Plans Snam Rete Gas Stock Option Plans (2) Eni Stock Option Plans Eni Stock Option Plans Options held at the start of the year: - number of option - average exercise price - average maturity Options granted during the year: - number of options - exercise price - period of possible exercise - fair value on grant date - grant date - market price of underlying shares upon granting of options Options exercised during the year: - number of options - exercise price - market price of underlying shares on exercise date Options expired during the year: - number of options Options held at the end of the year: - number of options Options relevant to the year (4) - fair value ________ 1,894,230 23.247 33 182,830 23.439 34 251,275 23.571 35 142,000 4.399 30 94,095 23.413 35 1,094,265 23.302 36 ((cid:1)) (months) ((cid:1)) (from-to) ((cid:1)) ((cid:1)) ((cid:1)) ((cid:1)) 285,525 38,475 66,375 22,500 1,608,705 144,355 184,900 (3) 142,000 71,595 (k(cid:1)) 175 24 41 14 277,875 816,390 166 (1) (2) (3) (4) Managers who, during the course of the year and with the Chief Executive Officer and Division Chief Operating Officers, were permanent members of the Company Management Committee and the ones who report directly to the Chief Executive Officer (ten managers). Granting was carried out by Snam Rete Gas (now Snam), in regards to Domenico Dispenza, Chairman of the company until December 23, 2005. Due to consensual termination, the options granted in 2007 and 2008, equal to 46,200 and 81,125 options, respectively, could be exercised within twelve months of the date of termination (by December 30, 2012). This refers to the 2011 pro-rata value (from January 1 to July 30) of the granting of the 2008 stock option plan in accordance with the breakdown provided for by the accounting standards. Board Practices Corporate Governance The corporate governance structure of Eni SpA follows the Italian traditional model, which assigns corporate management to the Board of Directors, the core of the organizational system, supervisory functions to the Board of Statutory Auditors and auditing of the accounts to the Audit firm appointed by the Shareholders’ Meeting. The names of Eni’s Directors, their positions, the year when each of them was initially appointed as a Director and their ages are reported in the related table above. The Board of Directors will expire at the date of the Shareholders’ Meeting approving Eni’s financial statements for the year ending December 31, 2013. Board of Directors’ duties and responsibilities The Board of Directors has the widest powers for the ordinary and extraordinary administration of the Company in relation to its purpose. In a resolution dated May 6, 2011, the Board appointed Paolo Scaroni as CEO and General Manager entrusting him with the widest powers for the ordinary and extraordinary administration of the Company. In the same resolution, the Board delegated to the Chairman, Giuseppe Recchi, the powers to identify and promote integrated projects and international agreements of strategic importance, according to Article 24 of the By-laws, while exclusively reserving the most important strategic, operational and organizational powers in addition to those that cannot be delegated by law. In particular, performing the powers as specified in the Eni Code, and in consultation with the relevant committees, the CEO, and/or the Chairman where applicable, the Board, among other tasks: defines the system of corporate governance of the Company and the Group; establishes the internal committees of the Board; assigns and revokes proxies to the CEO and to the Chairman and defines the limits and modalities for exercising such proxies; defines the 156 fundamental guidelines pertaining to the organizational, administrative and accounting structure of the Company and the internal control system; examines and approves the Company and Group’s strategic, industrial and financial plans and agreements, annual budgets and the semi-annual financial report and the interim reports, as well as the Sustainability Report; receives information from Directors with proxies relative to activities implemented during the exercising of proxies and receives periodical half-year information from the internal committees of the Board; assesses the general management trends of the Company and of the Group paying particular attention to conflicts of interest; examines and approves the operations of the Company and its subsidiaries which are significant from a strategic, economic and financial perspective, particularly with regards to situations in which one or more Directors retain personal or third party interests as well as related parties transactions9; appoints and dismisses the Chief Operating Officer, the Officer in charge of preparing financial reports, the Officer in charge of internal control and a Senior Executive Vice President of Internal Audit; defines a remuneration plan for top management of the Company and the Group; resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the primary subsidiaries; formulates the proposals to present to the Shareholders’ Meeting; and examines and decides on other issues which Directors with proxies believe it is appropriate to present to the Board due to their particular relevance or sensitivity. In accordance with Article 23.2 of the By-laws, the Board also decides on: mergers operations and proportional spin-off operations in shareholdings with share quotas exceeding 90%; on the creation and closing of branches; and on adjustments of the By-laws to regulatory provisions. In accordance with the By-laws, the Chairman and the Chief Executive Officer retain representative powers for the Company. Directors’ independence During its meeting on May 6, 201110 and, after the investigation of the Nomination Committee, in the meeting held on February 14, 2012, the Board of Directors has verified that the non-executive Directors Gatto, Lorenzi, Marchioni, Petri, Profumo, Resca and Taranto are independent. This determination was made by the Board on the basis of statements made by Directors and of the information available to the Company, and taking into account the criteria of independence set forth by in Italian regulations and the Corporate Governance Code of Borsa Italiana. Director Resca was confirmed as being independent under the terms of the Eni Code as well, even though he has held the position for over nine years, because of his recognized independence of judgment. With reference to the marital relationship of the Director Profumo with an employee of the Company, the Board considered that this relationship does not absolutely compromise the independence requirements requested by Eni Code, in consideration of the ethical and professional rigor of this Director and of his international reputation. The Board of Statutory Auditors has consistently verified the correct application of the criteria and procedures adopted by the Board for assessing the independence of its members. The above referenced independence criteria may not be equivalent to the independence criteria set forth by the NYSE listing standards applicable to a U.S. domestic company. Board Committees The Board of Directors has established four internal committees with consulting and advisory functions to the Board: (a) the Internal Control Committee; (b) the Compensation Committee; (c) the Nomination Committee11; and (d) the Oil-Gas Energy Committee. The Internal Control Committee and the Compensation Committee are required by the Corporate Governance Code of Borsa Italiana. The composition, role and functioning of these committees are governed by their related regulations which are approved by the Board, in compliance with the criteria outlined in the Eni Code. The committees required by the Code (Internal Control Committee, Nomination Committee and Compensation Committee) are composed of not less than three members and, in any case, fewer than the majority of members of the Board. The committees are composed of non-executive Directors, all of whom are independent with the exception of the Nomination Committee. With regard to this Committee, the majority of its members are independent in accordance with the recommendations of the Corporate Governance Code of Borsa Italiana. (9) (10) (11) The Board of Directors, on November 18, 2010, approved the Management System Guideline (MSG) “Transactions involving interests of directors and statutory auditors and transactions with related parties”, which has been applied since January 1, 2011, to ensure transparency and substantial and procedural fairness of transactions with related parties. The Board modified this MSG on January 19, 2012. Beforehand the Board of Directors had confirmed – at its Meeting on March 10, 2011 – that the non-executive Directors Clô, Colombo, Marchioni, Reboa, Resca, Scibetta and Taranto were independent. This determination was made on the basis of statements made by the Directors and on the information available to the Company, and taking into account the criteria of independence set forth by Italian regulations and the Corporate Governance Code of Borsa Italiana. The Board of Statutory Auditors verified the correct application of the criteria and procedures adopted by the Board for assessing the independence of its previous members. The Board of Directors of Eni established the Nomination Committee on July 28, 2011. 157 In the exercise of their role, the committees have the right to access any information necessary for the effective fulfillment of their tasks. They are also provided with adequate financial resources and retain the right to avail themselves of external consultants according to terms established by the Board of Directors. With the exception of the Nomination Committee, the Chairman of the Board of Statutory Auditors or a Statutory Auditor appointed by the former, and upon explicit invitation and with reference to specific topics on the agenda of the day, also external parties may participate in Committee meetings. The Chairman of the Board of Statutory Auditors or a Statutory Auditor appointed by the former may participate in the Nomination Committee meetings exclusively for the topics on the agenda of the day which are related to their duties. Minutes of all committee meetings are drafted by the respective secretaries. The current members of the Internal Control Committee, Compensation Committee, Oil-Gas Energy Committee were appointed by the Board of Directors on May 6, 2011. The current members of the Nomination Committee were appointed by the Board of Directors on July 28, 2011. Compensation Committee Members12: Mario Resca (Chairman), Carlo Cesare Gatto, Roberto Petri and Alessandro Profumo. Established by the Board of Directors for the first time in 1996, this committee advises Board of Directors regarding the proposal for the remuneration of the Chairman and of the CEO, the remuneration policy of Directors with proxies and of the members of the Board’s committees and, on instructions from the CEO, regarding: (i) annual and long-term incentive plans; (ii) general criteria for the remuneration of executives with strategic responsibilities; (iii) objectives and results of the Performance and Incentive Plans; (iv) reports to the Board, at least once every six months, not later than the term for the approval of the Financial Statements and of the Interim Consolidated Financial Report, on the activity carried out; and (v) reports to the Shareholders’ Meeting called to approve the Financial Statements on the exercise of its functions, through the Chairman or another Committee member appointed by the former. It performs the tasks assigned by the Management System Guideline on “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, adopted in November 2010 by the Board of Directors pursuant to Consob regulation of March 12, 2010. The Board of Directors modified this Management System Guideline on January 19, 2012. During 2011, the Compensation Committee met six times, with an attendance rate: (i) of 92% of its members in the three meetings held until the expiring date of the previous Board of Directors (May 5, 2011); and (ii) of 100% of its members in the three meetings held after the appointment of the current Committee. During 2011, the main topics discussed by the Committee were: (i) evaluation of the attainment of Eni’s 2010 management objectives and definition of 2011 performance objectives for the purposes of variable Incentive Plans; (ii) establishment of the variable incentive plan of the Chairman, CEO and Directors based on the results achieved in 2010; (iii) establishment of the 2011 Deferred Monetary Incentive Plan and its assignment to the CEO; (iv) examination of possible extraordinary remuneration for the CEO and Chairman; (v) proposal, related to the new appointment of the Board, regarding the remuneration of the Directors with proxies and of non-executive Director for the participation in the Board’s Committees; (vi) the criteria of the remuneration policy for executives with strategic responsibilities; (vii) establishment of the 2011 Long-Term Monetary Incentive Plan for the CEO replacing the Eni Stock Option Plan; implementation of the 2011 Long-Term Monetary Incentive Plan for critical managerial resources; (viii) (ix) examination of the changes in regulation regarding compensation (consultation documents issued by Consob on October 10, 2011); and (x) adoption of the provisions of the Corporate Governance Code of Borsa Italiana (Italian Stock Exchange) and consequent update of the Compensation Committee’s regulations.. The composition and appointment, as well as tasks and procedural rules of the Committee are governed by a regulation approved by the Board of Directors on June 1, 2011, and then modified on December 15, 2011. Internal Control Committee Members13: Alessandro Lorenzi (Chairman), Carlo Cesare Gatto, Paolo Marchioni and Francesco Taranto. The Internal Control Committee, first established in Eni in 1994, is entrusted with providing consulting and advisory services to the Board of Directors as regards the internal control system. It is exclusively made up of nonexecutive and independent Directors who possess the necessary skills for the tasks they are required to perform14. The Committee reports to the Board of Directors both on its activities and on the adequacy of the internal control system, at least once every six months, not later than the term for the approval of the annual and half-year financial (12) Until May 5, 2011, the members of the Committee were: Mario Resca (Chairman), Alberto Clô, Paolo Andrea Colombo and Francesco Taranto. (13) Until May 5, 2011, the members of the Committee were Marco Reboa (Chairman), Francesco Taranto, Pierluigi Scibetta and Paolo Marchioni. (14) The Eni Code establishes that at least two members of the Committee – and not one as set forth in the corporate Governance Code of Borsa Italiana – must possess adequate experience on financial and accounting matters, as assessed by the Board of Directors at the time of their appointment. 158 statements. The periodic reports for the Board of Directors are drafted by the Committee by taking into account the opinions expressed – in their respective periodic reports – by the Officer in charge of preparing financial reports, the Officer in charge of Internal Control, the Eni Watch Structure and, in general, on the basis of the evidence acquired in carrying out its activities. In particular, the Internal Control Committee performs the following activities: (i) examining and assessing – with the Officer in charge of preparing financial reports and the Audit firm – the proper use of accounting principles and their homogeneity for the drafting of the annual and half-year financial statements; (ii) assisting, with consulting and advisory functions, the Board in defining the guidelines for the internal control system; (iii) providing an evaluation – upon request by the CEO – on specific aspects concerning the process used to identify the main risks related to the Company and its subsidiaries as well as on the planning, implementation and management of the internal control system; (iv) overseeing the activities of Internal Audit Department and of the Officer in charge of Internal Control and examining and eventually proposing observations and integrations for the proposal of the Audit plan and the annual budget of the Internal Audit Department as well as on potential changes during the year; (v) examining and assessing the following: (a) the information received from the Internal Audit Senior Executive Vice President as well as any evidence on related monitoring activities on improvement actions on internal control system; (b) the periodical reports on the outcomes of the monitoring activities conducted on the internal control system over financial reporting, on its adequacy and actual application, as well as the adequacy of the powers and means assigned to the Officer in charge of preparing financial reports; (c) communications and information received from the Board of Statutory Auditors and Statutory Auditors, also in reference to the outcomes of preliminary investigation conducted by the Internal Audit Department following reports received even if in anonymous form (whistleblowing); (d) evidence emerging from the reports and management letters submitted by the Audit firm; (e) periodical reports issued by Eni Watch Structure, also in its capacity as Guarantor of the Code of Ethics; (f) evidence emerging from the periodical reports submitted by the Officer in charge of preparing financial reports and by the Officer in Charge of internal control; and (g) information on the internal control system concerning the Company’s structure, also through periodical meetings with management, as well as enquiries and reviews carried out by third parties; (vi) performing other specific activities aimed at formulating analyses and opinions on topics falling under its competence and based on the Board’s requests for details; (vii) performing the tasks assigned by the “Model of internal control on financial reporting”; and (viii) performing the tasks assigned by the Management System Guideline on “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, adopted in November 2010 by Eni’s Board of Directors pursuant to Consob Regulation of March 12, 2010, on which the Internal Control Committee expressed its unanimous approval in its capacity as committee of independent Directors provided for by the mentioned regulation. In particular, the Committee provides an opinion on the interest of the Company in the completion of transactions with related parties, as well as on the convenience and substantial correctness of the underlying terms. Moreover, for transactions with related parties of greater importance, the Committee is involved in the preparatory stage of these transactions. The composition and appointment, as well as tasks and procedural rules of the Committee are governed by a regulation approved by the Board of Directors on June 1, 2011 which basically confirmed the previous regulation dated 2009. Nomination Committee Members: Giuseppe Recchi (Chairman), Alessandro Lorenzi, Alessandro Profumo and Mario Resca. On July 28, 2011, the Board of Directors of Eni established the Nomination Committee, chaired by the Chairman of the Board of Directors. The members of the Nomination Committee are all non-executive directors. The majority of them are independent in accordance with the recommendations of the Corporate Governance Code of Borsa Italiana. The Committee assists the Board of Directors with consulting and advisory functions. In particular the Committee: (a) assists the Board of Directors in formulating the criteria for the appointment of persons indicated in letter b) and of members of the other corporate boards and bodies of Eni’s investees; (b) provides evaluations to the Board of Directors on the appointment of executives and members of the corporate boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer, whose appointment falls under the Board of Directors’ responsibility and oversees the relative succession plans. Where possible and appropriate, in relation with the shareholders’ structure, the Committee proposes to the Board of Directors the succession plan concerning the Chief Executive Officer; (c) upon proposal of the Chief Executive Officer, examines and evaluates criteria for the succession plan of executives holding strategic responsibilities in the Company; (d) proposes to the Board of Directors candidates to the position of director in the event of vacation of one or more during the course of the financial year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements on the minimum number of independent directors and of the portion reserved for the less represented gender; (e) designates to the Board of Directors candidates to the position of director to be submitted to the Shareholders’ Meeting of the Company, taking into account any recommendation received from shareholders, in the event of impossibility to draw the expected number of directors form the lists presented by shareholders; (f) oversees the annual self assessment process on performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and taking into account the outcomes of the self assessment, expresses opinions to the Board of Directors regarding the size and composition of the same as well as, possibly, with regard to the professional skills whose presence within the Board 159 or within the Committees is considered appropriate; (g) proposes to the Board of Directors the list of candidates to the position of director, if the Board decides to avail itself of the faculty provided for in Article 17.3 of the By-law; (h) in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of offices as director or statutory auditor that may be considered compatible with the effective performance of the duties of director or statutory auditor of the Company, and conducts the regular checks and evaluations to be submitted to the Board of Directors; (i) provides the periodical investigation on the assessment of independence and integrity requirements of directors, as well as on the absence of situations of incompatibility or ineligibility of the directors; (j) expresses an opinion to the Board of Directors on any activities in competition with the activities of the Company eventually carried out by the directors; and (k) reports to the Board of Directors, at least once every six months, not later than the term for the approval of the Financial Statements and of the Interim Consolidated Financial Report, on the activity carried out, as well as on the adequacy of the nomination system. The composition, tasks and procedurals rules of the Nomination Committee are governed by a regulation approved by the Board of Directors on September 29, 2011. Board of Statutory Auditors In accordance with Italian legislation, as specified in Article 28 of Eni’s By-Laws, the Board of Statutory Auditors consists of five effective members (and two alternate) who must comply with specific independence, expertise and integrity requirements. The members of the Board of Statutory Auditors currently in office15 were elected by the Ordinary Shareholders’ Meeting held on May 5, 2011 for a three financial year term, until the Shareholders’ Meeting approval of Eni’s 2013 Financial Statements. Name Ugo Marinelli Roberto Ferranti Paolo Fumagalli Renato Righetti Giorgio Silva Francesco Bilotti Maurizio Lauri Position Chairman Auditor Auditor Auditor Auditor Alternate Auditor Alternate Auditor Year first appointed to Board of Statutory Auditors 2008 2008 2011 2011 2005 (1999 Alternate Auditor) 2005 2011 Roberto Ferranti, Paolo Fumagalli, Renato Righetti and Francesco Bilotti were candidates in the list presented by the Ministry of Economy and Finance; Ugo Marinelli, Giorgio Silva and Maurizio Lauri were candidates in the list presented by institutional investors. The Auditors are appointed by means of a slate voting system: the lists are presented by the shareholders representing at least 0.5% of the share capital. Two Statutory and one Alternate Auditors are selected among the candidates of the minority shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting among the Auditors elected by the minority shareholders. The Auditors must possess the specific requirements of independence as well as the requirements of professionalism and honorability which are provided for in the regulations of the Ministry of Justice. The By-laws specify that the professionalism requirements can also be fulfilled by work experiences of at least three years in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) executive position within the engineering and geological sectors. U.S. Regulations requires for Audit Committee that at least one member of the Board of Statutory Auditors shall be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting principles, preparation and auditing of financial statements and internal control processes. Pursuant to the Consolidated Law on Finance, the Board of Statutory Auditors monitors: (i) the compliance with the law and the Company’s By-laws; (ii) the observance of the principles of correct administration; (iii) the adequacy of the Company’s organizational structure for matters within the scope of the Board’s authority, the adequacy of the internal control system and the administrative and accounting system and the reliability of the latter in correctly representing the Company’s transactions; (iv) the arrangements for implementing the corporate governance rules (15) Until May 5, 2011 the member of Board of Statutory Auditors were: Ugo Marinelli (Chairman); Roberto Ferranti; Luigi Mandolesi; Tiziano Onesti; Giorgio Silva; Francesco Bilotti (Alternate Auditor) and Pietro Alberico Mazzola (Alternate Auditor). 160 provided for in the Corporate Governance Code of Borsa Italiana to which the Company adheres; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements. Moreover, pursuant to Article 19 of Legislative Decree No. 39/2010, the Board of Statutory Auditors in its role of “internal control and financial auditing committee” supervises the following: (a) the financial reporting process; (b) the efficacy of internal control, internal audit (where applicable) and risk management system; (c) the auditing of the annual financial statements and consolidated financial statements; and (d) the independence of the auditor or audit firms, in particular with regard to the provision of non-auditing services to the entity subject to financial auditing. The functions assigned by the Decree to the “internal control and financial auditing committee” are coherent with and essentially comply with the responsibilities already assigned to the Board of Statutory Auditors of Eni, above all in consideration of its role as Audit Committee pursuant to the U.S. regulation “Sarbanes - Oxley Act” (which shall be outlined in greater detail further on). As already set forth in the Consolidated Law on Finance and currently regulated by Article 13 of Decree No. 39/2010, the Board of Statutory Auditors formulates a grounded proposal to the Shareholders’ Meeting on the assignment of the role of financial auditor and the determination of the remuneration payable to the auditor. Furthermore, pursuant to Article 19, paragraph 1, letters c) and d) of the Legislative Decree No. 39/2010, the Board of Statutory Auditors supervises the auditing activities and, also in compliance with the provisions of Article 10.C.5. of Eni Code, the independence of the Audit firm, by verifying the compliance with all applicable regulations as well as the nature and entity of any services other than financial auditing services provided to Eni Group, directly or through companies belonging to its network. Results of the supervisory activity are included in the Report drawn up in accordance with Article 153 of the Consolidated Law on Finance, and attached to the financial statements. On March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, identified the Board of Statutory Auditors as the body that, since June 1, 2005, has carried out, within the limits set forth by Italian regulations, the functions assigned to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and by the SEC regulations. On June 15, 2005, the Board of Statutory Auditors approved the regulations concerning the fulfillment of the functions assigned pursuant to the above mentioned U.S. Regulations, the text of which is available on Eni’s website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by SEC rules are as follows: • • evaluating the proposals presented by the external auditors for their appointment and making its prompted recommendation to the Shareholders’ Meeting about the proposal for the appointment or the retention of the external auditor; performing the activities of oversight of the work of the external auditor engaged for the audit or performing other audit, review or attest services; • making recommendations to the Board of Directors on the resolution of disagreements between management • • • • • • and the auditor regarding financial reporting; approving the procedures for: (a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and (b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters; approving the procedures for the pre-approval of admissible non-audit services, analytically identified, and examine the information on the execution of the authorized services; evaluating any request to have recourse to the external auditor engaged for the audit for admissible non-audit services and expresses its opinion to the Board of Directors; examining the periodical communications from the external auditor relating to: (a) all critical accounting policies and practices to be used; (b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and (c) other material written communication between the external auditor and the management; examining complaints received by the CEO and the CFO concerning any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; examining complaints received by the CEO and the CFO concerning any fraud that involves management or other employees who have a significant role in the Company’s internal controls. The Board of Statutory Auditors, in the execution of its functions, is supported by Company’s departments, in particular the Internal Audit department and the Administrative and Financial Statement department. 161 Eni Watch Structure and Model 231 According to the Italian regulations pertaining to the “administrative liability of legal entities deriving from offences”, pursuant to Legislative Decree No. 231 of June 8, 2001 (hereinafter, “Legislative Decree No. 231 of 2001”), associations, including corporations, may be held liable – and therefore charged with the payment of a penalty or placed under injunction, with regard to certain offences that are attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in an high-ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these offences. With regards to this issue, Eni SpA’s Board of Directors – in its meetings of December 15, 2003 and January 28, 2004 – has approved an organizational, managerial and control model pursuant to Legislative Decree No. 231 of 2001 (“Model 231”) and has appointed the Eni Watch Structure. Moreover, after the updates of the Model 231 as a result of the changes of Italian legislation on the matter and of the company organizational structures, the Board of Director on March 14, 2008, adopted Eni’s Code of Ethics – replacing the previous version of 1998 – along with the Model 231 which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis: shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the Countries where Eni operates. The synergies between the Code of Ethics – an integral part and unwaivable general principle of Model 231 – and Model 231 were underlined by the assignment to Eni Watch Structure established by the Model 231 of the role of Guarantor of the Code of Ethics. The composition of the Eni Watch Structure, at the beginning composed by only three members, was amended in 2007 with the addition of two external members, one of them appointed Chairman of the Eni Watch Structure identified among academics, professionals of proved authority and expertise on economic and business management. The internal members include the managers in charge of the Legal Affairs, Human Resources and Organization and Internal Audit of the Company. On May 19, 2011, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure. Audit firm The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit firm whose appointment falls under the competency of the Shareholders’ Meeting, upon the Board of Statutory Auditors opinion. In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit firm issues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting. For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit firm. Moreover, Eni’s Audit firm, for the purpose of issuing an opinion on the consolidated financial statements, assumes the responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which represent altogether an irrelevant part of the company’s assets and consolidated turnover. Under Board of Statutory Auditors’ grounded proposal, the Shareholders’ Meeting of April 29, 2010 appointed Reconta Ernst & Young SpA for the financial years 2010-2018. Court of Auditors (“Corte dei conti”) The financial management accounts of Eni is subject to the control of the Court of Auditors (Italian “Corte dei conti”) in order to protect public finances. This task is carried out by the Judge of the Court of Auditors, Raffaele Squitieri (whose substitute is Amedeo Federici), on the basis of the resolution approved on October 27-28, 2009 by the Council of the Presidency of the Court of Auditors. The Court Judge attends the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Internal Control Committee. Employees As of December 31, 2011, Eni had a total of 78,686 employees, a decrease of 1,255 employees, or down 1.6% from December 31, 2010, which reflects a decrease of 451 employees working outside Italy and a decrease of 804 employees hired in Italy. 162 Employees hired in Italy were 33,170 (42.2% of all Group employees). During the year 2,671 persons left their job at Eni, of these 2,102 had an open-end contract and 569 a fixed-term contract. Declines were registered in all business Divisions due to efficiency actions. The process of improvement in the quality mix of employees continued in 2011 with the hiring of 1,957 persons, of which 634 had fixed-term contracts. A total of 1,323 persons were hired with open-ended and apprenticeship contracts, most of them with university qualifications (737 persons) and 586 persons with a high school diploma. Employees hired and working outside Italy were 45,516 (57.8% of all Group employees), a decrease of 3,334 persons. 2009 2010 2011 (units) Exploration & Production................................................................................................... Gas & Power........................................................................................................................ Refining & Marketing......................................................................................................... Petrochemicals..................................................................................................................... Engineering & Construction............................................................................................... Other activities .................................................................................................................... Corporate and financial companies.................................................................................... 8,166 6,068 10,271 10,276 10,425 11,404 11,245 10,907 7,591 8,022 5,804 5,972 35,969 38,826 38,561 880 4,518 968 4,872 939 4,661 77,718 79,941 78,686 163 The table below sets forth Eni’s employees as of December 31, 2009, 2010 and 2011 in Italy and outside Italy: Exploration & Production 2009 2010 2011 Italy....................................................... Outside Italy......................................... 3,883 6,388 (units) 3,906 6,370 3,797 6,628 10,271 10,276 10,425 Gas & Power Italy....................................................... Outside Italy......................................... 8,842 2,562 8,652 2,593 8,422 2,485 11,404 11,245 10,907 Refining & Marketing Italy....................................................... Outside Italy......................................... 6,467 1,699 6,162 1,860 5,790 1,801 8,166 8,022 7,591 Petrochemicals Italy....................................................... Outside Italy......................................... 5,045 1,023 4,903 1,069 4,750 1,054 6,068 5,972 5,804 Engineering & Construction Italy....................................................... 5,197 Outside Italy......................................... 30,795 33,911 33,364 5,174 4,915 Other activities Italy....................................................... Outside Italy......................................... 968 - 968 939 - 939 880 - 880 Corporate and financial companies Italy....................................................... Outside Italy......................................... 4,706 166 4,497 164 4,334 184 35,969 38,826 38,561 4,872 4,661 4,518 Total Total Italy....................................................... 35,085 33,974 33,170 Outside Italy......................................... 42,633 45,967 45,516 77,718 79,941 78,686 of which senior managers .............................................................. 1,562 1,574 1,586 164 Share Ownership As of February 29, 2012, the cumulative number of shares owned by Eni’s directors, statutory auditors and senior managers, including the three Chief Operating Officers, was 310,755 less than 0.1% of Eni’s share capital outstanding as of the same data. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The break-down of share ownership for each of those persons is provided below. Name Position Chairman ................................................................................... CEO and COO of Eni ................................................................ Director ...................................................................................... Director ...................................................................................... Director ...................................................................................... Director ...................................................................................... Board of Directors Giuseppe Recchi Paolo Scaroni Carlo Cesare Gatto Paolo Marchioni Mario Resca Francesco Taranto Chief Executive Officers Claudio Descalzi Domenico Dispenza (*) Angelo Fanelli Board of Statutory Auditors ................................................................................................................. Senior managers ..................................................................................................................... Chief Operating Officer of the E&P Division ........................ Chief Operating Officer of the G&P Division ........................ Chief Operating Officer of the R&M Division ....................... Number of shares owned Options granted 42,000 56,250 6,800 1,500 3,900 500 39,455 99,715 30,800 7,454 22,381 1,608,705 144,355 184,900 71,595 691,850 ________ (*) In charge until December 31, 2011. 165 Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS Major Shareholders As of March 19, 2012, the following persons were known by Eni to own more than 2% of any class of Eni SpA’s voting securities. At such date, the total amount of Eni SpA’s voting securities owned by these shareholders was: Title of class Number of shares owned Percent of class Ministry of Economy and Finance ...................................................... Cassa Depositi e Prestiti SpA (a) .......................................................... BNP Paribas Group............................................................................... 157,552,137 1,056,179,478 91,529,423 3.93 26.37 2.29 (b) ________ (a) (b) Cassa Depositi e Prestiti is an entity controlled by the same Ministry. With Decree of the Ministry of Economy and Finance of November 30, 2010, published in the Official Gazette No. 293 of December 16, 2010, a share trade in has been decided which entails, among other things, the transfer to Cassa Depositi e Prestiti SpA a total of 655,891,140 Eni’s ordinary shares held by the Ministry of Economy and Finance. According to said Decree, the transfer of shares has been finalized on December 21, 2010. Of which 0.42% refers to non-voting shares. The following mutual funds reported to hold more than 2% of Eni’s share capital: Blackrock Investment Inc for a total number of shares corresponding to 2.68% of Eni’s ordinary share capital. The Ministry of Economy and Finance, in agreement with the Ministry for Economic Development, retains certain special powers over Eni. See “Item 10 – Additional Information – Memorandum and Articles of Association – Limitations on changes in control of the Company (Special Power of the Italian State)”. As of March 19, 2012 there were 29,722,077 ADRs, each representing two Eni ordinary shares outstanding corresponding to approximately 1.6% of Eni’s share capital. See “Item 9 – The Offer and the Listing”. Related Party Transactions In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with non-consolidated subsidiaries and affiliates as well as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of Eni companies. Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – Note 42 to the Consolidated Financial Statements”. 166 Item 8. FINANCIAL INFORMATION Consolidated Statements and Other Financial Information See “Item 18 – Financial Statements”. Legal Proceedings Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements. For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – Note 34 to the Consolidated Financial Statements”. Dividends Eni’s dividend policy in future periods, and the sustainability of the current amount of dividends over the next four-year period, will depend upon a number of factors including future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the “Risk Factors” set out in Item 3. The parent Company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries. However, subject to such factors, under the Company’s scenario for Brent prices at 90-85 $/BBL over the next four years, management plans to grow the dividend in line with OECD inflation from 2011. If management assumptions on oil prices were to change, management may revise the dividend and reset the basis for progressive dividend increases. Management intends to propose to the Annual Shareholders’ Meeting scheduled on May 8, 2012, the distribution of a dividend of (cid:1)1.04 per share for fiscal year 2011, of which (cid:1)0.52 was already paid as interim dividend in September 2011. Total cash outlay for the 2011 dividend is expected at approximately (cid:1)3.8 billion (including the (cid:1)1.9 billion already paid in September 2011) in case the Annual Shareholders’ Meeting approves the annual dividend. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance to the full-year dividend to be paid in each following year. Significant Changes See “Item 5 – Recent Developments” for a discussion of significant events occurred after 2011 year end up to the latest practicable date. 167 Item 9. THE OFFER AND THE LISTING Offer and Listing Details The principal trading market for the ordinary shares of Eni SpA (“Eni”), nominal value (cid:1)1.00 each (the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (“Borsa Italiana”). Eni’s American Depositary Receipts (“ADRs”), each representing two Shares, are listed on the New York Stock Exchange. The ratio has changed from one ADR per five Shares to one ADR per two Shares, effective January 10, 2006. The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. Due to the ratio change, the historical prices of ADRs have been adjusted by an adjustment factor of 2.5. See “Item 3 – Key Information – Exchange Rates” regarding applicable exchange rates during the periods indicated below. MTA New York Stock Exchange High Low High Low ((cid:1) per share) (U.S. $ per ADR) 2007.......................................................................................................................... 28.330 22.760 78.290 60.220 2008.......................................................................................................................... 26.930 13.798 84.140 37.220 2009.......................................................................................................................... 18.350 12.300 54.450 31.070 2010.......................................................................................................................... 18.560 14.610 53.890 35.370 2011.......................................................................................................................... 18.420 12.170 53.740 32.980 2010 First quarter ............................................................................................................. 18.560 16.010 53.890 43.950 Second quarter ......................................................................................................... 17.800 14.610 48.550 35.370 Third quarter ............................................................................................................ 16.590 14.710 43.870 36.970 Fourth quarter .......................................................................................................... 16.670 15.350 46.950 40.320 2011 First quarter ............................................................................................................. 18.420 16.420 50.300 43.990 Second quarter ......................................................................................................... 18.050 15.580 53.740 44.040 Third quarter ............................................................................................................ 16.550 12.170 48.120 32.980 Fourth quarter .......................................................................................................... 16.670 12.950 47.420 33.790 2012 First quarter ............................................................................................................. 18.670 16.200 49.440 41.420 January 2012............................................................................................................ 17.280 16.200 44.900 41.420 February 2012.......................................................................................................... 17.570 17.080 47.110 44.920 March 2012 ............................................................................................................. 18.670 17.220 49.440 45.200 Until January 17, 2012 JPMorgan Chase Bank NA has functioned as depositary banking issuing ADRs pursuant to a deposit agreement among Eni, the depositary bank and the beneficial owners and registered holders from time of ADRs issued hereunder. Effective January 18, 2012, The Bank of New York Mellon (the “Depositary”) functions as depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) among Eni, the Depositary and the beneficial owners (“Beneficial Owners”) and registered holders from time to time of ADRs issued hereunder. As of March 19, 2012 there were 29,722,077 ADRs outstanding, representing 59,444,154 ordinary shares or approximately 1.6% of all Eni’s shares outstanding, held by 115 holders of record (including the Depository Trust Company) in the United States, 110 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere. The Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian stock market. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on MTA and seeks to replicate the broad sector weights of the Italian stock market. The constituents of the FTSE MIB are selected according to the following criteria: sector representation, market capitalization of free-float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for float. Since June 1, 2009 the FTSE MIB (previously S&P/MIB 168 Index) is the principal indicator used to track the performance of the Italian stock market and is the basis for future and option contracts traded in the Italian Derivatives Market (“IDEM”) managed by Borsa Italiana. The Shares are the first largest component of the FTSE MIB, with a weighting of approximately 15%, as established by FTSE after the quarterly rebalancing for FTSE MIB effective March 19, 2012. Trading in the MTA is allowed in any quantity of the Shares as well as other financial instruments. Where necessary, Borsa Italiana may specify a minimum lot for each financial instrument. Since March 28, 2000, a three-day rolling cash settlement has been applied to all trades of equity securities in Italy, instead of the previous five-day settlement. In addition, future and option contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Market (“SeDeX”). IDEM facilitates the trading of future and option contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated market where it is possible to trade securitized derivatives (covered warrants and certificates). Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session, and a “reference price”, calculated as the closing- auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective December 20, 2010: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall be the previous day’s reference price, in the opening auction, or the auction price, in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the “Guide to the Parameters”) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time. Markets The Commissione Nazionale per le Società e la Borsa (the National Commission for Companies and the Stock Exchange or “Consob”), is the public authority responsible for regulating and supervising the Italian securities markets to ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate regulated markets in Italy; it is responsible for the organization and management of the Italian stock exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets. According to Consob Regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which are MTA (shares, convertible bonds, pre-emptive rights, warrants and Funds), TAH (After Hours trading market), ETFplus (Exchange Traded Funds and Exchange Traded Commodities market), IDEM (index and stock derivatives market), SeDeX (covered warrants and certificates), MOT (bond market) and MIV (Investment Vehicles Market), as well as the admission to listing on and trading on these markets. According to EU Markets in Financial Instruments Directive (2004/39/EC) (“MiFID”) and Consob Regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (“MTF”s) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which deals on own account by executing client orders outside a Regulated Market or a MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana. According to Legislative Decree No. 58 of February 24, 1998 (“Decree No. 58”), the Consolidated Law on Financial Intermediation, the provision of investment services and activities to the public on a professional basis is reserved to banks and investment firms (“authorized persons”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be 169 responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. The Bank of Italy, in agreement with Consob, also regulates the operation of the clearing and settlement service for transactions involving financial instruments. The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it). The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it). 170 Item 10. ADDITIONAL INFORMATION Memorandum and Articles of Association Register office “Eni SpA” results from the privatization of Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953 and it is registered at the Rome Companies Register, with identification number (and Tax number) 00484960588, and Vat number 0090581106. The registered head office of the Company is located in Rome, Italy, and the Company has two secondary registered office in San Donato Milanese (MI). The full text of Eni’s By-laws is attached as an exhibit to this annual report (last amended on June 3, 2010 in compliance with the provisions of Legislative Decree No. 27/2010, which implemented in Italy the EU Shareholders’ Rights Directive – Directive 2007/36/EC – which has been applied from November 1, 2010). See “Exhibit 1”. Company objects and purpose According to Article 4 of Eni’s By-laws, Company’s objects include the direct and/or indirect exercise, through equity holdings in companies or other entities of: the activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided by the law; activities in the field of chemicals, nuclear fuels, geothermal, renewable energy sources and energy in general, in the design and construction of industrial plants in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water derivation, potabilization; purification and distribution and reuse; in the environmental protection sector and the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company manages the technical and financial co-ordination of subsidiaries and affiliated companies. Moreover, the Company may take shareholdings and interests in other companies or business with similar purposes, comparable or complementary to its own or those of its subsidiaries or affiliates, either in Italy or abroad, and it may provide collateral and/or personal guarantees for both its own and third-party commitments. Directors’ issues The Eni’s Board of Directors is invested with the fullest powers for ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the Company purpose, except for the acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one among its members. The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on the matters regarding major strategic, operational and organizational decisions. According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may at any time revoke the powers delegated hereon, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts to other among its members. According with Eni’s By-laws, the quorum for meeting of the Board shall be the majority of the Directors with voting rights. Resolutions shall be approved by a majority of the votes of the Directors with voting rights present; in the event of a tie, the person who chairs the meeting shall have a casting vote. Interests in Company’s transactions As provided by Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company’s transactions, he shall disclose it to the Board of Directors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with Consob Regulation on March 12, 2010, and 171 taking also into account recommendations established by Eni Code, the Board of Directors – on November 18, 201016 – approved unanimously the Management System Guidelines (MSG) “Transaction involving interests of directors and statutory auditors and transactions with related parties”, which has been applied from January 1, 2011 to ensure transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Internal Control Committee, composed entirely of independent directors under the Corporate Governance Code of Borsa Italiana SpA and in accordance with Consob Regulation. The MSG specifies commitments of monitoring, evaluation and motivation related to the preliminary phase and completion of a transaction with a subject of interest of directors or statutory auditors. In this regard, both in the preliminary and deliberation phase, is requested a detailed and documented examination of the reason of the operation, highlighting the interest of company in its completion and the convenience and fairness of underlying terms. Directors involved in matters subject to the Board resolution normally shall not participate in the correspondent discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction is under his jurisdiction, he shall in any case abstain from taking part in the transaction and shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Civil Code). In any case, if the operation is under the responsibility of the Board of Directors of Eni, it is provided for a non-binding opinion from the Internal Control Committee. Moreover, to ensure compliance with the investigation and resolution procedures envisaged by the MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any variation, in which they illustrate their potential interests related to Eni and its subsidiaries, and in any case they inform the CEO (or the Chairman, in the case of interests on the part of the CEO) of the single Transactions that Eni intends to carry out and in which they have an interest; the CEO (or Chairman) will then inform the other Directors and the Board of Statutory Auditors. Compensation Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian civil law, while compensation of Directors invested with particular tasks in accordance with the By-laws (such as the Board Chairman and the CEO), or for participation in Board Committees, shall be determined by the Board of Directors, upon proposal of the Compensation Committee after consultation with the Board of Statutory Auditors (for more details about compensation policy in 2011, see “Item 6 – Compensation”). Borrowing powers Borrowing powers are included in the Company purpose. Moreover, according to the Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrant in compliance with the provisions of the law. Retirement and shareholdings There are no provisions in the By-laws relating to both the retirement based on age-limit requirements and the number of shares required for director’s qualification. Company’s shares According to Article 5 of the By-laws, the Company’s share capital amounts to (cid:1)4,005,358,876, fully-paid, and is represented by 4,005,358,876 ordinary nominative shares with a nominal value of (cid:1)1 (one) each. As required by Italian legislation on dematerialization of financial instruments, Eni’s shares must be held with “Monte Titoli SpA” (the Italian Central Depository for financial instrument) and their beneficial owners may exercise their rights through special deposit accounts opened with authorized intermediaries, such as banks, brokers and securities dealers. Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, also through proxy or correspondence. Moreover, according to Article 9 of the By-laws, the Shareholders’ Meeting might resolve to increase the Company capital by issuing shares, including shares of different classes, to be assigned for no consideration to Eni’s employees, pursuant to Article 2349 of the Italian Civil Code. This faculty has not been exercised. In 1995, Eni established a sponsored ADR (American Depositary Receipts) program directed to U.S. investors. (16) The Board of Directors modified this Management System Guideline on January 19, 2012. 172 Each of Eni’s ADR is equal to two of Eni’s ordinary shares; Eni’s ADR are listed on the New York Stock Exchange. Dividend rights Shareholders have the right to participate in profits and any other right as provided by the law and subject to any applicable legal limitations: in particular, the ordinary Shareholders’ Meeting called for the approval of the annual financial statements may allocate the net income resulting after the allotment to the legal reserve, to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors has the faculty, as allowed by the By-laws, to pay interim dividends to the shareholders. Dividends not collected within five years from the day in which they are payable will be prescribed in favor of the Company and allocated to reserves. Voting rights The general provisions on the shares’ “voting rights” are described at the point 6 below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see Item 6), Eni’s By-laws provide a voting list system. In particular, pursuant to Article 17 of the By-laws and according to the applicable law, lists may be presented both by shareholders, either individually or jointly with others, representing at least 1% of the share capital, or any other threshold established by Consob (the public authority responsible for regulating the Italian securities market) in its regulation, or by the Board of Directors. Each shareholder may present or contribute towards presenting, and vote for, a single list. There are no provisions in Eni’s By-laws relating to: rights to share in the Company’s profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company. Liquidation rights In case of liquidation of the Company, the Shareholders’ Meeting shall decide the manner of its liquidation and would appoint one or more liquidators and determine their powers and remuneration. According to the Italian Law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to the nominal value of their shares, only after payments of all Company’s liabilities and satisfaction of all other creditors. Change in shareholders’ rights To change the shareholders’ rights it is necessary a shareholders’ resolution. In case of any modification of the By-laws provisions relating to, among others, voting and dividend rights, resolved by the Shareholders’ Meeting, with the attendance and decision quorum established by the law for extraordinary meetings, shareholders are entitled with a withdrawal right, provided by the Italian Law. Shareholders’ Meeting The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. Resolutions of ordinary and extraordinary Shareholders’ Meetings in first, second or third call must be approved with the quorum and voting majorities provided for by the law in each case. The Board of Directors may, if it is deemed necessary, determine that both the ordinary and the extraordinary Shareholders’ Meeting shall be called for only one date, with the quorum and voting majorities provided for by the law. Shareholders’ Meetings are usually held at the Company’s registered office, unless otherwise resolved by the Board of Directors, provided however they are held in Italy. A Shareholders’ Meeting shall be called by way of notice published on the Company’s website, as well as in the ways specified by Consob in its regulation, by the statutory deadlines and in accordance with the applicable law. The call notice, which content is defined by the law and Eni’s By-laws, contains all the information to attend and to vote at the meeting including, information on proxy voting and vote by correspondence (the information is also available on the Company’s website). In the same manner and within the same deadline for publishing the notice calling the meeting, unless otherwise specified by the regulations, the Board of Directors issues a report on the meeting’s agenda. 173 An ordinary Shareholders’ Meeting shall be is called at least once a year, within 180 days of the end of the Company financial year (on December 31), to approve the financial statements, since as the Company is required to draw up consolidated financial statements. Entitlement to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances recorded at the end of the seventh trading day prior to the date of the Shareholders’ Meeting at first or single call. Credit and debit records entered on accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise of voting rights at the Shareholders’ Meeting. The statement issued by the authorized intermediary must be received by the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting on first or single call, or any other deadline established by Consob regulation issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy (or in electronic form where this is provided for in specific regulations) and in the manner set forth therein. In this latter case, electronic notification of the proxy may be made through a special section of the Company’s website as indicated in the notice calling the meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders associations that meet applicable statutory requirements, locations for communications and collecting proxies shall be made available to said associations in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations. The right to vote may also be exercised by correspondence according to the applicable provisions of laws and regulations. If envisaged in the notice calling the meeting, those persons entitled to vote may attend the Shareholders’ Meeting by means of telecommunication systems, and exercise their right to vote by electronic means, in accordance with the provisions of the law, the applicable regulations and the Shareholders’ Meeting Rules. The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda as provided by the law and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting on first or single call. Such proxy shall not be valid for items in respect of which no voting instructions have been provided. The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting. The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved with a resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient development of meetings and the right of each shareholder to express his/her opinion on the items on the agenda. The Board of Directors shall make a report on the items on the agenda available to the public at the Company’s registered office, on the Company’s website and in any other manner established in Consob regulations at the deadline for publication of the notice calling the Shareholders’ Meeting. During Shareholders’ Meetings, the Board of Directors provides wide disclosure on items examined and shareholders can require information on issues in the agenda. Information is provided taking into account of applicable rules on inside information. Stock ownership limitation and voting rights restrictions There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign people to hold shares or vote other than the limitations described below (which are equally applicable to residents and non-residents in Italy). In accordance with Article 6 of the By-laws, and applying the special rules pursuant to Article 3 of Law Decree 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), under no circumstances may any party own shares in the Company which constitute a direct or indirect shareholding more than 3% of the Company’s share capital. Exceeding this limit results in a ban on exercising the voting rights and other rights, except for the right to participate in profits, related to any shareholding that exceeds the limit. Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of Economy and Finance, public entities or organization controlled by them are exempt from this ban. Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors. 174 Limitation on changes in control of the Company (Special Powers of the Italian State) Pursuant to Article 6.2 of the By-laws and to the special rules set out in Law No. 474/1994, the Ministry of Economy and Finance, in agreement with the Ministry for Economic Development, holds special powers that can be exercised in accordance with the criteria set out in the Decree issued by the President of the Council of Ministers on June 10, 2004. These special powers are briefly the following: (a) objection to the purchase, by parties who are subject to the shareholding limit, of significant shareholdings, i.e. shareholdings that represent at least 3% of the share capital and consist of shares with the right to vote in ordinary Shareholders’ Meetings. The objection, duly justified, must be expressed if the transaction is deemed to be prejudicial to the vital interests of the State, within ten days of the date of the notification which Directors are required to send when a request is made for registration in the register of shareholders. During the period of time allowed for the right of objection to be exercised, the voting rights and other rights, except for the right to participate in profits, connected with the shares that represent the significant shareholding remain suspended. In the event of the right of objection being exercised, by means of a duly justified decision based on the actual prejudicial effect caused by the transaction to the vital interests of the State, the assignee will be forbidden from exercising its voting rights and any rights other than property rights connected with the shares that represent the significant shareholding, and will be required to assign these same shares within one year. In the event of a failure to comply, the Court, at the request of the Ministry of Economy and Finance, will order the sale of the shares representing the significant shareholding according to the procedures set out in Article 2359-ter of the Civil Code; (b) objection to the signing of agreements, as defined in Article 122 of the Consolidated Law on Finance, in the event that at least 3% of the share capital consisting of shares with the right to vote in ordinary Shareholders’ Meetings is represented in the agreements. For the purpose of allowing the right of objection to be exercised, Consob will inform the Ministry of Economy and Finance of any significant agreements of which it has been notified under the terms of the afore mentioned Article 122 of the Consolidated Law on Finance. The right of objection must be exercised within ten days of the date of Consob’s notification. During the period of time allowed for the right of objection to be exercised, the voting rights and any rights other than property rights of the shareholders signing up to the agreement are suspended. If an objection decision is issued with due justification detailing the actual prejudicial effect of the aforesaid agreements to the vital interests of the State, the agreement will be null and void. If the conduct during the Shareholders’ Meeting of the shareholders bound by the agreement reveals that the undertakings given under an agreement pursuant to the aforesaid Article 122 of the Consolidated Law on Finance have been maintained, any resolutions passed with the casting vote of these same shareholders may be challenged; (c) veto power, if duly justified by an actual prejudicial effect to the vital interests of the State, of resolutions to dissolve the Company, transfer the Company, merge, demerge, transfer the registered office overseas, change the Company purpose, amend the By-laws in a way that withdraws or modifies the powers detailed in letters (a), (b), (c) and the subsequent letter (d); and (d) appointment of a Director with no right to vote in Board meetings. Decisions to exercise the powers detailed in letters (a), (b) and (c) may be challenged, within sixty days, by the parties entitled to do so, before the Regional Administrative Court of Lazio. The special powers shall be exercisable with regard to significant and binding cases of general interest (public order, public security, public health and defense) in an appropriate way and measure and proportionally to the safeguarding of these interests, even by means of necessary time limits, without prejudice to compliance with the national and European principles, and in particular with the non-discrimination principle. The Italian Decree issued by the President of the Council of Ministers on May 20, 2010, after some decisions of the European Court of Justice, repealed Article 1, paragraph 2 of the Decree issued by the President of the Council of Ministers on June 10, 2004, related to the specific circumstances in which the special powers may be exercised. On March 15, 2012, the Law Decree No. 21/2012 on “Provisions regarding special powers on companies in defense and national security areas and for activities of strategic importance in energy, transport and communications areas” was published in the Italian Official Gazette. The Law Decree is in force, but subject to conversion into Law within 60 days. The Decree, issued to comply with the European Commission prescriptions, provides for the repeal of the present special powers (set out in the Law No. 474/1994), when the national strategic assets are identified by the Government. The new special powers of the Government include a veto power and the authority to impose specific conditions on the direct and/or indirect disposal of such assets, on the basis of objective and non discriminatory criteria. In order to “promote privatization and the spread of investment in shares” of companies in which the State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and 175 extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain such any provision. Shareholder ownership thresholds There are no By-laws provisions governing the disclosure of the ownership threshold because the matter is regulated by the Italian law. Under Consolidated Law on Finance17 and Consob Regulation18, any direct or indirect holding in the voting shares of a listed issuer in excess of 2%19, 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, 50%, 66.6%, 75%, 90% and 95% must be promptly disclosed to the investee company and to Consob. The same disclosure requirements refer to holdings which fall below one of the specified threshold. Due declarations shall be made within five trading days of the date of the transaction triggering the obligation to notify, regardless of the date on which it is to take effect, using the specific forms attached to the above mentioned Regulation. The relevant thresholds noted above shall be calculated including: (i) shares owned by the reporting person, even if the voting rights belong or are assigned to third parties, or are suspended, as well as shares of which the voting rights belong or are assigned to him; and (ii) shares held through third parties (and shares whose voting rights are assigned to such third parties) such as nominees, trustees or subsidiary companies. The obligation to notify also applies to any direct or indirect participation owned through ADRs. Specific disclosure requirements (with partially different thresholds), are connected to the so-called “potential holdings” (such as holdings of derivatives or other equity-linked securities). Voting rights attached to listed shares which have not been notified pursuant the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in Court, under the Civil Code, by shareholders or by Consob itself. The Consolidated Law on Finance regulates additional cross-ownership matters as follows. Cross-ownership between listed and non-listed companies may not exceed 2% of the shares of the listed company or 10% of the shares of the non-listed company (applying, for calculating these ownership thresholds, the same rules established for holdings in listed companies). The company that last exceed the limit of 2% or 10% interest in a listed or unlisted company respectively, may not exercise the voting rights on the shares held in excess of such thresholds and must sell such shares within the following 12 months. In the event of failure to make the disposal within such time limit, the suspension of voting rights shall apply to the entire shareholding, and any resolution or act adopted with the contribution of relevant shares, could be challenged under the Civil Code. If anyone holds an interest exceeding 2% of the share capital of a listed company, such listed company or any entity controlling such listed company may not acquire an interest exceeding 2% of the share capital of a listed company controlled by said holder. If the foregoing limit is exceeded, the holder who last exceeded the foregoing limit (or both the holders, if it is not possible to ascertain which holder exceeded such limit last) may not exercise the voting right related to the shares exceeding the foregoing limit. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended and any resolution or act adopted with the contribution of relevant shares could be challenged under the Italian Civil Code. Described limitations are not applicable in case of a takeover bid or exchange tender offer for acquiring at least 60% of the ordinary shares of a listed company. Under the same Consolidated Law on Finance, any agreement, in whatever form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed in the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights connected to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares could be challenged under the Italian Civil Code. The same provisions also apply to agreements, in whatever form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe for them; (c) provide for the purchase of the shares or of above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis) which aim to encourage or frustrate a takeover bid or equity swap, including commitments relating to non-participation in a takeover bid. Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122. (17) (18) Article 117 of Consob Decision No. 11971/1999 and subsequently amendments. (19) Moreover, based on reasoned investor protection and/or market efficiency aims, Consob is entitled to fix the first relevant threshold to a measure lower than 2%, by its decree (as provided for Law Decree No. 5 of February 2, 2009, converted into Law No. 33 of April 9, 2009). This faculty may be exercised only for definite period of time, with regard to public companies with high capitalization level. 176 Moreover, under the Italian Civil Code (Article 2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed a fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries. Finally, in accordance with Law No. 287 of October 10, 1990, any merger or acquisition of sole or joint control over a company that would create or strengthen a dominant position in the domestic market in a manner that eliminates or significantly reduces competition is prohibited and mergers and acquisition of specified dimension must be subject to preventive authorization of Italian Antitrust Authority20. However, if the acquiring party and the company to be acquired operate in more than one EU member state and together exceed certain revenue thresholds, the antitrust approval of the acquisition falls within the exclusive jurisdiction of the European Commission. Changes in share capital Eni’s By-laws do not provide for more stringent conditions than is required by the law. Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. According to Italian law, shareholders have a pre-emptive right to subscribe for new issues of shares and corporate bonds convertible into shares in proportion to their respective shareholdings. Subject to definite conditions, designated to prevent reduction of (actual) shareholders rights, and to preserve the Company’s interest, the preemptive right may be waived or limited by a shareholders’ resolution at an extraordinary Shareholders’ Meeting with the consent of more than 50% of the shares outstanding. The shareholders’ pre-emptive right is also waived by the law, in case of contributions in-kind. Material Contracts None. Exchange Controls There are no exchange controls in Italy. Residents and non-residents in Italy may effect any investments, divestments and other transactions that entail a transfer of assets to or from Italy, subject only to the reporting, record- keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions. Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of (cid:1)12.5 thousand be reported in writing to the Relevant Authority (Ministry for Economy and Finance) by residents or non-residents that effect such transfers directly, or by banks, securities dealers or Poste Italiane SpA (Italian Mail) that effect such transactions on their behalf. In addition, banks, securities dealers or Poste Italiane SpA effecting such transactions on behalf of residents or non-residents of Italy are required to maintain records of such transactions for five years, which records may be inspected at any time by Italian tax and judicial authorities. Non-compliance with these reporting and record-keeping requirements may result in administrative fines or, in the case of false reporting and in certain cases of incomplete reporting, criminal penalties. Italian Authorities will maintain reports for a period of ten years and may use them, directly or through other government offices, to police money laundering, tax evasion and any other crime or violation. (20) Autorità garante per la concorrenza ed il mercato (AGCM - www.agcm.it). 177 Taxation The information set forth below is a summary only, and Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction. Italian Taxation The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs. Income tax Dividends received by Italian resident individuals in relation to interest exceeding 2% of the voting rights or 5% of the share capital (“substantial interest”) are included in the taxable income subject to personal income tax to the extent of 49.72% of their amount. Personal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals in relation to non substantial interest not related to the conduct of a business are subject to a substitute tax of 20% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return. If the non-substantial interest is related to the conduct of a business, dividends received in respect of 2011 profits are included in the taxable business income to the extent of 49.72% of their amount. Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to un-distributed profit of 2007 and previous years. Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into law July 25, 1956, No. 786, and società di investimento a capitale variabile (“SICAV”) are not subject to substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the Dividends. A withholding tax of 20% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares. Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units. Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to an 11% substitute tax. Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 20%, provided that the interest is not connected to an Italian permanent establishment. Up to one fourth of the substitute tax withheld might be recovered by the non-resident shareholder from the Italian Tax Authorities upon provision of evidence of full payment of income tax on such dividend in his/her country of residence in an amount at least equal to the total refund claimed. Dividends are subject to the 1.375% substitute tax introduced by Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union member state or in Norway. The substitute tax may also be reduced under the tax treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income tax treaties with approximately 70 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that tax treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust. In order to obtain the treaty benefit (reduced substitute tax rate) at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for 178 the applicability of the treaty benefit, together with a certification issued by the foreign Tax Authorities stating that the shareholder is a resident of that country for treaty purposes. Under the tax treaty between the United States and Italy, dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy- U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 20%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the “IRS”) with respect to each dividend payment. The request for that certificate must include a statement, signed under penalties for perjury, to the effect that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks. Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 20%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (“treaty refund”) between the domestic rate and the treaty one by filing specific forms (certificate) with the Italian Tax Authorities. As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the ADSs, such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of Shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or tax treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith. Capital gains tax This paragraph applies with respect to capital gains out of the scope of a business activity carried out in Italy. Gains realized by Italian resident individuals upon the sale of substantial interest is included in the taxable base subject to personal income tax to the extent of 49.72% of their amount, while gains realized upon the sale of non-substantial interest is subject to a substitute tax at a 20% rate. For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return: • • the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (20%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 20% substitute tax to be applied by the portfolio. Gains realized by non-residents from non substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax. On the contrary, gains realized by non-residents from substantial interest even in listed companies are deemed to be realized in Italy and consequently they are subject to the capital gains tax. 179 However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non- taxability pursuant to the convention have been satisfied. Inheritance and gift tax Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006 effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows: (a) 4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding (cid:1)1,000,000 (per beneficiary); (b) 6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding (cid:1)100,000 (per beneficiary); (c) 6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity as well as to persons related by collateral affinity up to the third degree; and (d) 8 per cent: in all other cases. If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding (cid:1)1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place. United States Taxation The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to address all material tax consequences of the ownership of Shares or ADSs. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of Eni SpA’s Shares, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar. This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the “Code”), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs. If a partnership holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs. As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust. The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the income tax convention between the United States and Italy with their advisors and to discuss with their advisors any possible consequences of their failure to qualify for such benefits. 180 In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADRs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax. Dividends Subject to the passive foreign investment company, or PFIC, rules discussed below, distributions paid on the shares generally will be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian tax Authorities. If you are a noncorporate U.S. Holder, dividends paid to you in taxable years beginning before January 1, 2013 that constitute qualified dividend income will be taxable to you at a maximum tax rate of 15% provided that you hold the Shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends we pay with respect to the Shares or ADSs generally will be qualified dividend income. The amount of the dividend distribution that you must include in your income as a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot euro/U.S. dollar rate on the date the dividend distribution is includible in your income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date you include the dividend payment in income to the date you convert the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the maximum 15% tax rate. To the extent a refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that is refundable will not be eligible for credit against your U.S. federal income tax liability. See “Italian Taxation – Income Tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the shares will be income from sources outside the United States and will, depending on your circumstances, be either “passive” or “general” income for purposes of computing the foreign tax credit allowable to you. Sale or exchange of shares Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined at the spot rate on the date of disposition). Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a noncorporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes. PFIC rules Eni SpA believes that Shares and ADSs should not be treated as stock of a PFIC for U.S. federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if you are a U.S. Holder, you would be treated as if you had realized such gain and certain “excess distributions” ratably over your holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, your Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during your holding period in your Shares or ADSs. Dividends that you receive from Eni SpA will not be eligible for the special tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to you either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income. 181 Documents on Display Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at: http://www.eni.com/en_IT/documentation/documentation.page?type=bilrap&header=documentazione&doc_from=hpen i_header. The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Eni files its annual report on Form 20-F and other related documents with the SEC. It’s possible to read and copy documents that have been filed with the SEC at the SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA. You may also call the SEC at +1 800-SEC-0330 or log on to www.sec.gov. It is also possible to read and copy documents referred to in this annual report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17th floor, New York, USA. 182 Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the euro/US$ exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil and gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity. The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operations depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the euro/US$ exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa. As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, trading activities and risk management as well as, from time to time, to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil and gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives. Due to a changed competitive environment in the European gas market and also considering the development of highly liquid spot markets for gas and volatile gas margins, management has implemented through 2011 new risk management policies and instruments to safeguard the value of the Company’s assets in the gas value chain and to seek to profit from market and trading opportunities. As part of its risk management strategy, the Company actively manages exposure to the commodity risk by entering into commodity derivatives transactions on both financial and physical trading venues targeting different objectives. (i) On one hand, management enters commodity derivative transactions 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. Management has been implementing tight correlation between such commodity derivatives transactions and underlying physical contracts in order to account for those derivatives in accordance with hedging accounting in compliance with IAS 39, where possible; (ii) on the other hand, management plans to enter purchase/sale commodity contracts for speculative purposes in order to alter the risk profile associated with a portfolio of assets (purchase contracts, transport entitlements, storage capacity) or leverage any price 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 future trends in prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives will be accounted through profit and loss, resulting in higher volatility in the gas business’ operating profit. These trading activities are executed 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 them. This can be achieved through strategies of dynamic forward trading where the underlying items are represented by the Company’s assets. We believe that the risk associated with asset backed trading activities is mitigated by the natural hedge granted by the assets’ availability. We are planning to execute this activity both in the Gas & Power and the Refining & Marketing businesses. Please refer to “Item 18 – Note 34 to the Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to “Item 18 – Notes No. 13, 20, 25 and 30 to the Consolidated Financial Statements” for details of the different derivatives owned by the Company in these markets. 183 Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES Item 12A. Debt Securities Not applicable. Item 12B. Warrants and Rights Not applicable. Item 12C. Other Securities Not applicable. Item 12D. American Depositary Shares In the United States, Eni’s securities are traded in the form of ADSs (American Depositary Shares) which are listed on the New York Stock Exchange. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Since January the 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, PO Box 358516 Pittsburgh, PA 15252-8516, as depositary (the “Depositary”) under the Deposit Agreement between Eni, the Depositary and the holders of ADRs. Bank of New York Mellon is also the transfer agent for Eni’s ADRs. Société Générale Securities Services SpA and UniCredit SpA are the custodians (the “Custodian”) on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy. Fees and charges paid by ADR holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. 184 The table below sets forth all fees and charges that a holder of Eni’s ADRs may have to pay, either directly or indirectly, to Bank of New York Mellon, as Depositary. Type of service Amount of fees or charges (1) Depositary Actions (a) Depositing or substituting the underlying shares U.S. $ 5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) (b) Selling or exercising rights U.S. $ 5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of: • Share distributions, stock split, rights, merger. • Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities. Distribution or sale of securities, the fee being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities. (c) Withdrawing an underlying security U.S. $ 5.00 (or less) for each 100 ADSs (or portion of 100 ADSs) Acceptance of ADRs surrendered for withdrawal of deposited securities. (d) Transferring, splitting or grouping Registration or transfer fees Transfers, combining or grouping of depositary receipts. receipts (e) Expenses of the depositary Varied charges Expenses incurred on behalf of holders in connection with: • The depositary’s or its custodian’s compliance with applicable law, rule or regulation. • Stock transfer or other taxes and other governmental charges. • Cable, telex, facsimile transmission/delivery. • Expenses of the depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency). • Any other charge payable by Depositary or its agents. (f) Distribution of cash U.S. $ 0.02 (or less) per ADS Any cash distribution to ADS registered holders. (g) Depositary services ________ U.S. $ 0.02 (or less) per ADS per calendar year Depositary services. (1) All fees and charges are paid by ADR holders to Bank of New York Mellon as Depositary and Transfer agent. Fees and payments made by the Depositary to the issuer The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the New York Stock Exchange. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities. For the year 2011, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments, the Depositary will reimburse to Eni up to U.S. $900,000 in connection with above mentioned expenditures. Expenses waived or paid directly to third parties by the Depositary There are no agreements whereby the Depositary has agreed to waive Eni for any fees associated with the administration of the ADRs Program or other services thereof, nor to directly pay fees to third-parties. 185 Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES PART II None. Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS None. Item 15. CONTROLS AND PROCEDURES Disclosure controls and procedures In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries. The Company’s management, with the participation of the principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the principal executive officer and principal financial officer have concluded that these disclosure controls and procedures are effective. Management’s Annual Report on Internal Control over Financial Reporting The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time. The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system. The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2011. The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, has been audited by Reconta Ernst & Young SpA, an independent registered public accounting firm, as stated in its report that is included on pages F-1 and F-2 of this Annual Report on Form 20-F. 186 Changes in Internal Control over Financial Reporting There have not been changes in the Company’s internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 16A. Board of Statutory Auditors Financial Expert Eni’s Board of Statutory Auditors has determined that five members of Eni’s Board of Statutory Auditors, qualify as “audit committee financial expert”, as defined in Item 16A of Form 20-F. These five members are: Ugo Marinelli, who is the Chairman of the Board, and Roberto Ferranti, Paolo Fumagalli, Renato Righetti and Giorgio Silva. All members are independent. Item 16B. Code of Ethics Eni adopted a code of ethics that applies to all Eni’s employees including Eni’s principal executive officer, principal financial officer and principal accounting officer. Eni published its code of ethics on Eni’s website. It is accessible at www.eni.com, under the section Sustainability – Corporate Governance and Corporate Ethics – Code of Ethics. A copy of this code of ethics is included as an exhibit to this Annual Report on Form 20-F. Eni’s code of ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model. Item 16C. Principal Accountant Fees and Services Reconta Ernst & Young SpA has served as Eni’s principal independent public auditor for fiscal years 2011 and 2010 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F. The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services provided by Eni to its public auditors Reconta Ernst & Young SpA and its respective member firms, for the years ended December 31, 2011 and 2010, respectively: Audit fees................................................................................................................................ Audit-related fees ................................................................................................................... Tax fees................................................................................................................................... All other fees .......................................................................................................................... Total ....................................................................................................................................... Year ended December 31, 2010 2011 ((cid:1) thousand) 21,114 183 166 - 21,463 22,407 1,034 26 - 23,467 Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting. Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due 187 diligence, audit and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards. Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities. All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations. Pre-approval policies and procedures of the Internal Control Committee The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities within the Eni Group which are either controlled or jointly-controlled (directly or indirectly) by Eni SpA. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s internal audit department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The internal audit department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors. During 2011, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (c) of Rule 2-01 of Regulation S-X. Item 16D. Exemptions from the Listing Standards for Audit Committees Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, is performing the functions required by the SEC rules and the Sarbanes-Oxley Act to be performed by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 – Board of Statutory Auditors” above). Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers The Issuer and its affiliated purchasers have not executed any purchase of equity securities of the issuer since the beginning of 2009 up as of the date of the 20-F filing for the year ended December 31, 2011. All relevant authorizations previously granted by the General Shareholders’ Meeting to the Company management have expired to execute any purchase of equity securities. As of December 31, 2011, Eni’s treasury shares in portfolio amounted to No. 382,654,833 (nominal value (cid:1)1 each) corresponding to 9.55% of share capital of Eni, for a total book value of (cid:1)6,753 million. The decrease of No. 208,900 shares held in treasury from December 31, 2010 (No. 382,863,733 share) related to the sale of shares following the 2003 and 2004 stock option plans. Item 16F. Change in Registrant’s Certifying Accountant Not applicable. 188 Item 16G. Significant Differences in Corporate Governance Practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual Corporate governance. Eni’s governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model which provides for the Board of Directors as the sole corporate body responsible for management and for the establishment of an Audit Committee within the same Board, for monitoring activities. Below a description of the most significant differences between corporate governance practices followed by U.S. domestic companies under the NYSE standards and those followed by Eni, also with reference to Corporate Governance Code promoted by Borsa Italiana (hereafter Borsa Italiana Code) to whom Eni adheres. Independent Directors NYSE standards. Under NYSE standards listed U.S. companies’ Boards must have a majority of independent directors. A director qualifies as independent when the Board affirmatively determines that such director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a director may not be deemed independent if he/she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he/she is an employee of the issuer or a partner of the auditor). In addition, a director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a director’s independence. Eni standards. In Italy, the Consolidated Law on Finance states that at least one member, or two members if the Board is composed by more than seven members, must possess the independence requirements provided for Statutory Auditors of listed companies. In particular, a director may not be deemed independent if he/she or an immediate family member has relationships with the issuer that could influence their autonomous judgment, with its directors or with the companies in the same group of the issuer. Eni’s By-laws increases the number and states that at least one member, if the Board is made up by up to five members, or three Board members, in case the Board is made up by more than five members, shall have the independence requirement. Eni’s Code foresees further independence requirements, in line with the ones provided by the Borsa Italiana Code, that recommends that the Board of Directors includes an adequate number of independent non-executive directors; independence is defined as not being currently or recently involved in any relationship – either directly or indirectly – with the issuer or other parties associated with the issuer and which may influence his/her independent judgment. In accordance with Eni’s By-laws, the Board of Directors, at the time of its appointment by the Shareholders’ Meeting and then from time to time assess the independence of directors, reporting on this assessment in the Annual Corporate Governance Report. Eni’s Code also requires that the Board of Statutory Auditors verifies the correct application of criteria and procedures adopted by the Board of Directors to evaluate the independence of its members. The results of the assessments of the Board shall be communicated to the market. In accordance with Eni’s By-laws, should the independence requirements be impaired or cease or the minimum number of independent directors diminish below the threshold set by Eni’s By-laws, the Board declares the termination of office of the member lacking said requirements and provides for his substitution. Board members are expected to inform the Company in case they lose their independence requirements or of any reasons for ineligibility or incompatibility that might arise. Meetings of non Executive Directors NYSE standards. Non-executive directors, including those who are not independent, must meet on regularly basis in the absence of management. 189 In addition, if the group of non-executive directors includes directors who are not independent, independent directors should meet separately at least once a year. Eni standards. Eni’s Code allows independent Directors to decide whether to meet in the absence of the other Directors for discussion of issues deemed relevant to the functioning of the Board. This provision allowing such meetings to take place was requested by the independent Directors themselves, in order to have greater flexibility, to deal with actual requirements. During 2011, the independent Directors, in consideration of the frequency of the Board meetings, had numerous opportunities to meet, holding formal and informal meetings to hold discussions and exchange opinions. Audit Committee NYSE standards. Listed U.S. companies must have an audit committee that satisfies the requirements of Rule 10A- 3 under the Securities Exchange Act of 1934 and that complies with the further provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual. Eni standards. During the Meeting held on March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, assigned the Board of Statutory Auditors, effective from June 1, 2005, within the limits set forth by Italian laws, the function specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the SEC regulations (see “Item 6 – Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE listed Company Manual audit committees of U.S. companies have further functions and responsibilities which are not mandatory for non-U.S. private issuers and which therefore are not included in the list of functions shown in “Item 6 – Board of Statutory Auditors”. Nominating/Corporate Governance Committee NYSE standards. U.S. listed companies must have a nominating/corporate governance committee (or equivalent body) composed entirely of independent directors that are entrusted, among others, with the responsibility to identify individuals qualified to become board members and to select or recommend director nominees for submission to the Shareholders’ Meeting, as well as to develop and recommend to the Board of Directors a set of corporate governance guidelines. This provision is not binding for non-U.S. private issuers. Eni standards. The Borsa Italiana Code recommends that the Board of Directors shall evaluate whether to establish among its members a nomination committee made up, for the majority, of independent directors. On July 28, 2011, the Board of Directors of Eni established the Nomination Committee, chaired by the Chairman of the Board of Directors, Giuseppe Recchi, and composed by the Chairmen of the other Board Committees: Alessandro Lorenzi (Chairman of the Internal Control Committee) Alessandro Profumo (Chairman of the Oil-Gas Energy Committee) and Mario Resca (Chairman of the Compensation Committee). The members of the Nomination Committee are all non-executive directors. The majority of them are independent in accordance with the recommendations of the Borsa Italiana Code. Further details on this Committee are reported in the Item 6. Code of Business Conduct and Ethics NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a code of business conduct and ethics for its directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers. Eni standards. After the first approval of the Model 231, in the meetings held on December 15, 2003, and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Decree No. 231 of 2001 (hereinafter “Model 231”) and established the relative Eni Watch Structure. Moreover, after the following approvals of the updating of the Model 231 as a result of the changes of Italian legislation on the matter and of the company organizational structures, the Board of Director on March 14, 2008, adopted Eni’s Code of Ethics – replacing the previous version of 1998 – along with the Model 231 which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on ongoing basis: shareholders, employees, suppliers, customers, commercial and financial partners, and the 190 local communities and institutions of the Countries where Eni operates. These values are stated in the Code of Ethics and all the people working for Eni, without exception or distinction, starting from Directors, senior management and members of Company’s bodies, as also requested by the SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing these principles within their function and responsibility. The synergies between the Code of Ethics – an integral part and mandatory general principle of Model 231 – and Model 231 were underlined by the assignment to Eni Watch Structure established by the Model 231 for the organizational, management and control according to Legislative Decree No. 231/2001 – the role of Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics – that is the Watch Structure of the Model 231 – acts for the protection and promotion of the abovementioned principles and every six months presents a report on the implementation of the Code to the Internal Control Committee, to the Board of Statutory Auditors and to the Chairman and the CEO, who reports on this to the Board of Directors. The composition of the Watch Structure of the Model 231, at the beginning composed by only three members, has been modified in 2007, with the introduction of other two external members, one of which appointed Chairman of the Watch Structure, identified among academicians, professional men of proved authority and expertise on economic and management matters. The internal members include the managers responsible for the Legal Affairs, Human Resources and Organization and Internal Audit of the Company. On May 19, 2011, the Board of Directors, with the favorable opinion of the Board of Statutory Auditors, appointed the current members of the Watch Structure. Item 16H. Mine Safety Disclosure Not applicable since Eni does not engage in mining operations. 191 PART III Item 17. FINANCIAL STATEMENTS Not applicable. Item 18. FINANCIAL STATEMENTS Index to Financial Statements: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheet as of December 31, 2011 and 2010 Consolidated profit and loss account for the years ended December 31, 2011, 2010 and 2009 Consolidated Statements of comprehensive income for the years ended December 31, 2011, 2010 and 2009 Consolidated Statements of changes in shareholder’s equity for the years ended December 31, 2011, 2010 and 2009 Consolidated Statement of cash flows for the years ended December 31, 2011, 2010 and 2009 Notes to the Consolidated Financial Statements Page F-1 F-4 F-5 F-6 F-7 F-10 F-12 Item 19. EXHIBITS 1. By-laws of Eni SpA 8. List of subsidiaries 11. Code of Ethics Certifications: 12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act 12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act 13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act) 13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act) 15.a(i) Report of DeGolyer and MacNaughton 15.a(ii) Report of Ryder Scott Co 192 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Shareholders of Eni S.p.A We have audited the accompanying consolidated balance sheets of Eni S.p.A. as of December 31, 2011 and 2010 and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders' equity and cash flows for each of the two years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eni S.p.A. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2011, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 5, 2012 expressed an unqualified opinion thereon. /s/ Reconta Ernst & Young S.p.A. Rome, Italy April 5, 2012 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Shareholders of Eni S.p.A We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Eni S.p.A. management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting on page 186. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Eni S.p.A. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Eni S.p.A. as of December 31, 2011 and 2010 and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders' equity and cash flows for each of the two years in the period ended December 31, 2011 and our report dated April 5, 2012 expressed an unqualified opinion thereon. /s/ Reconta Ernst & Young S.p.A. Rome, Italy April 5, 2012 F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Eni SpA In our opinion, the consolidated balance sheet as of December 31, 2009 and the related consolidated profit and loss accounts, consolidated statements of comprehensive income, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for each of the two years in the period ended December 31, 2009 present fairly, in all material respects, the financial position of Eni SpA and its subsidiaries at December 31, 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers SpA Rome, Italy April 26, 2010 F-3 CONSOLIDATED BALANCE SHEET ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Note Total amount of which with related parties Total amount of which with related parties ASSETS Current assets Cash and cash equivalents ..................................... Other financial assets held for trading or available for sale ................................................ Trade and other receivables ................................... Inventories .............................................................. Current income tax assets ...................................... Other current tax assets .......................................... Other current assets ................................................ Non-current assets Property, plant and equipment .............................. Inventory - compulsory stock ................................ Intangible assets ..................................................... Equity-accounted investments ............................... Other investments .................................................. Other financial assets ............................................. Deferred tax assets ................................................. Other non-current receivables ............................... Assets held for sale ............................................... TOTAL ASSETS .................................................. LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term debt ....................................................... Current portion of long-term debt ......................... Trade and other payables ....................................... Income taxes payable ............................................. Other taxes payable ................................................ Other current liabilities .......................................... Non-current liabilities Long-term debt ....................................................... Provisions for contingencies ................................. Provisions for employee benefits .......................... Deferred tax liabilities ........................................... Other non-current liabilities .................................. Liabilities directly associated with assets held for sale ........................................................... TOTAL LIABILITIES......................................... SHAREHOLDERS’ EQUITY ............................ Non-controlling interest ...................................... Eni shareholders’ equity Share capital ............................................................ Reserve related to cash flow hedging derivatives net of tax effect .................................... Other reserves ......................................................... Treasury shares ....................................................... Interim dividend ..................................................... Net profit ................................................................. Total Eni shareholders’ equity ........................... TOTAL SHAREHOLDERS’ EQUITY ............ TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY .................. 1,549 382 23,636 6,589 467 938 1,350 34,911 67,404 2,024 11,172 5,668 422 1,523 4,864 3,355 96,432 517 131,860 6,515 963 22,575 1,515 1,659 1,620 34,847 20,305 11,792 1,032 5,924 2,194 41,247 38 76,132 4,522 4,005 (174) 49,624 (6,756) (1,811) 6,318 51,206 55,728 131,860 (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (17) (18) (19) (20) (31) (21) (26) (22) (23) (24) (25) (26) (27) (28) (29) (30) (31) (32) F-4 1,496 2 704 3 503 1,446 1,356 9 668 16 127 1,297 5 45 1,500 262 24,595 7,575 549 1,388 2,326 38,195 73,578 2,433 10,950 5,843 399 1,578 5,514 4,225 104,520 230 142,945 4,459 2,036 22,912 2,092 1,896 2,237 35,632 23,102 12,735 1,039 7,120 2,900 46,896 24 82,552 4,921 4,005 49 53,195 (6,753) (1,884) 6,860 55,472 60,393 142,945 CONSOLIDATED PROFIT AND LOSS ACCOUNT ((cid:1) million except as otherwise stated) REVENUES Net sales from operations ............................................... Other income and revenues ............................................ OPERATING EXPENSES .......................................... Purchases, services and other ......................................... - of which non-recurring charge (income) .................... Payroll and related costs ................................................. OTHER OPERATING (EXPENSE) INCOME ....... DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS .............. OPERATING PROFIT ................................................ FINANCE INCOME (EXPENSE) ............................. Finance income ............................................................... Finance expense .............................................................. Derivative financial instruments .................................... INCOME (EXPENSE) FROM INVESTMENTS .... Share of profit (loss) of equity-accounted investments . Other gain (loss) from investments ................................ PROFIT BEFORE INCOME TAXES ...................... Income taxes..................................................................... Net profit ........................................................................ Attributable to: - Eni .................................................................................. - Non-controlling interest ............................................... Earnings per share attributable to Eni ((cid:1) per share) ... Basic ................................................................................. Diluted ............................................................................. Note (35) (36) (37) (38) (39) (32) (40) 2009 2010 2011 Total amount of which with related parties Total amount of which with related parties Total amount of which with related parties 3,882 43 5,887 33 32 49 (1) 338 83,227 1,118 84,345 58,351 250 4,181 55 9,813 12,055 5,950 (6,497) (4) (551) 393 176 569 12,073 (6,756) 5,317 4,367 950 5,317 1.21 1.21 3,300 26 4,999 15 44 27 (4) 98,523 956 99,479 69,135 (246) 4,785 131 9,579 16,111 6,117 (6,713) (131) (727) 537 619 1,156 16,540 (9,157) 7,383 6,318 1,065 7,383 1.74 1.74 3,274 109,589 933 110,522 58 5,825 28 41 41 79,191 69 4,749 171 9,318 17,435 6,379 (7,396) (112) (1,129) 544 1,627 2,171 18,477 (10,674) 7,803 6,860 943 7,803 1.89 1.89 F-5 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME ((cid:1) million) Net profit ..................................................................... Other items of comprehensive income Foreign currency translation differences .................... Change in the fair value of cash flow hedging derivatives ................................. Change in the fair value of available-for-sale financial instruments ................. Share of “Other comprehensive income” on equity-accounted entities ........................................ Taxation ........................................................................ Total other items of comprehensive income .......... Total comprehensive income .................................... Attributable to: - Eni ............................................................................... - Non-controlling interest ............................................ Note 2009 2010 2011 (32) (32) (32) (32) (32) 5,317 (869) (481) 1 2 202 (1,145) 4,172 3,245 927 4,172 7,383 2,169 443 (9) (10) (175) 2,418 9,801 8,699 1,102 9,801 7,803 1,031 352 (6) (13) (128) 1,236 9,039 8,097 942 9,039 F-6 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY ((cid:1) million) Eni shareholders’ equity Reserve related to the fair value of cash flow hedging derivatives net of tax effect Reserve related to the fair value of available- for-sale securities net of tax effect Share capital Legal reserve of Eni SpA Reserve for treasury shares Cumulative currency translation differences Other reserves Treasury shares Retained earnings Interim dividend Net profit for the year Total Non- controlling interest Total share- holders’ equity 4,005 Balance at December 31, 2008 Net profit of the year Other items of comprehensive income Change in the fair value of cash flow hedge derivatives net of tax effect Change in the fair value of available- for-sale securities net of tax effect Share of “Other comprehensive income” on equity-accounted entities Foreign currency translation differences Total recognized income and (expense) for the year Transactions with shareholders Dividend distribution of Eni SpA ((cid:1)0.65 per share in settlement of 2008 interim dividend of (cid:1)0.65 per share) Interim dividend distribution of Eni SpA ((cid:1)0.50 per share) Dividend distribution of other companies Payments by non-controlling interest Allocation of 2008 net profit Put option granted to Publigaz SCRL (Distrigas NV non-controlling shareholder) Effect related to the purchase of Italgas SpA and Stoccaggi Gas SpA by Snam Rete Gas SpA Non-controlling interest acquired following the mandatory tender offer and the squeeze-out on the shares of Distrigas NV Other changes in shareholders’ equity Utilization of the reserve for the acquisition of treasury shares Cost related to stock options Stock options expired Other changes Balance at December 31, 2009 4,005 959 7,187 (90 ) 4 (1,054 ) (969 ) (6,757 ) 34,685 (2,359 ) 8,825 44,436 4,074 48,510 950 5,317 4,367 4,367 (279 ) 1 (278 ) (278 ) 1 1 1 (279 ) (279 ) 1 2 1 2 (696 ) (696 ) (151 ) (151 ) (846 ) (1,122 ) (23 ) (869 ) (23 ) (1,145 ) 2 2 2 (696 ) (151 ) 4,367 3,245 927 4,172 2,359 (4,714 ) (2,355 ) (2,355 ) (1,811 ) (1,811 ) (1,811 ) 4,111 (4,111 ) (350 ) (350 ) 1,560 1,560 1,495 1,086 1,495 1,495 1,086 (1,086 ) 2,581 4,111 (1,146 ) (1,146 ) 548 (8,825 ) (1,585 ) (1,022 ) (2,607 ) (430 ) 1 13 (7 ) (30 ) (24 ) 5 1,492 (1,665 ) (6,757 ) 39,160 (1,811 ) 4,367 46,073 3,978 50,051 13 (7 ) (29 ) (23 ) (38 ) (37 ) (1 ) (1 ) 429 13 (7 ) 80 515 (430 ) 959 6,757 (71 ) (71 ) (439 ) F-7 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued ((cid:1) million) Eni shareholders’ equity Note Share capital Legal reserve of Eni SpA Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of tax effect Reserve related to the fair value of available- for-sale securities net of tax effect Cumulative currency translation differences Other reserves Treasury shares Retained earnings Interim dividend Net profit for the year Total Non- controlling interest Total share- holders’ equity 4,005 959 6,757 (439 ) 5 1,492 (1,665 ) (6,757 ) 39,160 (1,811 ) 4,367 46,073 3,978 50,051 6,318 6,318 1,065 7,383 (32) (32) (32) (32) (32) (32) 267 (2 ) 265 265 (8 ) (8 ) (8 ) 267 267 (8 ) (8 ) (5 ) 2,204 (5 ) 2,204 (5 ) 2,204 (5 ) (5 ) (10 ) 2,127 2,381 42 2,169 37 2,418 6,318 8,699 1,102 9,801 (75 ) (75 ) (75 ) 1,811 (3,622 ) (1,811 ) (1,811 ) (1,811 ) (1,811 ) (1,811 ) 745 (745 ) (514 ) (514 ) 56 56 (56 ) (1 ) 1 1 1 1 10 10 27 37 (1 ) 56 1 756 (4,367 ) (3,555 ) 7 7 (37 ) (37 ) (573 ) (4,128 ) Balance at December 31, 2009 Net profit of the year Other items of comprehensive income Change in the fair value of cash flow hedge derivatives net of tax effect Change in the fair value of available-for-sale securities net of tax effect Share of “Other comprehensive income” on equity-accounted entities Foreign currency translation differences Total recognized income and (expense) for the year Transactions with shareholders Dividend distribution of Eni SpA ((cid:1)0.50 per share in settlement of 2009 interim dividend of (cid:1)0.50 per share) Interim dividend distribution of Eni SpA ((cid:1)0.50 per share) Dividend distribution of other companies Allocation of 2009 net profit Effect related to the purchase of Italgas SpA and Stoccaggi Gas SpA by Snam Rete Gas SpA Treasury shares sold following the exercise of stock options by Eni managers Treasury shares sold following the exercise of stock options by Saipem and Snam Rete Gas managers Non-controlling interest recognized following the acquisition of the control stake in the share capital of Altergaz SA Non-controlling interest excluded following the divestment of the control stake in the share capital of GreenStream BV Other changes in shareholders’ equity Cost related to stock options Stock options expired Stock warrants on Altergaz SA Other changes Balance at December 31, 2010 (32) 4,005 959 6,756 (174 ) 7 (6 ) 7 (6 ) (25 ) 28 4 539 (6,756 ) 39,855 (1,811 ) 6,318 51,206 4,522 55,728 7 (6 ) (25 ) 13 (11 ) 15 15 13 14 (25 ) (25 ) (3 ) 1,518 F-8 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY continued ((cid:1) million) Eni shareholders’ equity Note Share capital Legal reserve of Eni SpA Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of tax effect Reserve related to the fair value of available- for-sale securities net of tax effect Cumulative currency translation differences Other reserves Treasury shares Retained earnings Interim dividend Net profit for the year Total Non- controlling interest Total share- holders’ equity (32) 4,005 959 6,756 (174 ) (3 ) 1,518 539 (6,756 ) 39,855 (1,811 ) 6,318 51,206 4,522 55,728 943 7,803 6,860 6,860 (32) (32) (32) (32) (32) (32) (32) 223 (5 ) (12 ) 223 (5 ) 1,000 (12 ) 1,000 223 (5 ) (12 ) 1,000 31 31 31 223 223 (5 ) (5 ) (12 ) (1 ) (13 ) 1,031 1,237 1,031 (1 ) 1,236 6,860 8,097 942 9,039 1,811 (3,622 ) (1,811 ) (1,811 ) (1,884 ) (1,884 ) (1,884 ) (571 ) (571 ) 26 26 2,696 (2,696 ) (94 ) (5 ) (25 ) (119 ) (7 ) (126 ) (5 ) 5 (3 ) 3 3 3 3 14 (10 ) 4 13 17 (3 ) (85 ) 3 2,664 (73 ) (6,318 ) (3,812 ) (10 ) (10 ) (544 ) (4,356 ) Balance at December 31, 2010 Net profit of the year Other items of comprehensive income Change in the fair value of cash flow hedge derivatives net of tax effect Change in the fair value of available-for-sale securities net of tax effect Share of “Other comprehensive income” on equity-accounted entities Foreign currency translation differences Total recognized income and (expense) for the year Transactions with shareholders Dividend distribution of Eni SpA ((cid:1)0.50 per share in settlement of 2010 interim dividend of (cid:1)0.50 per share) Interim dividend distribution of Eni SpA ((cid:1)0.52 per share) Dividend distribution of other companies Payments by minority shareholders Allocation of 2010 net profit Acquisition of non-controlling interest relating to Altergaz SA and Tigaz Zrt Effect related to the purchase of Italgas SpA by Snam Rete Gas SpA Treasury shares sold following the exercise of stock options exercised by Eni managers Treasury shares sold following the exercise of stock options by Saipem and Snam Rete Gas managers Non-controlling interest excluded following the sale of Eni Acqua Campania SpA and the divestment of the control stake in the share capital of Petromar Lda Other changes in shareholders’ equity Cost related to stock options Stock options expired Other changes Balance at December 31, 2011 (32) 4,005 959 6,753 49 2 (7 ) (13 ) (18 ) (8 ) 1,421 1,539 (6,753 ) 42,531 (1,884 ) 6,860 55,472 4,921 60,393 2 (7 ) (14 ) (19 ) 2 (7 ) (14 ) (19 ) 1 1 F-9 CONSOLIDATED STATEMENT OF CASH FLOWS ((cid:1) million) Net profit of the year .................................................... Adjustments to reconcile net profit to net cash provided by operating activities Depreciation, depletion and amortization ................... Impairments of tangible and intangible assets, net .... Share of (profit) loss of equity-accounted investments ................................. Gain on disposal of assets, net .................................... Dividend income .......................................................... Interest income ............................................................. Interest expense ............................................................ Income taxes ................................................................. Other changes ............................................................... Changes in working capital: - inventories .................................................................. - trade receivables ........................................................ - trade payables ............................................................. - provisions for contingencies ..................................... - other assets and liabilities .......................................... Cash flow from changes in working capital ............... Net change in the provisions for employee benefits ... Dividends received ....................................................... Interest received ........................................................... Interest paid .................................................................. Income taxes paid, net of tax receivables received .... Net cash provided by operating activities .............. - of which with related parties...................................... Investing activities: - tangible assets ............................................................. - intangible assets .......................................................... - consolidated subsidiaries and businesses .................. - investments.................................................................. - securities...................................................................... - financing receivables .................................................. - change in payables and receivables in relation to investing activities and capitalized depreciation .. Cash flow from investing activities .............................. Disposals: - tangible assets ............................................................. - intangible assets .......................................................... - consolidated subsidiaries and businesses .................. - investments.................................................................. - securities...................................................................... - financing receivables .................................................. - change in payables and receivables in relation to disposals ................................................ Cash flow from disposals.............................................. Net cash used in investing activities ........................ - of which with related parties ..................................... Note 2009 2010 2011 5,317 7,383 7,803 (36) (36) (38) (38) (39) (42) (14) (16) (33) (17) (33) (42) 8,762 1,051 (393) (226) (164) (352) 603 6,756 (319) 52 1,431 (2,559) 517 (636) (1,195) 16 576 594 (583) (9,307) 11,136 (1,188) (12,032) (1,663) (25) (230) (2) (972) (97) (15,021) 111 265 3,219 164 861 8,881 698 (537) (552) (264) (96) 571 9,157 (39) (1,150) (1,918) 2,770 588 (2,010) (1,720) 21 799 126 (600) (9,134) 14,694 (1,749) (12,308) (1,562) (143) (267) (50) (866) 261 (14,935) 272 57 215 569 14 841 8,297 1,021 (544) (1,170) (659) (101) 737 10,674 331 (1,422) (369) 161 122 (668) (2,176) (10) 997 100 (893) (10,025) 14,382 (186) (11,658) (1,780) (115) (245) (62) (715) 379 (14,196) 154 41 1,006 711 128 695 147 4,767 (10,254) (1,262) 2 1,970 (12,965) (1,626) 243 2,978 (11,218) (800) F-10 CONSOLIDATED STATEMENT OF CASH FLOWS continued ((cid:1) million) Note 2009 2010 2011 Proceeds from long-term debt ..................................... Repayments of long-term debt .................................... Increase (decrease) in short-term debt ........................ (26) (26) (21) Net capital contributions by non-controlling interest .......................................... Sale of treasury shares ................................................. Net acquisition of treasury shares different from Eni SpA ................................................................ Acquisition of additional interests in consolidated subsidiaries ......................................... Dividends paid to Eni’s shareholders ......................... Dividends paid to non-controlling interest ................. Net cash used in financing activities ........................ - of which with related parties ..................................... Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries) .................................................................. Effect of exchange rate changes on cash and cash equivalents and other changes ..................... Net cash flow of the year ........................................... Cash and cash equivalents - beginning of the year ............................................... Cash and cash equivalents - end of the year .......... (42) (7) (7) 2,953 (3,327) 2,646 2,272 8,774 (2,044) (2,889) 3,841 1,551 9 37 (2,068) (4,166) (350) (1,183) (14) (30) (331) 1,939 1,608 (3,622) (514) (1,827) (23) 39 (59) 1,608 1,549 4,474 (889) (2,481) 1,104 26 3 17 (126) (3,695) (552) (3,223) 348 (7) 17 (49) 1,549 1,500 F-11 Notes to the Consolidated Financial Statements 1 Basis of presentation The Consolidated Financial Statements of Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB)1. Oil and natural gas exploration and production activity is accounted for in conformity with internationally accepted accounting principles. Specifically, this concerns the determination of the amortization expenses using the unit-of- production method and the recognition of the production-sharing agreement and buy-back contracts. The Consolidated Financial Statements have been prepared on an historical cost basis, taking into account where appropriate of any value adjustments, except for certain items that under IFRS must be recognized at fair value as described in the summary of significant accounting policies paragraph. The Consolidated Financial Statements include the statutory accounts of Eni SpA and the accounts of subsidiaries where the company holds the right to directly or indirectly exercise control, determine financial and operating policies and obtain economic benefits from their activities. For entities acting as sole-operator in the management of oil and gas contracts on behalf of companies participating in a joint venture, the activities are financed proportionately based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognized proportionally directly in the financial statements of the companies involved. The exclusion from consolidation of some subsidiaries, which are not material either individually or overall, has not produced significant2 economic and financial effects on the Consolidated Financial Statements. These interests are accounted for as described below under the item “Financial fixed assets”. Subsidiaries’ financial statements are audited by the independent auditors who examine and certify also the information required for the preparation of the Consolidated Financial Statements. The 2011 Consolidated Financial Statements approved by Eni’s Board of Directors on March 15, 2012, were audited by the independent auditor Reconta Ernst & Young SpA. The independent auditor of Eni SpA, as the main auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other independent auditors, it takes the responsibility of their work. Amounts in the financial statements and in the notes are expressed in millions of euros ((cid:1) million). 2 Principles of consolidation Interests in consolidated companies Assets and liabilities, revenues and expenses related to fully consolidated subsidiaries are wholly incorporated in the Consolidated Financial Statements; the book value of these subsidiaries is eliminated against the corresponding share of the shareholders’ equity by attributing to each of the balance sheet items its fair value. When acquired, the net equity of subsidiaries is initially recognized at fair value. The excess of the purchase price of an acquired entity over the total fair value assigned to assets acquired and liabilities assumed is recognized as goodwill; negative goodwill is recognized in the profit and loss account. Equity and net profit of non-controlling interests are included in specific lines of equity and profit and loss account. If the partial control is acquired, this share of equity is determined using the proportionate share of the fair value of assets and liabilities, excluding any related goodwill, at the time when control is acquired (partial goodwill method); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, taking into account therefore also the portion attributable to the non-controlling interests (full goodwill method); in the latter case, the non-controlling interests are measured at their total fair value which therefore includes the goodwill attributable to them3. The method of measuring goodwill (partial goodwill method or full goodwill method) is selective for each business combination. In a business combination achieved in stages, the purchase price is determined summing the fair value of previously held equity interest and the consideration transferred for the acquisition of control; the previously held (1) (2) (3) Related party disclosures have been prepared according to the provisions of IAS 24 “Related Party Disclosures”, effective starting from 2011, that enhance the definition of related party and the disclosure to be reported. According to the requirements of the Framework of international accounting standards, information is material if its omission or misstatement could influence the economic decisions that users make on the basis of the financial statements. The choice between partial goodwill and full goodwill method is available also for business combinations resulting in the recognition of a “negative goodwill” in profit or loss account (gain on bargain purchase). F-12 equity interest is remeasured at its acquisition date fair value and the resulting gain or loss is recognized in profit or loss account. The purchase of additional equity interests in subsidiaries from non-controlling interests is recognized in equity and represents the excess of the amount paid over the carrying value of the non-controlling interests acquired; similarly, the effects of the sale of non-controlling interests in subsidiaries without loss of control are recognized in equity. Inter-company transactions Inter-company transactions and balances, including unrealized profits arising from intra-group transactions have been eliminated. Unrealized losses are not eliminated because they provide evidence of an impairment of the asset transferred. Foreign currency translation Financial statements of foreign companies having a functional currency other than the euro, that represents the Group’s functional currency, are translated into euro using the rates of exchange ruling at the balance sheet date for assets and liabilities, historical exchange rates for equity accounts and average rates for the profit and loss account (source: Bank of Italy). Cumulative exchange rate differences resulting from this translation are recognized in shareholders’ equity under “Other reserves” in proportion to the Group’s interest and under “Non-controlling interest” for the portion related to non-controlling interests. Cumulative exchange rate differences are charged to the profit and loss account when the entity disposes the entire interest in a foreign operation or at the loss of control of a foreign subsidiary. On the partial disposal, without losing control, the proportionate share of cumulative amount of exchange differences related to the disposed interest is recognized in equity to non-controlling interests. Financial statements of foreign subsidiaries which are translated into euro are denominated in the functional currencies of the Countries where the entities operate. The U.S. dollar is the prevalent functional currency for the entities that do not use the euro. The main foreign exchange rates used to translate the financial statements adopting a different functional currency are indicated below: (currency amount for (cid:1)1) Annual average exchange rate 2009 Exchange rate at Dec. 31, 2009 Annual average exchange rate 2010 Exchange rate at Dec. 31, 2010 Annual average exchange rate 2011 Exchange rate at Dec. 31, 2011 U.S. Dollar ...................................................... Pound Sterling ................................................ Norwegian Krone ........................................... Australian Dollar ............................................ Hungarian Forint ............................................ 1.39 0.89 8.73 1.77 280.33 1.44 0.89 8.30 1.60 270.42 1.33 0.86 8.00 1.44 275.48 1.34 0.86 7.80 1.31 277.95 1.39 0.87 7.79 1.35 279.37 1.29 0.84 7.75 1.27 314.58 3 Summary of significant accounting policies The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below. Current assets Held for trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the profit and loss account under “Financial income (expense)”4 and to the equity reserve related to other comprehensive income, respectively. Changes in fair value of available-for-sale financial assets recognized in equity are charged to the profit and loss account when the assets are derecognized or impaired. The objective evidence that an impairment loss has occurred is verified considering, interalia, significant breaches of contracts, serious financial difficulties or the risk of insolvency of the counterparty; asset write downs are included in the carrying amount. Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets and held-to-maturity financial assets. The fair value of financial instruments is determined by market quotations or, where there is no active market, it is estimated (4) Starting from 2009, changes in the fair value of non-hedging derivatives on commodities, also including the effects of settlements, are recognized in the profit and loss account item “Other operating income (expense)”. F-13 adopting suitable financial valuation models which take into account all the factors adopted by market operators and prices obtained in similar recent transactions in the market. Interests and dividends on financial assets stated at fair value are accounted for on an accrual basis in “Financial income (expense)” and “Other gain (loss) from investments”, respectively. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame generally established by regulation or convention in the market place concerned, the transaction is accounted for on the settlement date. Receivables are measured at amortized cost (see item “Financial fixed assets” below). Transferred financial assets are derecognized when the contractual rights to receive the cash flows of the financial assets are transferred together with the risks and rewards of the ownership. Inventories, including compulsory stocks and excluding construction contracts, are stated at the lower of purchase or production cost and net realizable value. Net realizable value is the net amount expected to be realized from the sale of inventories in the normal course of business, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual sale price. Inventories of natural gas which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell. The cost for inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted-average cost method on a three-month basis, or monthly, when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost for inventories of the Petrochemical segment is determined by applying the weighted-average cost on an annual basis. Construction contracts are measured using the cost-to-cost method, whereby contract revenue is recognized by reference to the stage of completion of the contract matching it with the contract costs incurred in reaching that stage of completion. Advances are deducted from inventories within the limits of accrued contractual considerations; any excess of such advances over the value of the inventories is recorded as a liability. Losses related to construction contracts are recognized immediately as an expense when it is probable that total contract costs will exceed total contract revenues. Construction contract not yet invoiced, whose payment will be made in a foreign currency, is translated into euro using the rates of exchange ruling at the balance sheet date and the effect of rate changes is reflected in the profit and loss account. When take-or-pay clauses are included in long-term natural gas purchase contracts, uncollected gas volumes which imply the “pay” clause, measured using the price formulas contractually defined, are recognized under “Other assets” as “Deferred costs” as an offset to “Other payables” or, after the settlement, to “Cash and Cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually delivered – the related cost is included in the determination of the weighted-average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to collect gas that was previously uncollected within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, determined adopting the same criteria described for inventories. Hedging instruments are described in the section “Derivative Instruments”. Non-current assets Property, plant and equipment5 Tangible assets, including investment properties, are recognized using the cost model and stated at their purchase or self-construction cost including any costs directly attributable to bringing the asset into operation. In addition, when a substantial period of time is required to make the asset ready for use, the purchase price or self- construction cost includes the borrowing costs incurred that could have otherwise been saved had the investment not been made. In the case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired. (5) Recognition and evaluation criteria of exploration and production activities are described in the section “Exploration and production activities” below. F-14 Changes in estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized under “Provisions for contingencies”6. Property, plant and equipment are not revalued for financial reporting purposes. Assets carried under financial leasing or concerning arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset are recognized at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt payable to the lessor is recognized as a financial liability. These assets are depreciated using the criteria described below. When the renewal is not reasonably certain, leased assets are depreciated over the shorter of the lease term or the estimated useful life of the asset. Expenditures on renewals, improvements and transformations which provide additional economic benefits are capitalized to property, plant and equipment. Tangible assets, from the moment they begin or should begin to be used, are depreciated systematically using a straight-line method over their useful life which is an estimate of the period over which the assets will be used by the company. When tangible assets are composed of more than one significant element with different useful lives, each component is depreciated separately. The amount to be depreciated is the book value less the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see item “Non-current assets held for sale” below). Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset’s useful life. Replacement costs of identifiable components in complex assets are capitalized and depreciated over their useful life; the residual book value of the component that has been substituted is charged to the profit and loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred. The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying value with the recoverable amount, which is the higher of fair value less costs to sell or its value in use. If there is no binding sales agreement, fair value is estimated on the basis of market values, recent transactions, or the best available information that shows the proceeds that the company could reasonably expect to collect from the disposal of the asset. Value in use is the present value of the future cash flows expected to be derived from the use of the asset and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life, net of disposal costs. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices (and to prices for products which derive there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. Discounting is carried out at a rate that reflects a current market valuation of the time value of money and of those specific risks of the asset that are not reflected in the estimate of the future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific Country risk of the activity. The evaluation of the specific Country risk to be included in the discount rate is provided by external parties. The WACC differs considering the risk associated with individual operating segments; in particular for the assets belonging to the Gas & Power and Engineering & Construction segments, taking into account their different risk compared with Eni, specific WACC rates have been defined (for Gas & Power segment on the basis of a sample of companies operating in the same segment; for Engineering & Construction segment on the basis of the market quotation); WACC used for impairments in the Gas & Power segment is adjusted to take into consideration the risk premium of the specific Country of the activity while WACC used for impairments in the Engineering & Construction segment is not adjusted for Country risk as most of the assets are not located in a specific Country. For the regulated activities, the discount rate used for the measurement of the value in use is equal to the rate return defined by the Regulator. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash generating unit”. When the reasons for their impairment cease to exist, Eni makes a reversal that is recognized in the profit or loss account as income from asset revaluation. This reversed amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior-years. (6) The company recognizes material provisions for the retirement of assets in the Exploration & Production business. No significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets are generally recognized, as undetermined settlement dates for asset retirements do not allow a reasonable estimate of the fair value of the associated retirement obligation. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation. F-15 Intangible assets Intangible assets are identifiable assets without physical substance, controlled by the company and able to produce future economic benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or as an integral part of other assets. An entity controls an asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits. Intangible assets are initially stated at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with a definite useful life are amortized systematically over their useful life estimated as the period over which the assets will be used by the company; the amount to be amortized and the recoverability of the carrying amount are determined in accordance with the criteria described in the section “Property, plant and equipment”. Goodwill and other intangible assets with an indefinite useful life are not amortized. The recoverability of their carrying value is reviewed at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management purposes. When the carrying amount of the cash generating unit, including goodwill allocated thereto, exceeds the cash generating unit’s recoverable amount7, the excess is recognized as impairment. The impairment loss is first allocated to reduce the carrying amount of goodwill; any remaining excess to be allocated to the assets of the unit is applied pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against goodwill are not reversed8. Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be reliably determined; (ii) there is the intention, availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate future economic benefits. Intangible assets also include public to private service concession arrangements concerning the development, financing, operation and maintenance of infrastructures under concession, in which: (i) the grantor controls or regulates what services the operator must provide with the infrastructure, and at what price; and (ii) the grantor controls – by the ownership, beneficial entitlement or otherwise – any significant residual interest in the infrastructure at the end of the concession arrangement. According to the agreements, the operator has the right to operate the infrastructure, controlled by the grantor, in order to provide the public service9. Exploration and production activities10 Acquisition of mineral rights Costs associated with the acquisition of mineral rights are capitalized in connection with the assets acquired (such as exploratory potential, probable and possible reserves and proved reserves). When the acquisition is related to a set of exploratory potential and reserves, the cost is allocated to the different assets acquired on the basis of the value of the relevant discounted cash flows. Expenditure for the exploratory potential, represented by the costs for the acquisition of the exploration permits and for the extension of existing permits, is recognized under “Intangible assets” and is amortized on a straight-line basis over the period of the exploration as contractually established. If the exploration is abandoned, the residual expenditure is charged to the profit and loss account. Acquisition costs for proved reserves and for possible and probable reserves are recognized in the balance sheet as assets. Costs associated with proved reserves are amortized on a UOP basis, as detailed in the section “Development”, considering both developed and undeveloped reserves. Expenditures associated with possible and probable reserves are not amortized until classified as proved reserves; in case of a negative result, the costs are charged to the profit and loss account. Exploration Costs associated with exploratory activities for oil and gas producing properties incurred both before and after the acquisition of mineral rights (such as acquisition of seismic data from third parties, test wells and geophysical surveys) are initially capitalized in order to reflect their nature as an investment and subsequently amortized in full when incurred. (7) (8) For the definition of recoverable amount see item “Property, plant and equipment”. Impairment charges recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized. (9) When the operator has an unconditional contractual right to receive cash or another financial asset from or at the direction of the grantor, considerations (10) received or receivable by the operator for construction or upgrade of infrastructure are recognized as a financial asset. IFRS does not have specific criteria for hydrocarbon exploration and production activities. Eni continues to use existing accounting policies for exploration and evaluation of assets previously applied before the introduction of IFRS 6 “Exploration for and evaluation of mineral resources”. F-16 Development Development expenditures are those costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas. They are then capitalized within property, plant and equipment and amortized generally on a UOP basis, as their useful life is closely related to the availability of feasible reserves. This method provides for residual costs at the end of each quarter to be amortized at a rate representing the ratio between the volumes extracted during the quarter and the proved developed reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between development expenditures and proved developed reserves. Costs related to unsuccessful development wells or damaged wells are expensed immediately as losses on disposal. Impairments and reversal of impairments of development costs are made on the same basis as those for tangible assets. Production Production costs are those costs incurred to operate and maintain wells and field equipment and are expensed as incurred. Production-sharing agreements and buy-back contracts Oil and gas reserves related to production-sharing agreements and buy-back contracts are determined on the basis of contractual clauses related to the repayment of costs incurred for the exploration, development and production activities executed through the use of company’s technologies and financing (Cost Oil) and the company’s share of production volumes not destined to cost recovery (Profit Oil). Revenues from the sale of the production entitlements against both Cost Oil and Profit Oil are accounted for on an accrual basis whilst exploration, development and production costs are accounted for according to the policies mentioned above. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on the behalf of the company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Retirement Costs expected to be incurred with respect to the retirement of a well, including costs associated with removal of production facilities, dismantlement and site restoration, are capitalized, consistently with the policy described under “Property, plant and equipment”, and then amortized on a UOP basis. Grants Grants related to assets are recognized as a reduction of purchase price or production cost of the related assets when there is reasonable assurance that all the required conditions attached to them, agreed upon with government entities, have been met. Grants not related to capital expenditure are recognized in the profit and loss account. Financial fixed assets Investments Investments in subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for using the equity method11. Under the equity method, investments are initially recognized at cost and subsequently adjusted to reflect: (i) the investor’s share of the post-acquisition profit or loss of the investee; and (ii) the investor’s share of the investee’s other comprehensive income. Distributions received from an investee are recorded as a reduction of the carrying amount of the investment. In applying the equity method, consolidations adjustments are considered (see also “Principles of consolidation” paragraph). When there is objective evidence of impairment (see also section “Current assets”), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the section “Property, plant and equipment”. Subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for at cost, adjusted for impairment losses if this does not result in a misrepresentation of the company’s financial condition. When the reasons for their impairment cease to exist, investments accounted for at cost are revalued within the limit of the impairment made and their effects are included in “Other gain (loss) from investments”. Other investments, included in non-current assets, are recognized at their fair value and their effects are included in the equity reserve related to other comprehensive income; the changes in fair value recognized in equity are charged to the profit and loss account when it is impaired or realized. When investments are not traded in a public market and (11) In the case of step acquisition of a significant influence (or joint control), the investment is recognized, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity. F-17 their fair value cannot be reasonably determined, they are accounted for at cost, adjusted for impairment losses; impairment losses shall not be reversed12. The investor’s share of losses of an investee, that exceeds its interest in the investee, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to cover its losses. Receivables and financial assets to be held to maturity Receivables and financial assets to be held to maturity are stated at cost represented by the fair value of the initial exchanged amount adjusted to take into account direct external costs related to the transaction (e.g. fees of agents or consultants, etc.). The initial carrying value is then adjusted to take into account principal repayments, reductions for impairment or uncollectibility and amortization of any difference between the maturity amount and the initial amount. Amortization is carried out on the basis of the effective interest rate of return represented by the rate that equalizes, at the moment of the initial recognition, the present value of expected cash flows to the initial carrying amount (so called “amortized cost method”). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease. If there is objective evidence that an impairment loss has been incurred (see also point “Current assets”), the impairment loss is measured by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate as defined at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and financial assets to be held to maturity are recognized net of the allowance for impairment losses; when the impairment loss is definite the allowance for impairment losses is utilized against charges; any amount in excess is reversed to profit. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as “Financial income (expense)”. Non-current assets held for sale Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through their continuing use. For this to be the case, the sale must be highly probable and the asset or the disposal group must be available for immediate sale in its present condition. Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from the other assets and liabilities. Non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell and their carrying amount. The classification as held for sale of equity-accounted investments determines the interruption of equity method accounting; therefore, in this case, the book value of the investment in accordance with the equity method represents the carrying amount for the measurement as non-current assets held-for sale. Any difference between the carrying amount and the fair value less costs to sell is taken to the profit or loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. Financial liabilities Debt is measured at amortized cost (see item “Financial fixed assets” above). Financial liabilities are derecognized when they are extinguished, or when the obligation specified in the contract is discharged or cancelled or expires. (12) Impairment charges recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized. F-18 Provisions for contingencies Provisions for contingencies are liabilities for expenses and charges of a definite nature and whose existence is certain or probable but for which at year-end the timing or amount of future expenditure is uncertain. Provisions are recognized when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that the settlement of that obligation will result in an outflow of resources embodying economic benefits; and (iii) the amount of the obligation can be reliably estimated. The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation at the balance sheet date or to transfer it to third parties at that time. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any indemnity or penalty arising from failure to fulfill these obligations. If the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as “Financial income (expense)”. When the liability regards a tangible asset (e.g. site dismantling and restoration), the provision is stated with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made with the amortization process. Costs that the company expects to bear in order to carry out restructuring plans are recognized when the company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring. Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognized in the same profit and loss account item that had previously held the provision, or, when the liability regards tangible assets (i.e. site dismantling and restoration), with a corresponding entry to the assets to which they refer. In the Note 27, the following contingent liabilities are described: (i) possible, but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the company’s control; and (ii) present obligations arising from past events whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Provisions for employee benefits Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. In the first case, the company’s obligation, which consists of making payments to the State or a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. The actuarial gains and losses of defined benefit plans are recognized pro-rata on service, in the profit and loss account using the corridor method, if and to the extent that net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period exceed the greater of 10% of the present value of the defined benefit obligation or 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating in the plan. Such actuarial gains and losses derive from changes in the actuarial assumptions used or from a change in the conditions of the plan. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety. Treasury shares Treasury shares are recognized as deductions from equity at cost. Gains or losses resulting from subsequent sales are recognized in equity. Revenues and costs Revenues associated with sales of products and services are recognized when significant risks and rewards of ownership have passed to the customer or when the transaction can be considered settled and the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of: • crude oil, generally upon shipment; • natural gas, upon delivery to the customer; • petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognized upon shipment; • chemical products and other products, generally upon shipment. Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer. Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other F-19 producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Differences between Eni’s net working interest volume and actual production volumes are recognized at current prices at year-end. Income related to partially rendered services is recognized in the measurement of accrued income if the stage of completion can be reliably determined and there is no significant uncertainty as to the collectability of the amount and the related costs. When the outcome of the transaction cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable. Revenues accrued during the year related to construction contracts are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis. For service concession arrangements (see item “Intangible assets” above) in which customers fees do not provide a reliable distinction between the compensation for construction/update of the infrastructure and the compensation for operating it and in the absence of external benchmarks, revenues recognized during the construction/update phase are limited to the amount of the costs incurred. Additional revenues, derived from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them. Tangible assets, different from an infrastructure used in service concession arrangements, transferred from customers (or constructed using cash transferred from customers) and used to connect them to a network to supply goods and services, are recognized at their fair value as an offset to revenues. When more than one separately identifiable service is provided (for example, connection to a network and supply of goods) the entity shall assess for which one service it receives the transferred asset from the customer and it shall consistently recognize a revenue when the connection is delivered or over the lesser period between the length of the supply and the useful life of the transferred asset. Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and direct taxation. Award credits, related to customer loyalty programs, are recognized as a separate component of the sales transaction which grant the right to customers. Therefore, the portion of revenues related to the fair value of award credits granted is recognized as an offset to the item “Other liabilities”. The liability is charged to the profit and loss account in the period in which the award credits are redeemed by customers or the related right is lost. The exchange of goods and services of a similar nature and value do not give rise to revenues and costs as they do not represent sale transactions. Costs are recorded when the related goods and services are sold or consumed during the year or systematically allocated or when their future economic benefits cannot be identified. Costs associated with emission quotas, determined on the basis of the average prices of the main European markets at period end, are recognized in relation to the amount of the carbon dioxide emissions that exceed the amount assigned. Costs related to the purchase of the emission rights are recorded as intangible assets net of any negative difference between the amount of emissions and the quotas assigned. Revenues related to emission quotas are recognized when they are realized through a sale transaction. In case of sale, if applicable, the acquired emission rights are considered as the first to be sold. Monetary receivables granted as a substitution of emission rights awarded free of charge are recognized as an offset to item “Other income” of the profit and loss account. Operating lease payments are recognized in the profit and loss account over the length of the contract. Labor costs include stock options granted to managers, consistent with their actual remunerative nature. The instruments granted are recorded at fair value on the vesting date and are not subject to subsequent adjustments; the current portion is calculated pro-rata over the vesting period13. The fair value of stock options is determined using valuation techniques which consider conditions related to the exercise of options, current share prices, expected volatility and the risk-free interest rate. The fair value of stock options is recorded as a charge to “Other reserves”. The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized (see item “Intangible assets” above), are included in the profit and loss account. Exchange rate differences Revenues and costs associated with transactions in currencies other than the functional currency are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year-end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary items that are measured at fair value, recoverable amount or net realizable value are translated using the exchange rate at the date when the value is determined. Dividends Dividends are recognized at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain. (13) The period between the date of the award and the date at which the option can be exercised. F-20 Income taxes Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in “Income taxes payable”. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the tax authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets or liabilities are recognized for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their realization is considered probable. Similarly, deferred tax assets for the carryforward of unused tax credits and unused tax losses are recognized to the extent that the recoverability is probable. Relating to the temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, the related deferred tax liabilities are not recognized if the investor is able to control the timing of reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item “Deferred tax assets”; if negative, in the item “Deferred tax liabilities”. When the results of transactions are recognized directly in shareholders’ equity, current taxes, deferred tax assets and liabilities are also charged to the shareholders’ equity. Derivatives Derivatives, including embedded derivatives which are separated from the host contract, are assets and liabilities recognized at their fair value which is estimated by using the criteria described in the section “Current assets”. When there is objective evidence that an impairment loss has occurred for reasons different from fair value decreases (see item “Current assets”) derivative are recognized net of the allowance for impairment losses. Derivatives are designated as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is highly effective and regularly reviewed. When hedging instruments hedge the risk of changes of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability on the fair value of fixed interest rate assets/liabilities) the derivatives are recognized at fair value and the effects charged to the profit and loss account. Hedged items are consistently adjusted to reflect the variability of fair value associated with the hedged risk. When derivatives hedge the cash flow variability risk of the hedged item (cash flow hedge, e.g. hedging the variability on the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), changes in the fair value of the derivatives, considered effective, are initially recognized in equity and then in the profit and loss account consistently with the economic effects produced by the hedged transaction. The changes in the fair value of derivatives that do not meet the conditions required to qualify for hedge accounting are reported in the profit and loss account. Economic effects of transactions to buy or sell commodities entered into to meet the entity’s normal operating requirements and for which the settlement is provided with the delivery of the underlying, are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption). 4 Financial statements14 Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature15. The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS. The statement of changes in shareholders’ equity includes profit and loss for the year, transactions with shareholders and other changes in shareholders’ equity. The statement of cash flows is presented using the indirect method, whereby net profit is adjusted for the effects of non-cash transactions. 5 Use of 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 notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on (14) (15) The financial statements are the same reported in the Annual Report 2010. Further information on financial instruments as classified in accordance with IFRS is provided in Note 34 – Guarantees, commitments and risks – Other information about financial instruments. F-21 complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant 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 in 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 the company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summary of significant estimates follows. Oil and gas activities Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be designated as “proved”, the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves are classified as proved undeveloped. Volumes are subsequently reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural as that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment. Impairment of assets Tangible assets and intangible assets, including goodwill, are impaired when there are events or changes in circumstances that indicate the carrying values of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred costs – see also item “Current assets”) related to natural gas volumes not collected under long-term purchase contracts with take-or-pay clauses. The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. F-22 Oil, natural gas and petroleum product prices (and prices from products which are derived there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows. Goodwill and other intangible assets with an indefinite useful life are not subject to amortization. The Company tests for impairment such assets at the cash-generating unit level on an annual basis and whenever there is an indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed to that cash generating unit is impaired up to that difference; if the carrying amount of goodwill is less than the amount of impairment, assets of the cash generating unit are impaired pro-rata on the basis of their carrying amount for the residual difference. Asset retirement obligations Obligations to remove tangible equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. Estimating future asset retirement obligations is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the Countries where Eni operates, as do political, environmental, safety and public expectations. The subjectivity of these estimates is also increased by the accounting method used that requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically, at the time the asset is installed at the production location). When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are increased with the passage of time (i.e. interest accretion) and any change in the estimates following the modification of future cash flows and discount rate adopted. The recognized asset retirement obligations are based on future retirement cost estimates and incorporate many assumptions such as: expected recoverable quantities of crude oil and natural gas, abandonment time, future inflation rates and the risk-free rate of interest adjusted for the Company’s credit costs. Business combinations Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. Any positive residual difference is recognized as “Goodwill”. Negative residual differences are credited to the profit and loss account. Management uses all available information to make these fair value determinations and, for major business combinations, typically engages independent external advisors to assist in the fair value determination of the acquired assets and liabilities. Environmental liabilities Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability has been incurred and the amount can be reasonably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by Decree No. 471/1999 of the Ministry for the Environment concerning the remediation of contaminated sites; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible insurance recoveries. F-23 Provisions for employee benefits Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds. The inflation rates reflect market conditions observed Country by Country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved; and (v) determination of the expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equity and cash and their specific average expected rate of return is taken into account. Differences between expected and actual costs and between the expected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. Eni applies the corridor method to amortize its actuarial losses and gains. This method amortizes on a pro-rata basis the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period that exceed the greater of 10% of: (i) the present value of the defined benefit obligation; and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan. Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions. The effects of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety. Contingencies In addition, to accruing the estimated costs for environmental liabilities, asset retirement obligation and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining the appropriate amount to accrue is a complex estimation process that includes subjective judgments of the management. Revenue recognition in the Engineering & Construction segment Revenue recognition in the Engineering & Construction segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to the geographical region where the activity is carried out, market conditions in that region and any assessment that is necessary to estimate with sufficient precision the total future costs as well as the expected timetable to the end of the contract. Additional income, derived from a change in the scope of work, is included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the customer are included in the total amount of revenues when it is probable that the counterparty will accept them. 6 Recent accounting principles Accounting standards and interpretations issued by IASB /IFRIC and endorsed by EU By Commission Regulation No. 1205/2011 of November 22, 2011, the Amendments to IFRS 7 “Disclosures - Transfers of financial assets” have been endorsed. The document provides supplementary disclosures on financial instruments, with reference to transfers of financial assets, to describe any risks that may remain with the entity that transferred the assets. The amendments also require additional disclosures if a disproportionate amount of transfer transactions are undertaken around the end of a reporting period. The new provisions shall be applied for annual periods beginning on or after July 1, 2011 (for Eni: 2012 financial statements). F-24 Accounting standards and interpretations issued by IASB/IFRIC and not yet been endorsed by EU On November 12, 2009, the IASB issued IFRS 9 “Financial Instruments” (hereinafter “IFRS 9”) which changes recognition and measurement criteria of financial assets and their classification in the financial statements. In particular, new provisions require, interalia, a classification and measurement model of financial assets based exclusively on the following categories: (i) financial assets measured at amortized cost; and (ii) financial assets measured at fair value. New provisions also require that investments in equity instruments, other than subsidiaries, jointly controlled entities or associates, shall be measured at fair value with effects taken to the profit and loss account. If these investments are not held for trading purposes, subsequent changes in the fair value can be recognized in other comprehensive income, even if dividends are taken to the profit and loss account. Amounts taken to other comprehensive income shall not be subsequently transferred to the profit or loss account even at disposal. In addition, on October 28, 2010, the IASB updated IFRS 9 by incorporating the recognition and measurement criteria of financial liabilities. In particular, new provisions require, interalia, that if a financial liability is measured at fair value through profit or loss, subsequent changes in the fair value attributable to changes in the own credit risk shall be presented in other comprehensive income; the component related to own credit risk is recognized in profit and loss account if the treatment of the changes in own credit risk would create or enlarge an accounting mismatch. On December 16, 2011, the IASB issued the document “Mandatory effective date and transition disclosures” which defer the effective date of IFRS 9 provisions to annual periods beginning on or after January 1, 2015 (previously January 1, 2013). On May 12, 2011, the IASB issued IFRS 10 “Consolidated Financial Statements” (hereinafter “IFRS 10”) and the revised IAS 27 “Separate Financial Statements” (hereinafter “IAS 27”) which respectively state principles for presentation and preparation of consolidated and separate financial statements. IFRS 10 provisions provide, interalia, a new definition of control to be consistently applied to all entities (including vehicles). According to this definition, an entity controls an investee when it is exposed, or has rights, to its (positive and negative) returns from its involvement and has the ability to affect those returns through its power over the investee. The standard provides some indicators to be considered assessing control which include, interalia, potential voting rights, protective rights, the presence of agency relationships and franchise agreements. Furthermore, the new provisions acknowledge the existence of control of an investee even if the investor holds less than majority of voting rights due to shareholding dispersion or passive attitude of other shareholders. IFRS 10 and the revised IAS 27 shall be applied for annual periods beginning on or after January 1, 2013. On May 12, 2011, the IASB issued IFRS 11 “Joint Arrangements” (hereinafter “IFRS 11”) and the revised IAS 28 “Investments in Associates and Joint Ventures” (hereinafter “IAS 28”). Depending on the rights and obligations of the parties arising from arrangements, IFRS 11 classifies joint arrangements into two types – joint operations and joint ventures – and states the required accounting treatment. With reference to joint ventures, the new provisions require to account for them using the equity method, eliminating proportionate consolidation. The revised IAS 28 defines, interalia, the accounting treatment to adopt in case of the disposal of an interest, or a portion of an interest, in a joint venture or an associate. IFRS 11 and the revised IAS 28 shall be applied for annual periods beginning on or after January 1, 2013. On May 12, 2011, the IASB issued IFRS 12 “Disclosure of Interests in Other Entities” (hereinafter “IFRS 12”) combine all the disclosures to be provided in financial statements regarding subsidiaries, joint arrangements, associates and unconsolidated structured entities. IFRS 12 shall be applied for annual periods beginning on or after January 1, 2013. On May 12, 2011, the IASB issued IFRS 13 “Fair Value Measurement” (hereinafter “IFRS 13”) in order to define a framework for fair value measurements, required or permitted by other IFRSs, and the required disclosures about fair value measurements. Fair value is defined as the price that would be received to sell an asset (or paid to transfer a liability) in an orderly transaction between market participants. IFRS 13 shall be applied for annual periods beginning on or after January 1, 2013. On June 16, 2011, the IASB issued Amendments to IAS 1 “Presentation of Items of Other Comprehensive Income” which require, interalia, entities to group, within other comprehensive income, items on the basis of whether they are potentially reclassifiable to profit or loss account subsequently according to applicable IFRSs (reclassification adjustments). The amendments shall be applied for annual periods beginning on or after July 1, 2012 (for Eni: 2013 financial statements). On June 16, 2011, the IASB issued the revised IAS 19 “Employee Benefits” that requires, interalia: (i) to recognize actuarial gains and losses in other comprehensive income, eliminating the possibility to apply the corridor method. Actuarial gains and losses recognized in other comprehensive income will not be recycled through profit or loss account in subsequent periods; and (ii) to replace the separate presentation of the expected return on plan assets and the interest cost, with net interest expense or income. This aggregate is measured applying to the net defined benefit liabilities the discount rate used to measure the obligation. The new provisions require, interalia, additional F-25 disclosures with reference to defined benefit plans. The revised IAS 19 shall be applied for annual periods beginning on or after January 1, 2013. On December 16, 2011, the IASB issued Amendments to IAS 32 “Offsetting Financial Asset and Financial Liabilities” (hereinafter “Amendments to IAS 32”) and Amendments to IFRS 7 “Disclosures - Offsetting Financial Assets and Financial Liabilities” (hereinafter “Amendments to IFRS 7”) which respectively state the requirements for offsetting financial assets and financial liabilities and the related disclosures. In particular, the Amendments to IAS 32 state that: (i) in order to set off financial assets and liabilities, the right of set-off must be legally enforceable in all circumstances, or in the normal course of business, or in the event of default, or in the event of insolvency or bankruptcy, of one or all of the counterparties; and (ii) in presence of specific characteristics, the gross simultaneous settlement of financial assets and liabilities that eliminate or result in insignificant credit and liquidity risk may be considered equivalent to net settlement. The amendments to IAS 32 shall be applied for annual periods beginning on or after January 1, 2014. The amendments to IFRS 7 shall be applied for annual periods beginning on or after January 1, 2013. Eni is currently reviewing these new IFRS to determine the likely impact on the Group’s results. F-26 Current assets 7 Cash and cash equivalents Cash and cash equivalents of (cid:1)1,500 million ((cid:1)1,549 million at December 31, 2010) included financing receivables originally due within 90 days amounting to (cid:1)323 million ((cid:1)339 million at December 31, 2010). The latter were related to amounts on deposit with financial institutions accessible only on a 48-hour notice. The average maturity of financing receivables due within 90 days was 26 days and the average effective interest rate amounted to 1.1%. 8 Other financial assets held for trading or available for sale Other financial assets held for trading or available for sale are set out below: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Securities held for operating purposes Listed bonds issued by sovereign states ....................................................................... Listed securities issued by financial institutions .......................................................... Non-quoted securities .................................................................................................... Securities held for non-operating purposes Listed bonds issued by sovereign states ....................................................................... Listed securities issued by financial institutions .......................................................... Total securities .............................................................................................................. 211 56 6 273 87 22 109 382 173 47 5 225 16 21 37 262 Securities of (cid:1)262 million ((cid:1)382 million at December 31, 2010) were available for sale. At December 31, 2010 and December 31, 2011, no financial assets were held for trading. At December 31, 2011, bonds issued by sovereign states amounted to (cid:1)189 million. A break-down by country is presented below: Nominal value ((cid:1) million) Fair value ((cid:1) million) Nominal rate of return (%) Maturity date Fixed rate bonds Belgium ............................................................... Italy ..................................................................... Austria ................................................................. Portugal ............................................................... Ireland ................................................................. Spain ................................................................... Netherlands ......................................................... Germany ............................................................. France .................................................................. Finland ................................................................ Sweden ................................................................ Slovakia .............................................................. United States of America ................................... Floating rate bonds Italy ..................................................................... Belgium ............................................................... Total .................................................................... 27 18 17 15 15 14 13 11 10 6 4 3 3 31 2 189 from 2.88 to 4.25 from 3.75 to 5.25 from 3.25 to 3.50 from 3.35 to 5.45 from 3.90 to 4.50 from 2.75 to 4.10 from 4.00 to 4.25 from 3.25 to 4.25 4.00 from 1.25 to 4.25 1.88 4.20 2.00 from 2014 to 2021 from 2013 to 2034 from 2013 to 2016 from 2013 to 2019 from 2012 to 2020 from 2012 to 2018 from 2013 to 2016 from 2014 to 2015 from 2013 to 2014 from 2012 to 2015 2012 2017 2012 from 2012 to 2013 2012 27 19 16 24 18 15 12 10 10 6 4 3 3 31 2 200 F-27 The effects of fair value evaluation of securities are set out below: ((cid:1) million) Carrying amount at Dec. 31, 2010 Changes recognized in equity Carrying amount at Dec. 31, 2011 Fair value ................................................................................................. Deferred tax liabilities ............................................................................ Other reserves of shareholders’ equity .............................................. (3) (3) (6) 1 (5) (9) 1 (8) Securities held for operating purposes of (cid:1)225 million ((cid:1)273 million at December 31, 2010) were designed to hedge the loss provisions of the Group’s insurance company Eni Insurance Ltd for (cid:1)220 million ((cid:1)267 million at December 31, 2010). The break-down by currency of other financial assets held for trading or available for sale is presented below: ((cid:1) million) Euro ................................................................................................................................. U.S. dollar ....................................................................................................................... Indian rupee .................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 308 58 16 382 193 51 18 262 The fair value of securities was calculated basing on quoted market prices. 9 Trade and other receivables The break-down of trade and other receivables is presented below: ((cid:1) million) Trade receivables ......................................................................................................... Financing receivables: - for operating purposes - short-term ............................................................................. - for operating purposes - current portion of long-term receivables............................ - for non-operating purposes .......................................................................................... Other receivables: - from disposals ............................................................................................................... - other ............................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 17,221 17,709 436 220 6 662 86 5,667 5,753 23,636 468 162 28 658 169 6,059 6,228 24,595 Receivables are stated net of the valuation allowance for doubtful accounts of (cid:1)1,651 million ((cid:1)1,524 million at December 31, 2010): ((cid:1) million) Trade receivables .............................. Financing receivables ....................... Other receivables ............................... Carrying amount at Dec. 31, 2010 Additions Deductions Other changes Carrying amount at Dec. 31, 2011 962 6 556 1,524 171 6 177 (52) (7) (59) (14) 23 9 1,067 6 578 1,651 F-28 During the course of the 2011, Eni transferred, without notification to factoring institutions, certain trade receivables without recourse due by December 31, 2012, for (cid:1)1,779 million ((cid:1)1,279 million at December 31, 2010, due by December 31, 2011). Transferred receivables mainly related to the Refining & Marketing segment ((cid:1)1,353 million), the Gas & Power segment ((cid:1)377 million) and the Petrochemical segment ((cid:1)49 million). Following the contractual arrangements with the financing institutions, Eni collects the sold receivables and transfers the collected amounts to the respective institutions. Trade receivables increased by (cid:1)488 million from the prior-year balance sheet date mainly in the Gas & Power segment ((cid:1)1,028 million) and the Refining & Marketing segment ((cid:1)103 million). Trade receivable decreased in the Engineering & Construction segment (down by (cid:1)478 million). Trade and other receivables were as follows: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Neither impaired nor past due .................. Impaired (net of the valuation allowance) ................ Not impaired and past due in the following periods: - within 90 days ............................................. - 3 to 6 months ............................................... - 6 to 12 months ............................................. - over 12 months ............................................ Trade receivables Other receivables Total Trade receivables Other receivables Total 14,122 4,451 18,573 14,505 5,062 19,567 1,142 51 1,193 977 221 1,198 1,291 196 177 293 1,957 17,221 74 56 663 458 1,251 5,753 1,365 252 840 751 3,208 22,974 953 360 441 473 2,227 17,709 86 61 190 608 945 6,228 1,039 421 631 1,081 3,172 23,937 Trade receivables not impaired and past due primarily pertained to high-credit-rating public administrations and other highly-reliable counterparties for oil, natural gas and chemical products supplies. Additions to the allowance reserve for doubtful accounts amounted to (cid:1)171 million ((cid:1)201 million in 2010) primarily related to the Gas & Power segment ((cid:1)119 million) and the Refining & Marketing segment ((cid:1)22 million). Utilizations of the reserve amounted to (cid:1)52 million ((cid:1)191 million in 2010) and related to the Gas & Power segment ((cid:1)21 million), the Refining & Marketing segment ((cid:1)13 million) and the Engineering & Construction segment ((cid:1)12 million). Trade receivables included amounts withheld to guarantees certain contract work in progress for (cid:1)103 million ((cid:1)70 million at December 31, 2010). Trade receivables in currencies other than euro amounted to (cid:1)5,693 million. Receivables related to divestment activities included the current portion of the receivable related to the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kashagan government effective from January 1, 2008 ((cid:1)116 million). The reimbursement of the receivable will take place in three annual installments, with the first one due once the commercial production at the Kashagan field starts. Production start-up is currently planned by the end of 2012 or in the first months of 2013. The receivable accrues interest income at market rates. The long-term portion is disclosed under Note 20 – Other non-current receivables. Other receivables of (cid:1)6,059 million included receivables for (cid:1)504 million ((cid:1)482 million at December 31, 2010) relating the recovery of costs incurred to develop an oil&gas project in the Exploration & Production segment. The receivable amount is currently undergoing arbitration procedure. Receivables associated with financing operating activities of (cid:1)630 million ((cid:1)656 million at December 31, 2010) included loans made to unconsolidated subsidiaries, joint ventures and associates for (cid:1)345 million ((cid:1)470 million at December 31, 2010) for executing industrial project. Other amounts included (cid:1)250 million for a cash deposit to hedge the loss provision made by Eni Insurance Ltd ((cid:1)159 million at December 31, 2010) and receivables for financial leasing for (cid:1)31 million ((cid:1)19 million at December 31, 2010). More information about receivables for financial leasing is disclosed under Note 18 – Other financial assets. F-29 Receivables not related to operating activities amounted to (cid:1)28 million ((cid:1)6 million at December 31, 2010) and primarily related to restricted deposits in the Engineering & Construction segment. Financing receivables in currencies other than euro amounted to (cid:1)224 million. Other receivables were as follows: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Receivables originated from divestments ..................................................................... Accounts receivable from: - joint venture operators in exploration and production .............................................. - non-financial government entities .............................................................................. - insurance companies .................................................................................................... - prepayments for services ............................................................................................. - from factoring arrangements ....................................................................................... - other receivables .......................................................................................................... 86 3,017 457 131 1,085 190 787 5,667 5,753 169 3,827 62 171 837 150 1,012 6,059 6,228 Receivables from factoring arrangements of (cid:1)150 million ((cid:1)190 million at December 31, 2010) related to Serfactoring SpA and consisted primarily of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse. Other receivables in currencies other than euro amounted to (cid:1)4,954 million. Receivables with related parties are described under Note 42 – Transactions with related parties. Because of the short-term maturity of trade receivables and other receivables, the fair value approximated their carrying amount. 10 Inventories The break-down of inventories is presented below: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Crude oil, gas and petroleum products 878 117 2,721 3,716 Raw and auxiliary materials and consumables .................. Products being processed and semi-finished products .. Work in progress ................. Finished products and goods Chemical products Work in progress Other Total Crude oil, gas and petroleum products Chemical products Work in progress Other Total 167 33 666 866 1,516 2,561 1 62 1,579 151 428 3,449 6,589 892 127 2,892 3,911 172 25 804 1,001 1,722 2,786 1 71 1,794 153 869 3,767 7,575 869 869 428 428 Contract works in progress for (cid:1)869 million ((cid:1)428 million at December 31, 2010) are stated net of prepayments for (cid:1)11 million ((cid:1)16 million at December 31, 2010) which corresponded to the amount of the works executed and accepted by customers. F-30 Changes in inventories and in the loss provision were as follows: ((cid:1) million) Carrying amount at the beginning of the year Additions New or increased provisions Deductions Changes in the scope of consolidation Currency translation differences Other changes Carrying amount at the end of the year December 31, 2010 Gross carrying amount ................ Loss provision .............................. Net carrying amount ................. December 31, 2011 Gross carrying amount ................ Loss provision .............................. Net carrying amount ................. 5,598 (103) 5,495 6,694 (105) 6,589 822 822 1,091 1,091 (16) (16) (94) (94) 23 23 20 20 124 124 (20) (20) 112 (2) 110 38 (2) 36 38 (7) 31 (42) (5) (47) 6,694 (105) 6,589 7,761 (186) 7,575 Additions for the year amounting to (cid:1)1,091 million were recorded in the Engineering & Construction segment ((cid:1)543 million), the Refining & Marketing segment ((cid:1)249 million) and the Exploration & Production segment ((cid:1)220 million). Increased loss provisions amounting to (cid:1)94 million were mainly recorded in the Petrochemical segment ((cid:1)55 million). Changes in the scope of consolidation of (cid:1)20 million mainly related to Petromar Lda following loss of control ((cid:1)17 million). Other changes of (cid:1)47 million comprised the reclassification to tangible assets of pseudo-working gas pertaining to Stoccaggi Gas Italia SpA ((cid:1)113 million). Following a recent technical study carried out in collaboration with Politecnico di Torino and the Ministry for Economic Development, such gas resulted as not available or re- injectable in an annual cycle of storage. 11 Current income tax assets ((cid:1) million) Italian subsidiaries .......................................................................................................... Foreign subsidiaries ....................................................................................................... Dec. 31, 2010 Dec. 31, 2011 297 170 467 399 150 549 Income tax expenses are described under Note 39 – Income taxes. 12 Other current tax assets ((cid:1) million) VAT ................................................................................................................................ Excise and customs duties ............................................................................................. Other taxes and duties .................................................................................................... Dec. 31, 2010 Dec. 31, 2011 431 192 315 938 581 239 568 1,388 The increase in other taxes and duties amounting to (cid:1)253 million was mainly related to foreign subsidiaries for (cid:1)262 million, of which (cid:1)240 million referred to foreign subsidiaries of the Exploration & Production segment. F-31 13 Other current assets ((cid:1) million) Fair value of non-hedging and trading derivatives ...................................................... Fair value of cash flow hedge derivatives .................................................................... Other current assets ........................................................................................................ Dec. 31, 2010 Dec. 31, 2011 626 210 514 1,350 1,562 157 607 2,326 The fair value of non-hedging derivative contracts and derivatives contracts held for trading is presented below: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments Derivatives on exchange rate Interest currency swap .................................. Currency swap ............................................... Other .............................................................. Derivatives on interest rate Interest rate swap ........................................... Derivatives on commodities Over the counter ............................................ Future ............................................................. Other .............................................................. 123 1 124 1,357 80 1,437 4,411 162 4,573 50 5,819 116 5,985 16 204 2 222 6 6 383 33 86 502 626 2,739 418 3,157 4,594 525 448 973 5,546 1,181 68 85 1,334 1,562 5,644 452 6,096 12,081 833 833 1,885 1,885 4,378 438 581 5,397 8,115 Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods commonly used on the marketplace. Fair values of non-hedging and trading derivatives of (cid:1)1,562 million ((cid:1)626 million at December 31, 2010) consisted of: (i) (cid:1)1,450 million ((cid:1)596 million at December 31, 2010) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; and (ii) (cid:1)112 million ((cid:1)30 million at December 31, 2010) of commodity trading derivatives entered by the Gas & Power segment in order to optimize the economic margin as provided by the new risk management strategy. Fair value of cash flow hedge derivatives of (cid:1)157 million ((cid:1)210 million at December 31, 2010) pertained for (cid:1)154 million to the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated to highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. Negative fair value of contracts expiring by 2012 is disclosed under Note 25 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2012 is disclosed under Note 20 – Other non-current receivables and under Note 30 – Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are given under Note 32 – Shareholders’ equity and under Note 36 – Operating expenses. The nominal value of cash flow hedge derivatives for purchase and sale commitments was (cid:1)3,297 million and (cid:1)610 million, respectively. Information on hedged risks and hedging policies is disclosed under Note 34 – Guarantees, commitments and risks – Risk factors. Other assets amounted to (cid:1)607 million ((cid:1)514 million at December 31, 2010) and included prepayments and accrued income for (cid:1)260 million ((cid:1)155 million at December 31, 2010), insurance premiums for (cid:1)64 F-32 million ((cid:1)52 million at December 31, 2010) and rentals for (cid:1)18 million ((cid:1)20 million at December 31, 2010). Non-current assets 14 Property, plant and equipment ((cid:1) million) December 31, 2010 Land ........................................... Buildings ................................... Plant and machinery ................. Industrial and commercial equipment ............. Other assets ................................ Tangible assets in progress and advances .......... December 31, 2011 Land ........................................... Buildings ................................... Plant and machinery ................. Industrial and commercial equipment ............. Other assets ............................... Tangible assets in progress and advances .......... Net book amount at the beginning of the year Additions Depreciation Impairments Changes in the scope of consolidation Currency translation differences Reclassification to assets held for sale Other changes Net book amount at the end of the year Gross book amount at the end of the year Provisions for depreciation and impairments 618 785 39,858 3 35 3,280 (94) (6,755) (1) (150) 787 543 115 143 (170) (122) 18 19 (652) 4 21 1,721 74 17 18 22 67 665 832 5,689 42,991 693 3,194 28 2,362 108,464 65,473 242 516 991 1,172 2,309 2,583 1,318 1,411 17,174 59,765 8,732 12,308 (7,141) (106) (257) (58) (599) 833 2,614 (5,822) 20,753 714 67,404 22,369 1,616 139,612 72,208 665 832 42,991 991 1,172 9 305 3,704 (131) (6,094) (40) (601) 100 16 383 117 (206) (113) (2) (5) (116) (9) 12 866 (5) 6 (2) (9) (209) 8 458 771 1,427 6,821 47,494 799 3,544 28 2,117 121,166 73,672 (702) (231) 459 829 1,789 2,308 1,330 1,479 (1) 20,753 67,404 7,140 11,658 (6,544) (243) (891) 523 1,393 (221) (5,575) 22,598 779 73,578 24,257 1,659 153,863 80,285 Capital expenditures of (cid:1)11,658 million ((cid:1)12,308 million in 2010) related to the Exploration & Production segment for (cid:1)8,162 million ((cid:1)8,622 million in 2010), the Gas & Power segment for (cid:1)1,281 million ((cid:1)1,251 million in 2010), the Engineering & Construction segment for (cid:1)1,084 million ((cid:1)1,541 million in 2010) and the Refining & Marketing segment for (cid:1)860 million ((cid:1)704 million in 2010). Capital expenditures included capitalized finance expenses of (cid:1)147 million ((cid:1)186 million at December 31, 2010) relating to the Exploration & Production segment ((cid:1)79 million), the Gas & Power segment ((cid:1)36 million), the Refining & Marketing segment ((cid:1)16 million) and the Engineering & Construction segment ((cid:1)12 million). The interest rates used for capitalizing finance expense ranged from 1.0% to 3.7% (0.8% and 4.8% at December 31, 2010). The depreciation rates used ranged as follows: (%) Buildings .............................................................................................................................................. Plant and machinery ............................................................................................................................ Industrial and commercial equipment ................................................................................................ Other assets .......................................................................................................................................... 2 2 4 6 - - - - 10 10 33 33 F-33 The break-down of impairments losses recorded in 2011 amounting to (cid:1)891 million ((cid:1)257 million at December 31, 2010) and the associated tax effect is provided below: ((cid:1) million) 2010 2011 Impairment losses Refining & Marketing .................................................................................................... Exploration & Production .............................................................................................. Petrochemicals ............................................................................................................... Other segments ............................................................................................................... Tax effects Refining & Marketing .................................................................................................... Exploration & Production .............................................................................................. Petrochemicals ............................................................................................................... Other segments ............................................................................................................... Impairments net of the relevant tax effects Refining & Marketing .................................................................................................... Exploration & Production .............................................................................................. Petrochemicals ............................................................................................................... Other segments ............................................................................................................... 72 123 52 10 257 28 49 15 3 95 44 74 37 7 162 484 189 174 44 891 194 65 47 3 309 290 124 127 41 582 In assessing whether impairment is required, the carrying value of an item of property, plant and equipment is compared with its recoverable amount. The recoverable amount is the higher between an asset’s fair value less costs to sell and its value-in-use. Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by using the value-in-use which is calculated by discounting the estimated cash flows arising from the continuing use of an asset. The valuation is carried out for individual asset or for the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets (cash generating unit - CGU). The Group’s has identified its main CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields whereby technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, transport and distribution networks and related facilities, storage sites and re-gasification facilities in a consistent way with the gas segments of operations that are defined by Regulatory Authorities for the purpose of setting tariffs. Other CGUs in the Gas & Power segment are gas carrier ships and plants for the production of electricity; (iii) in the Refining & Marketing segment, refining plants, warehouses and commercial facilities relating to each distribution channels and by country (ordinary network, high- ways network, and wholesale activities); (iv) in the Petrochemical segment, production plants by business and related facilities; and (v) in the Engineering & Construction segment, the business units E&C Offshore and E&C Onshore, onshore drilling facilities and individual rigs for offshore operations. The recoverable amount is calculated by discounting the estimated cash flows deriving from the continuing use of the CGU and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life. The CGUs recoverable amounts in the regulated businesses of gas transportation, distribution, storage and re-gasification equal the regulatory asset base which is recognized by the Regulatory Authority, considering that the operating costs are recovered in tariffs. Cash flows are determined on the basis of the best information available at the moment of the assessment deriving: (i) for the first four years of each projection, from the Company’s four-year plan adopted by the top management which provides information on expected oil and gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates; and (ii) beyond the four- year plan horizon, cash flow projections are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and along a time horizon which considers the following factors: (a) for the oil&gas CGUs, the residual life of the reserves and the associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment, the economical and technical life of the plants and associated projections of operating costs, expenditures to support plant efficiency and refining and marketing margins; (c) for the CGUs of the Petrochemical segment, the economical and technical life of the plants and associated projections of expenditures to support plant efficiency, and normalized operating results plus depreciation; (d) for the CGUs of the gas market and the Engineering & Construction segment, the perpetuity method of the last-year-plan by using a nominal growth rate ranging from F-34 0% to 2%; and (e) for the regulated businesses of gas transportation, distribution, storage and re-gasification, a terminal value equal to the regulatory asset base (RAB) of the last-year-plan; and (ii) commodity prices are estimated on the basis of the forward prices prevailing in the marketplace as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s management for strategic planning purposes and capital budget allocation (see Note 3 – Summary of significant accounting policies). In particular, the long-term price of oil adopted for assessing the future cash flows of the Company’s CGUs was $85 per barrel which is adjusted to take into account the expected inflationary rate from 2015 onwards. Values-in-use are determined by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production, Refining & Marketing and Petrochemical segments to the Company’s weighted average cost of capital, adjusted to consider risks specific to each Country of activity (adjusted post-tax WACC). In 2011, the adjusted post-tax rates used for assessing values-in-use decreased by 0.5 percentage points on average from the previous year reflecting a reduced market risk premium for the Eni’s share. Such trend was partially offset by an increase in the other financial parameters used for determining the cost of capital: cost of borrowings to Eni determined by expected trends for spreads and management’s estimates for the composition of the Company’s finance debt, increased risk-free yields reflecting the higher risk premium for Italy and an appreciation of the Country risk of Eni’s portfolio. In 2011, the adjusted WACC used for impairment test purposes ranged from 7.5% to 12.5%. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. The amount of impairments recorded in the Refining & Marketing segment of (cid:1)484 million reflects management’s expectations of incurring further operating losses due to a continuing weak trading environment for the refining business negatively affected by rising feedstock costs, excess capacity and anticipated poor demand for fuels on the back of the economic downturn. Based on these drivers, management recognized impairment losses of the Company’s refining plants by adjusting their book value to the lower values-in-use considering expectations of negative margins in the short and medium-term. Other minor impairments regarded a retail network, marginal lines of business and certain safety and maintenance expenditures incurred in the period that were written-off because they related to assets previously impaired. The largest impairment losses were recorded at two CGUs which were tested for impairment using a post-tax discount rate of 8%, corresponding to a pre-tax discount rate of 10.7-10.9%. In the Exploration & Production segment were recorded asset impairments for a total amount of (cid:1)189 million which primarily related to gas properties located in USA as a result of a changed price environment and downward reserve revisions. The only material impairment loss referred to a single CGU was assessed using a post-tax discount rate of 7.5%, corresponding to a pre-tax discount rate of 9.7%. In the Petrochemical segment impairment losses amounted to (cid:1)174 million and related to a marginal business line lacking any profitability perspectives and certain safety and maintenance expenditures incurred in the period that were written-off because they related to assets previously impaired. Change in the consolidation area essentially related to the inclusion in the scope of consolidation, following the full acquisition of Terminal Portuário do Guarujá SA ((cid:1)100 million) and, as a decrease, loss of control of Petromar Lda ((cid:1)99 million). Foreign currency translation differences of (cid:1)1,393 million were primarily related to translation of entities accounts denominated in U.S. dollar ((cid:1)1,337 million). The reclassification to assets held for sale of (cid:1)221 million was primarily related to certain non-strategic assets of the Exploration & Production segment ((cid:1)206 million). Other changes of (cid:1)779 million related to the initial recognition and change in estimates of the costs for dismantling and site restoration ((cid:1)740 million) and the reclassification from inventories ((cid:1)113 million) and inventories - compulsory stock ((cid:1)1 million) of pseudo-working gas pertaining to Stoccaggi Gas Italia SpA, as a consequence of a recent technical study carried out in collaboration with Politecnico di Torino and the Ministry for Economic Development for which such gas resulted as not available or re-injectable in an annual cycle of storage. The initial recognition and change in estimates of the costs for dismantling and site restoration ((cid:1)740 million) pertained to the Exploration & Production segment ((cid:1)874 million) and to Stoccaggi Gas Italia SpA (down (cid:1)137 million). The downward estimate revision was made by Stoccaggi Gas Italia SpA reflecting a new time schedule of the disbursements for dismantling and restoring of gas storage sites, which was adopted prospectively from January 1, 2010. It is now assumed that the settlement of the obligations will occur 20 years later than the previous estimates based on the probable time extension of ongoing concessions to operate the relevant storage sites. This assumption is consistent with the tariff-setting mechanism approved by the Authority for Electricity and Gas. F-35 Unproved mineral interests included in tangible assets in progress and advances are presented below: ((cid:1) million) December 31, 2010 Congo ............................................................. USA ................................................................ Turkmenistan ................................................. Algeria ........................................................... Other countries .............................................. December 31, 2011 Congo ............................................................. Nigeria ........................................................... Turkmenistan ................................................. Algeria ........................................................... USA ................................................................ Other countries .............................................. Book amount at the beginning of the year Acquisitions Impairment losses Transfers to Proved Mineral Interest Other changes and currency translation differences Book amount at the end of the year 1,164 882 649 452 231 3,378 1,248 688 446 718 161 3,261 697 57 754 (84) (84) (64) (64) (7) (150) (12) (43) (61) (273) (8) (70) (34) (458) (34) (604) 91 70 51 37 (9) 240 40 61 17 16 21 (6) 149 1,248 718 688 446 161 3,261 1,280 758 635 485 217 121 3,496 Acquisitions for the year related to the awards of blocks and interests in licenses in Nigeria and Algeria. The accumulated provisions for impairments amounted to (cid:1)6,186 million and (cid:1)6,816 million at December 31, 2010 and 2011, respectively. At December 31, 2011, Eni pledged property, plant and equipment for (cid:1)27 million primarily as collateral against certain borrowings ((cid:1)28 million as of December 31, 2010). Government grants recorded as a decrease of property, plant and equipment amounted to (cid:1)724 million ((cid:1)753 million at December 31, 2010). Assets acquired under financial lease agreements amounted to (cid:1)19 million ((cid:1)27 million at December 31, 2010), of which, (cid:1)14 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities and (cid:1)5 million related to service stations in the Refining & Marketing segment. Contractual commitments related to the purchase of property, plant and equipment are disclosed under Note 34 – Guarantees, commitments and risks – Liquidity risk. Property, plant and equipment under concession arrangements are described under Note 34 – Guarantees, commitments and risks – Asset under concession arrangements. F-36 Property, plant and equipment by segment ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Property, plant and equipment, gross Exploration & Production .............................................................................................. Gas & Power .................................................................................................................. Refining & Marketing .................................................................................................... Petrochemicals ............................................................................................................... Engineering & Construction .......................................................................................... Other activities ............................................................................................................... Corporate and financial companies ............................................................................... Elimination of intra-group profits ................................................................................. Accumulated depreciation, amortization and impairment losses Exploration & Production .............................................................................................. Gas & Power .................................................................................................................. Refining & Marketing .................................................................................................... Petrochemicals ............................................................................................................... Engineering & Construction .......................................................................................... Other activities ............................................................................................................... Corporate and financial companies ............................................................................... Elimination of intra-group profits ................................................................................. Property, plant and equipment, net Exploration & Production .............................................................................................. Gas & Power .................................................................................................................. Refining & Marketing .................................................................................................... Petrochemicals ............................................................................................................... Engineering & Construction .......................................................................................... Other activities ............................................................................................................... Corporate and financial companies ............................................................................... Elimination of intra-group profits ................................................................................. 85,494 22,510 14,177 5,226 10,714 1,614 372 (495) 139,612 44,973 8,634 9,411 4,236 3,292 1,536 201 (75) 72,208 40,521 13,876 4,766 990 7,422 78 171 (420) 67,404 96,561 23,655 14,884 5,438 11,809 1,617 422 (523) 153,863 51,034 9,138 10,126 4,478 3,840 1,541 226 (98) 80,285 45,527 14,517 4,758 960 7,969 76 196 (425) 73,578 15 Inventory - compulsory stock ((cid:1) million) Crude oil and petroleum products ................................................................................. Natural gas....................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 1,874 150 2,024 2,284 149 2,433 Compulsory inventories were primarily held by Italian subsidiaries ((cid:1)2,010 million and (cid:1)2,418 million at December 31, 2010 and 2011, respectively) in accordance with minimum stock requirements of oil, petroleum products and natural gas set forth by applicable laws. F-37 16 Intangible assets ((cid:1) million) December 31, 2010 Intangible assets with finite useful lives Exploration expenditures ............................... Industrial patents and intellectual property rights ................................................. Concessions, licenses, trademarks and similar items ............................................. Service concession arrangements .................. Intangible assets in progress and advances ... Other intangible assets ................................... Intangible assets with indefinite useful lives Goodwill .......................................................... December 31, 2011 Intangible assets with finite useful lives Exploration expenditures ............................... Industrial patents and intellectual property rights ................................................. Concessions, licenses, trademarks and similar items ............................................. Service concession arrangements .................. Intangible assets in progress and advances ... Other intangible assets ................................... Intangible assets with indefinite useful lives Goodwill .......................................................... Net book amount at the beginning of the year Additions Depreciation Impairment losses Currency translation differences Other changes Net book amount at the end of the year Gross book amount at the end of the year Provisions for depreciation and impairments 631 1,038 (1,235) 138 38 (87) 671 3,412 581 1,626 7,059 4,410 11,469 40 300 138 8 1,562 (160) (134) (128) (1,744) 1,562 (1,744) (10) (1) (11) (430) (441) 538 1,245 (1,244) 150 37 (85) (2) 575 3,562 658 1,514 6,997 4,175 11,172 10 308 171 9 1,780 (159) (142) (128) (1,758) 1,780 (1,758) (2) (152) (154) 52 1 6 9 68 17 85 17 (1) (13) 7 10 2 12 52 61 23 (12) (60) (1) 63 538 2,323 1,785 150 1,374 1,224 575 3,562 658 1,514 6,997 2,410 6,205 664 2,048 15,024 1,835 2,643 6 534 8,027 178 241 4,175 11,172 8 57 421 (25) (581) 20 (100) 564 2,634 2,070 156 1,474 1,318 847 3,690 248 1,422 6,927 2,827 6,361 254 2,074 15,624 1,980 2,671 6 652 8,697 (2) (102) 4,023 10,950 Exploration expenditures of (cid:1)564 million mainly related to license acquisition costs that are amortized on a straight-line basis over the contractual term of the exploration lease or fully written off against profit and loss upon expiration of terms or management’s decision to cease any exploration activities. Additions for the year included exploration drilling expenditures which were fully amortized as incurred for (cid:1)1,017 million ((cid:1)1,009 million at December 31, 2010). Concessions, licenses, trademarks and similar items for (cid:1)847 million primarily comprised transmission rights for natural gas imported from Algeria ((cid:1)705 million) and concessions for mineral exploration ((cid:1)81 million). Service concession arrangements of (cid:1)3,690 million primarily pertained to Italian gas distribution activities for (cid:1)3,618 million ((cid:1)3,492 million as of December 31, 2010). The distribution of gas is operated through concessions which are granted to distribution companies by local public administrations. In 2011, a specific Decree issued by the Italian Government established 177 territorial basins representing the lowest levels of aggregation of municipalities. The new concessions will be granted based on these new territorial basins. When an existing concession expires, the new operator who takes over the concession will award the previous operator a compensation for the distribution network based on an industrial assessment of the asset value. Tariffs for the distribution service are defined by the Italian Authority for Electricity and Gas. Applicable regulations award concessions to distribution companies exclusively by means of competitive bid. Concessions are granted for a maximum term of 12 years. Government grants recorded as a decrease in the carrying amounts of service concession arrangements amounted to (cid:1)756 million ((cid:1)729 million as of December 31, 2010). Other intangible assets with finite useful lives of (cid:1)1,422 million primarily pertained to: (i) customer relationship and order backlog for (cid:1)1,036 million ((cid:1)1,140 million at December 31, 2010) recognized upon the business combination of Distrigas NV. These assets are amortized on the basis of the supply contract with the longest term (19 years) and the residual useful life of sale contracts (4 years); (ii) an option to develop offshore storage capacity for the commercial modulation of gas in the British North Sea which was recognized upon the acquisition of Eni Hewett Ltd amounting to (cid:1)248 million ((cid:1)241 million at December 31, 2010). The asset impairment test confirmed the recoverability of the book value; (iii) royalties for the use of licenses by Polimeri F-38 Europa SpA amounting to (cid:1)60 million ((cid:1)64 million at December 31, 2010); and (iv) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri and in North Adriatic area connected to mineral rights under concession for (cid:1)50 million ((cid:1)35 million at December 31, 2010) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna. The depreciation rates used were as follows: (%) Exploration expenditures .................................................................................................................... Industrial patents and intellectual property rights ............................................................................. Concessions, licenses, trademarks and similar items ....................................................................... Service concession arrangements ....................................................................................................... Other intangible assets ........................................................................................................................ 14 20 3 2 4 - - - - - 33 33 33 20 25 Impairment losses of intangible assets with indefinite useful life (goodwill) amounted to (cid:1)152 million and mainly related to the Gas & Power segment ((cid:1)149 million), as described below. The carrying amount of goodwill at the end of the year was (cid:1)4,023 million ((cid:1)4,175 million at December 31, 2010) net of cumulative impairments amounting to (cid:1)726 million. The break-down of goodwill by operating segment is as follows: ((cid:1) million) Gas & Power .................................................................................................................. Engineering & Construction .......................................................................................... Exploration & Production............................................................................................... Refining & Marketing..................................................................................................... Dec. 31, 2010 Dec. 31, 2011 3,000 749 262 164 4,175 2,845 749 270 159 4,023 Goodwill acquired through business combinations has been allocated to the cash generating units (“CGUs”) that are expected to benefit from the synergies of the acquisition. The CGUs of the Gas & Power segment are represented by such commercial business units whose cash flows are largely interdependent and therefore benefit from acquisition synergies. The recoverable amounts of the CGUs are determined by discounting the future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from their disposal at the end of the useful life. The CGUs recoverable amounts in the regulated businesses of gas transportation, distribution, storage and re-gasification equal the regulatory asset base which is recognized by the Regulatory Authority, considering that the operating costs are recovered in tariffs. Cash flows are determined on the basis of the best information available at the moment of the assessment deriving: (i) for the first four years of each projection, from the Company’s four-year plan adopted by the top management which provides information on expected oil and gas production volumes, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates; (ii) beyond the four-year plan horizon, cash flow projections are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and along a time horizon which considers the following factors: (a) for the oil&gas CGUs, the residual life of the reserves and the associated projections of operating costs and development expenditures; (b) for the CGUs of the Refining & Marketing segment, the economical and technical life of the plants and associated projections of operating costs, expenditures to support plant efficiency and refining and marketing margins; (c) for the CGUs of the gas market and the Engineering & Construction segment, the perpetuity method of the last-year-plan by using a nominal growth rate ranging from 0% to 2%; and (d) for the regulated businesses of gas transportation, distribution, storage and re-gasification, a terminal value equal to the regulatory asset base (RAB) of the last-year-plan; and (iii) commodity prices are estimated on the basis of the forward prices prevailing in the marketplace as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s management for strategic planning purposes and capital budget allocation (see Note 3 – Summary of significant accounting policies). In particular, the long-term price of oil adopted for assessing the future cash flows of the Company’s CGUs was $85 per barrel which is adjusted to take into account the expected inflationary rate from 2015 onwards. F-39 Values-in-use are determined by discounting post-tax cash flows at a rate which corresponds: (i) for the Exploration & Production, Refining & Marketing and Petrochemical segments to the Company’s weighted average cost of capital, adjusted to consider risks specific to each Country of activity (adjusted post-tax WACC). In 2011, the adjusted post-tax rates used for assessing values-in-use decreased by 0.5 percentage points on average from the previous year reflecting a reduced market risk premium for the Eni’s share. Such trend was partially offset by an increase in the other financial parameters used for determining the cost of capital: cost of borrowings to Eni determined by expected trends for spreads and management’s estimates for the composition of the Company’s finance debt, increased risk-free yields reflecting the higher risk premium for Italy and an appreciation of the Country risk of Eni’s portfolio. In 2011, the adjusted WACC used for impairment test purposes ranged from 7.5% to 12.5%; (ii) the impairment test rate for the Gas & Power segment was estimated on the basis of a sample of comparable companies in the utility industry. The impairment test rate for the Engineering & Construction segment was derived from market data. Rates used in the Gas & Power segment were adjusted to take into consideration risks specific to each Country of activity, while rates used in the Engineering & Construction segment did not reflect any Country risks as most of the Company assets are not permanently located in a specific Country. Rates for the Gas & Power segment ranged from 7% to 8%, unchanged from the previous year as the decrease observed in the equity risks for gas companies was lower than the oil sector and was offset by an increase in the other financial parameters used for determining the cost of capital. In the Engineering & Construction segment, the discount rate was 8.5%, with a decrease of 0.5 percentage points from the previous year due to a lower equity risk; and (iii) for the regulated activities, the discount rates were assumed to be equal to the rates of return defined by the Italian Authority for Electricity and Gas. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. Goodwill has been allocated to the following CGUs: Gas & Power segment ((cid:1) million) Domestic gas market ...................................................................................................... Foreign gas market ......................................................................................................... - of which European market .......................................................................................... Domestic natural gas transportation network ............................................................... Other ............................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 767 1,918 1,722 305 10 3,000 767 1,763 1,668 305 10 2,845 Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of Italgas SpA minorities in 2003 through a public offering ((cid:1)706 million). This CGU engages in supplying gas to residential customers and small businesses. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of that CGU, including the allocated goodwill. Goodwill allocated to the CGU European market was mainly recognized upon the purchase price allocation of the Distrigas business combination in 2009. The CGU comprises Distrigas marketing activities and those activities managed directly or indirectly by the Gas & Power Division of the Parent Company Eni SpA, which includes marketing activities in France, Germany, Benelux, UK, Switzerland and Austria. Those business units jointly benefited from the business combination synergies. In 2011, this goodwill was increased by (cid:1)95 million as the result of definitive allocation of the goodwill related to the purchase in 2010 of Altergaz SA. In performing the impairment review of the recoverability of the CGU carrying amount at the balance sheet date, management recognized an impairment loss amounting to (cid:1)149 million considering a reduced profitability outlook for the gas business over the short to medium-term. The key assumptions adopted in assessing future cash flow projections of both the CGUs domestic market and European market included marketing margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers was derived from the four-year-plan approved by the Company’s top management which reduced with respect to past reviews the projected returns and cash flows particularly in the European market, driven by expectations for weak demand growth due to the current economic downturn, continuing competitive pressures fuelled by oversupplies, and increased commercial risk. The European market is expected to be negatively affected by lowering marketing margins over the next four years. This reflects ongoing development of very liquid spot markets for gas and the circumstance that spot prices have increasingly become the prevailing reference price for contractual formulae in supplies outside Italy, whereas Eni’s purchase F-40 costs for gas are mainly indexed to the price of oil and refined products. In the current trading environment gas spot prices are expected to fail to track the oil-linked cost of Eni’s supplies as weak demand growth and oversupplies will continue to fuel pricing competition among gas operators. This trend will negatively affect gas margins. Management believes that trends in spot prices and oil-linked costs of supplies will re-couple in 2014 at the earliest. Compared to the impairment review performed in 2010, management is now assuming: (i) an average reduction of 25% in unit marketing margins on future gas sales used to assess the value-in-use of the European market CGU; and (ii) an average reduction of 3% in planned sales volumes; while the discount rate and the growth rate are unchanged from previous assumptions. The industrial and financial forecasts for the next four-year plan of the gas business as well as the amount of the impairment loss recognized in 2011 consolidated accounts both take into consideration management assumptions to renegotiate better economic terms within the Company’s long-term gas purchase contracts, so as to restore the competitiveness of the Company’s cost position in the current depressed scenario for the gas sector. In the course of 2011, Eni finalized a number of important contractual renegotiations by obtaining improved economic conditions for supplies and wider contractual flexibility with a benefit to its commercial programs. In the first quarter 2012 management has finalized new important renegotiations the economic benefits of which have been determined considering the whole 2011 (see Note 45 – Subsequent events). The terminal value of the CGUs was estimated based on the perpetuity method of the last year of the plan assuming a long-term nominal growth rate equal to zero for both the CGUs. Value in use of the CGU European market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7.5% that corresponds to the pre-tax rate of 9.3% (unchanged from the previous year). Value-in-use of the CGU Italian market was assessed by discounting the associated post-tax cash flows at a post-tax rate of 7% that corresponds to the pre-tax rate of 13.1% (7% and 11.7%, respectively in the previous year). The excess of the recoverable amount of the CGU domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to (cid:1)298 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 27.1% on average in the projected commercial margins; (ii) a decrease of 27.1% on average in the projected sales volumes; (iii) an increase of 3.3 percentage points in the discount rate; and (iv) a negative nominal growth rate of 4.4%. The recoverable amount of the CGU and the relevant sensitivity analysis were calculated solely on the basis of retail margins, thus excluding wholesale and business client margins (industrial, thermoelectric and others). Goodwill allocated to the domestic natural gas transportation network CGU was recognized alongside the repurchase of own shares by Snam Rete Gas SpA and equals the difference between the purchase cost over the carrying amount of the corresponding share of net equity. The recoverable amount of the CGU is assessed based on its Regulatory Asset Base (RAB) as recognized by the Italian Authority for Electricity and Gas and is higher than its carrying amount, including the allocated goodwill. Management believes that no reasonable change in the assumptions adopted would cause the headroom of the CGU to be reduced to zero. Engineering & Construction segment ((cid:1) million) E&C Offshore ................................................................................................................ E&C Onshore ................................................................................................................. Other ............................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 415 318 16 749 415 315 19 749 The segment goodwill of (cid:1)749 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA ((cid:1)710 million) and allocated to the CGUs E&C Offshore and E&C Onshore. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amounts of both those CGUs, including the allocated portions of goodwill. The key assumptions adopted for assessing the recoverable amounts of those two CGUs which exceeded their respective carrying amounts related to operating results, the discount rate and the growth rates adopted to determine the terminal value. Information on those drivers were collected from the four-year-plan approved by the Company’s top management, while the terminal value was estimated by using a perpetual nominal growth rate of 2% applied to the cash flow of the last year in the four-year plan. Value in use of both CGUs was assessed by discounting the associated post-tax cash flows at a post-tax rate of 8.5% (9% in 2010) which corresponds to the pre-tax rate of 11.1% and 12.1% for the E&C Offshore business unit and the E&C Onshore one, respectively (11.8% and 13%, respectively in the previous year). The headroom of the E&C Offshore business unit of (cid:1)4,942 million would be reduced to zero under each of the following alternative changes in the above mentioned assumptions: (i) a decrease F-41 of 57% in the operating result of the four-year plan; (ii) an increase of about 9 percentage points in the discount rate; and (iii) negative real growth rate. Changes in each of the assumptions that would cause the headroom of the E&C Onshore business unit to be reduced to zero are greater than those applicable to the E&C Offshore construction CGU described above. The Exploration & Production and the Refining & Marketing segments tested their goodwill, yielding the following results: (i) in the Exploration & Production segment with goodwill amounting to (cid:1)270 million, management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the purchase price that was not allocated to proved or unproved mineral interests of the business combinations Lasmo, Burren Energy (Congo) and First Calgary (Algeria) executed in previous reporting periods; and (ii) in the Refining & Marketing segment goodwill amounted to (cid:1)159 million at the balance sheet date. Goodwill amounting to (cid:1)63 million pertained to retail networks in the Czech Republic, Hungary and Slovakia which were purchased in 2008, for which profitability expectations have remained unchanged from the previous-year impairment review. Additionally, goodwill of (cid:1)76 million included the allocation of the purchase price of a business combination involving a network of service stations in Austria acquired in 2010 and marginal lines of business in Italy and Europe ((cid:1)20 million) that were impaired for an amount of (cid:1)3 million. 17 Investments Investments accounted for using the equity method ((cid:1) million) December 31, 2010 Investments in unconsolidated entities controlled by Eni ....................................... Joint ventures ............................................. Associates .................................................. December 31, 2011 Investments in unconsolidated entities controlled by Eni ....................................... Joint ventures ............................................. Associates .................................................. Book amount at the beginning of the year Additions Share of profit of equity- accounted investments Share of loss of equity- accounted investments Divestments and reimbursements Deduction for dividends Currency translation differences Other changes Book amount at the end of the year 217 3,327 2,284 5,828 256 2,735 2,677 5,668 32 44 187 263 8 93 134 235 (3) (526) (33) (562) (19) (35) (34) (88) 75 379 263 717 35 376 267 678 (18) (124) (7) (149) (7) (68) (31) (106) (38) (312) (130) (480) (39) (276) (138) (453) 9 124 81 214 4 45 45 94 (18) (177) 32 (163) (16) (268) 99 (185) 256 2,735 2,677 5,668 222 2,602 3,019 5,843 Addition for the year of (cid:1)235 million mainly related to a capital contribution made to Angola LNG Ltd ((cid:1)129 million) which is currently engaged in building a liquefaction plant in order to monetize Eni’s gas reserves in that country (Eni’s interest in the project being 13.6%). Other capital contributions related to the subscription of the new companies Zagoryanska Petroleum BV ((cid:1)30 million), Est Più Società per Azioni ((cid:1)29 million) and Pokrovskoe Petroleum BV ((cid:1)26 million). Divestments and reimbursements of equity-accounted investments of (cid:1)88 million mainly pertained to the capital reimbursement of Eteria Parohis Aeriou Thessalonikis AE ((cid:1)34 million) and the sale of Viscolube SpA ((cid:1)32 million). F-42 Share of profit of equity-accounted investments and the decrease following the distribution of the dividends pertained to the following companies: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Share of profit of equity- accounted investments Deduction for dividends Eni’s interest (%) Share of profit of equity- accounted investments Deduction for dividends Eni’s interest (%) Unión Fenosa Gas SA ................................... Galp Energia SGPS SA ................................ United Gas Derivatives Co ........................... PetroSucre SA ............................................... Blue Stream Pipeline Co BV ........................ Unimar Llc ..................................................... Saipon Snc ..................................................... Eni BTC Ltd .................................................. Azienda Energia e Servizi Torino SpA ....... Supermetanol CA .......................................... Trans Austria Gasleitung GmbH .................. Other investments ......................................... 116 147 47 15 36 18 24 37 26 98 153 717 50.00 33.34 33.33 26.00 50.00 50.00 60.00 100.00 49.00 34.51 89.00 126 55 44 7 23 35 24 15 67 84 480 152 144 49 37 34 32 31 28 23 17 131 678 50.00 33.34 33.33 26.00 50.00 50.00 60.00 100.00 49.00 34.51 148 39 44 9 34 26 25 128 453 Share of losses of equity-accounted investments related to the following companies: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 EnBW Eni Verwaltungsgesellschaft mbH ............................................ GreenStream BV ..................................................................................... Enirepsa Gas Ltd ..................................................................................... CARDÓN IV SA ..................................................................................... Pokrovskoe Petroleum BV ..................................................................... Artic Russia BV ...................................................................................... Immobiliare Est SpA ............................................................................... Super Octanos CA ................................................................................... Starstroi Llc ............................................................................................. Altergaz SA ............................................................................................. Other investments ................................................................................... Share of loss of equity- accounted investments Share of loss of equity- accounted investments Eni’s interest (%) 30 23 14 12 9 7 1 10 106 50.00 60.00 100.00 49.00 50.00 41.62 40 14 10 36 14 10 25 149 Eni’s interest (%) 50.00 50.00 50.00 50.00 30.00 60.00 100.00 Share of losses of equity-accounted investments in EnBW Eni Verwaltungsgesellschaft mbH was driven by a reduced profitability outlook due to the current downturn in the European gas market. GreenStream BV incurred losses caused by the shut down of the import pipeline from Libya, throughout the peak of the Country’s internal crisis (which lasted approximately 6 months). The GreenStream pipeline was restarted the last part of the year. Other changes of (cid:1)185 million included the full write-down of the book value, recognized as “income (expense) from investments”, of Ceska Rafinerska AS in relation to the impairment test of the relevant CGU due to management’s expectation of incurring future losses driven by a negative outlook for the refining segment ((cid:1)157 million). The transfer to investments in unconsolidated controlled entities of Eni Medio Oriente SpA occurred in 2011 following the exclusion from the scope of consolidation due to immateriality ((cid:1)11 million). F-43 List of equity-accounted investments: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Net carrying amount Number of shares held Eni’s interest (%) Net carrying amount Number of shares held Eni’s interest (%) Investments in unconsolidated entities controlled by Eni: - Eni BTC Ltd .................................................................. - Eni BBI Ltd ................................................................... - Other investments (*) ...................................................... Joint ventures: - Blue Stream Pipeline Co BV......................................... - Unión Fenosa Gas SA ................................................... - Artic Russia BV ............................................................ - Azienda Energia e Servizi Torino SpA ....................... - Toscana Energia SpA .................................................... - Eteria Parohis Aeriou Thessalonikis AE ..................... - Raffineria di Milazzo ScpA .......................................... - GreenStream BV ........................................................... - Unimar Llc ..................................................................... - CARDÓN IV SA .......................................................... - Supermetanol CA .......................................................... - Eteria Parohis Aeriou Thessalias AE ........................... - Zagoryanska Petroleum BV ......................................... - Est Più Società per Azioni ............................................ - Saipon Snc ..................................................................... - EnBW Eni Verwaltungsgesellschaft mbH .................. - Starstroi Llc ................................................................... - Other investments (*) ...................................................... Associates: - Galp Energia SGPS SA ................................................ - Angola LNG Ltd ........................................................... - PetroSucre SA ............................................................... - EnBW Eni Verwaltungsgesellschaft mbH .................. - United Gas Derivatives Co ........................................... - Fertilizantes Nitrogenados de Oriente CEC ................ - ACAM Gas SpA ........................................................... - Distribuidora de Gas del Centro SA ............................ - Termica Milazzo Srl ..................................................... - Gaz de Bordeaux SAS .................................................. - Rosetti Marino SpA ...................................................... - Ceska Rafinerska AS .................................................... - Other investments (*) ...................................................... 34,000,000 1,200,000 100.00 100.00 34,000,000 1 100.00 100.00 104 28 124 256 435 468 445 172 155 160 128 147 74 17 66 43 21 285 19 100 2,735 1,005 841 198 1,000 273,100 12,000 54,150,000 70,304,854 150,846,500 175,000 100,000,000 50 4,305 49,000,000 38,445,008 12,000 1 1 276,472,161 961,209,900 26,000 94 950,000 68 1,933,662,121 3,336,410 48 50,303,329 32 9,296,400 40 257,576 27 800,000 24 189 303,301 111 2,677 5,668 50.00 50.00 60.00 49.00 48.13 49.00 50.00 50.00 50.00 50.00 34.51 49.00 60.00 50.00 50.00 33.34 13.60 26.00 33.33 20.00 49.00 31.35 40.00 34.00 20.00 32.44 100 122 222 476 465 428 169 159 130 130 128 111 74 59 45 32 30 30 136 2,602 1,000 273,100 12,000 54,150,000 70,304,854 116,546,500 175,000 100,000,000 50 6,455 49,000 38,445,008 10,800 2,940,000 12,000 244 237 102 1,103 276,472,161 1,008 1,141,284,004 5,727,800 1 950,000 68 1,933,662,121 3,336,410 48 50,303,329 31 9,296,400 26 257,576 26 800,000 25 303,301 101 3,019 5,843 50.00 50.00 60.00 49.00 48.08 49.00 50.00 50.00 50.00 50.00 34.51 49.00 60.00 70.00 60.00 33.34 13.60 26.00 50.00 33.33 20.00 49.00 31.35 40.00 34.00 20.00 32.44 ______ (*) Each individual amount included herein did not exceed (cid:1)25 million. Carrying amounts of investments in unconsolidated entities, including entities controlled by Eni, joint ventures and associates, comprised differences between the purchase price of relevant shareholdings and the corresponding Eni’s share in the net equity of each entities amounting to (cid:1)512 million, of which (cid:1)354 million referred to goodwill. Such differences primarily related to Unión Fenosa Gas SA for (cid:1)195 million of goodwill, EnBW Eni Verwaltungsgesellschaft mbH for (cid:1)174 million (of which: goodwill (cid:1)16 million) and Galp Energia SGPS SA for (cid:1)106 million (goodwill). F-44 The fair value of an investment listed on a regulated exchange market was as follows: Galp Energia SGPS SA ................................................ 276,472,161 33.34 11.38 3,146 Shares (No.) Ownership (%) Price per share ((cid:1)) Fair value ((cid:1) million) The table below sets out the provisions for losses included in the provisions for contingencies of (cid:1)151 million ((cid:1)124 million at December 31, 2010), primarily related to the following equity-accounted investments: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) ............................. Southern Gas Constructors Ltd ..................................................................................... Charville - Consultores e Serviços Lda ........................................................................ Other investments .......................................................................................................... 59 31 12 22 124 100 11 7 33 151 Other investments ((cid:1) million) December 31, 2010 Investments in unconsolidated entities controlled by Eni .......... Associates .................................. Other investments ...................... December 31, 2011 Investments in unconsolidated entities controlled by Eni .......... Associates .................................. Other investments ...................... Net book amount at the beginning of the year Additions Currency translation differences Other changes Net book amount at the end of the year Gross book amount at the end of the year Accumulated impairment charges 44 8 364 416 29 10 383 422 2 1 16 19 (1) (10) 7 (4) (17) 1 (1) (17) (27) 13 (15) (29) 29 10 383 422 3 13 383 399 29 18 390 437 3 21 390 414 4 4 2 8 10 8 7 15 8 7 15 Investments in unconsolidated entities controlled by Eni and associates are stated at cost net of impairment losses. Other investments, for which fair value cannot be reliably determined, were recognized at cost and adjusted for impairment losses. The net carrying amount of other investments of (cid:1)399 million ((cid:1)422 million at December 31, 2010) was related to the following entities: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Net carrying amount Number of shares held Eni’s interest (%) Net carrying amount Number of shares held Eni’s interest (%) Investments in unconsolidated entities controlled by Eni (*).............................................. Associates ......................................................................... Other investments: - Interconnector (UK) Ltd ............................................... - Nigeria LNG Ltd ........................................................... - Darwin LNG Pty Ltd .................................................... - other (*) ........................................................................... 29 10 136 89 79 79 383 422 2,050,017 118,373 213,995,164 16.07 10.40 10.99 3 13 136 91 73 83 383 399 2,050,017 118,373 213,995,164 16.07 10.40 10.99 _______ (*) Each individual amount included herein did not exceed (cid:1)25 million. F-45 Provisions for losses related to other investments, included within the provisions for contingencies, amounted to (cid:1)21 million ((cid:1)76 million at December 31, 2010) and were primarily in relation to the following entities: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Caspian Pipeline Consortium R - Closed Joint Stock Co ............................................ Eni BB Ltd (in liquidation) ............................................................................................ Other investments .......................................................................................................... 19 28 29 76 16 5 21 Other information about investments The following table summarizes key financial data, net to Eni, as disclosed in the latest available financial statements of unconsolidated entities controlled by Eni, joint ventures and associates: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Unconsolidated entities controlled by Eni Joint ventures Associates Total assets .................................................... Total liabilities ............................................... Net sales from operations ............................. Operating profit ............................................. Net profit ........................................................ 2,383 2,193 113 (9) 32 5,711 3,022 3,497 434 252 5,087 2,410 5,134 323 225 Unconsolidated entities controlled by Eni 2,393 2,279 86 (2) 41 Joint ventures 5,655 3,085 3,011 484 299 Associates 6,165 3,144 6,347 316 234 The total assets and liabilities of unconsolidated controlled entities of (cid:1)2,393 million and (cid:1)2,279 million, respectively ((cid:1)2,383 million and (cid:1)2,193 million at December 31, 2010) pertained to entities acting as sole-operator in the management of oil and gas contracts for (cid:1)2,208 million and (cid:1)2,096 million ((cid:1)2,172 million and (cid:1)2,054 million at December 31, 2010). The residual amount pertained to not significant entities that were excluded from the scope of consolidation for the reasons described under Note 1 – Basis of presentation. 18 Other financial assets ((cid:1) million) Receivables for financing operating activities .............................................................. Securities held for operating purposes........................................................................... Dec. 31, 2010 Dec. 31, 2011 1,488 35 1,523 1,516 62 1,578 Receivables for financing operating activities are stated net of the valuation allowance for doubtful accounts of (cid:1)32 million (the same amount as of December 31, 2010). F-46 Operating financing receivables of (cid:1)1,516 million ((cid:1)1,488 million at December 31, 2010) primarily pertained to loans granted by the Exploration & Production segment ((cid:1)826 million), the Gas & Power segment ((cid:1)517 million) and the Refining & Marketing segment ((cid:1)83 million) and receivables for financial leasing for (cid:1)47 million ((cid:1)78 million at December 31, 2010). Financing receivables granted to unconsolidated subsidiaries, joint ventures and associates amounted to (cid:1)694 million. Receivables for financial leasing pertained to the disposal of the Belgian gas network by Finpipe GIE. The following table shows principal receivable by maturity date, which was obtained by summing future lease payment receivables discounted at the effective interest rate, interest and the nominal value of future lease receivables: ((cid:1) million) Maturity range Within 12 months Between one and five years Total Principal receivable ................................................................................. Interest ..................................................................................................... Undiscounted value of future lease payments .................................. 31 5 36 47 5 52 78 10 88 Receivables with a maturity date within one year is disclosed among current assets in the item trade receivables for operating purposes - current portion of long-term receivables under Note 9 – Trade and other receivables. Receivables for financing operating activities in currencies other than euro amounted to (cid:1)1,338 million ((cid:1)1,128 million at December 31, 2010). Receivables for financing operating activities due beyond five years amounted to (cid:1)896 million ((cid:1)823 million at December 31, 2010). The valuation at fair value of financing receivables of (cid:1)1,574 million has been determined based on the present value of expected future cash flows discounted at rates ranging from 0.7% to 3.1% (0.8% and 4.1% at December 31, 2010). Receivables with related parties are described under Note 42 – Transactions with related parties. Securities of (cid:1)62 million ((cid:1)35 million at December 31, 2010), designated as held-to-maturity investments, are listed bonds issued by the Italian Government ((cid:1)26 million) and foreign governments ((cid:1)36 million), of which Belgium (cid:1)10 million, Spain (cid:1)9 million and France (cid:1)5 million. Securities with a maturity beyond five years amounted to (cid:1)24 million. The valuation at fair value of financial securities has resulted in marginal effects. The fair value of securities was derived from quoted market prices. 19 Deferred tax assets Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for (cid:1)4,045 million ((cid:1)3,421 million at December 31, 2010). ((cid:1) million) Amount at Dec. 31, 2010 Additions Deductions Currency translation differences Other changes Amount at Dec. 31, 2011 4,864 2,036 (882) 145 (649) 5,514 Deferred tax assets are described under Note 29 – Deferred tax liabilities. Income tax expenses are described under Note 39 – Income taxes. F-47 20 Other non-current receivables ((cid:1) million) Tax receivables from: - Italian tax authorities . income tax .................................................................................................................. . interest on tax credits ................................................................................................ - foreign tax authorities .................................................................................................. Other receivables: - related to divestments .................................................................................................. - other non-current ......................................................................................................... Fair value of non-hedging and trading derivatives ...................................................... Fair value of cash flow hedge derivatives .................................................................... Other asset ...................................................................................................................... Dec. 31, 2010 Dec. 31, 2011 14 65 79 106 185 800 224 1,024 420 102 1,624 3,355 16 66 82 72 154 535 258 793 714 33 2,531 4,225 Receivables originated from divestments amounted to (cid:1)535 million and comprised: (i) the residual outstanding amount of (cid:1)302 million recognized following the compensation agreed with the Republic of Venezuela for the expropriated Dación oilfield. The receivable accrues interests at market conditions as the collection has been fractionated in installments. As agreed by the parties, the reimbursement is in kind through equivalent assignment of volumes of crude oil. In the 2011, Eni collected nine loads of oil for a total amount equal to (cid:1)187 million (US$260 million). In January 2012, Eni collected a further load for an amount equal to US$29 million. Negotiations for further equivalent collections of hydrocarbons are ongoing; and (ii) the long-term portion of a receivable related to the divestment of the 1.71% interest in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kashagan government, which became effective from January 1, 2008 ((cid:1)220 million). The reimbursement of the receivable is provided for in three annual installments commencing from the date of the production start-up which is planned at the end of 2012 or in the first months of 2013. The receivable accrues interest income at market rates. The short-term portion is disclosed under Note 9 – Trade and other receivables. The fair values of non-hedging derivative contracts and derivative contracts held for trading were as follows: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments Derivatives on exchange rate Interest currency swap .................................. Currency swap ............................................... Derivatives on interest rate Interest rate swap ........................................... Derivatives on commodities Over the counter ............................................ Future ............................................................. Other .............................................................. 171 11 182 83 83 134 21 155 420 714 83 797 691 691 95 99 194 3,615 3,615 1,578 119 1,578 3,066 54 173 3,982 277 16 293 82 82 326 2 11 339 714 948 197 1,145 713 713 3,010 120 3,130 4,988 219 219 300 300 922 116 1,038 1,557 Derivative fair values are calculated basing on market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques generally adopted in the marketplace. Fair values of non-hedging and trading derivatives of (cid:1)714 million ((cid:1)420 million at December 31, 2010) consisted of: (i) (cid:1)680 million ((cid:1)392 million at December 31, 2010) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net F-48 exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not related to specific trade or financing transactions; and (ii) (cid:1)34 million ((cid:1)28 million at December 31, 2010) of commodity trading derivatives entered by the Gas & Power segment in order to optimize the economic margin as provided by the new risk management strategy. Fair value of cash flow hedge derivatives of (cid:1)33 million ((cid:1)102 million at December 31, 2010) regarded the Gas & Power segment. Further information is disclosed under Note 13 – Other current assets. Fair value related to the contracts expiring beyond 2012 is disclosed under Note 30 – Other non-current liabilities; fair value related to the contracts expiring in 2012 is disclosed under Note 13 – Other current assets and under Note 25 – Other current liabilities. The effects of fair value evaluation of cash flow hedges are disclosed under Note 32 – Shareholders’ equity and Note 36 – Operating expenses. The nominal values of cash flow hedge derivatives for purchase and sale commitments were (cid:1)204 million and (cid:1)379 million, respectively. Information on the hedged risks and the hedging policies is disclosed under Note 34 – Guarantees, commitments – Risk factors. Other non-current asset of (cid:1)2,531 million ((cid:1)1,624 million at December 31, 2010) mainly included prepayments amounting to (cid:1)2,227 million ((cid:1)1,436 million at December 31, 2010) that were made to gas suppliers upon triggering the take-or-pay clause provided by the relevant long-term supply arrangements. The increase was due to the circumstance that the Company’s gas off-takes for the year were lower than the annual minimum quantity thus triggering the take-or-pay clause, net of limited amounts of volumes make-up on previous-year prepayments. In accordance to those arrangements, the Company is contractually required to off-take minimum annual quantities of gas, or in case of failure is held to pay the whole price or a fraction of it for the uncollected volumes up to the minimum annual quantity. The Company is entitled to off-take the pre-paid volumes in future years alongside the contract execution, for its entire duration or a shorter term as the case may be. The carrying amounts of those deferred costs, which are substantially equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-years impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. The amount of volumes pre-paid reflects ongoing difficult market condition in the European gas sector due to weak demand and strong competitive pressures fuelled by oversupplies. In future years, management plans to recover the pre-paid volumes once current market imbalances have been absorbed, leveraging the expected long-term growth outlook in gas demand, and a projected sales expansion in target European markets and Italy supported by strengthening the Company’s market leadership and an improved competitiveness of the Company’s cost position. F-49 Current liabilities 21 Short-term debt ((cid:1) million) Banks .............................................................................................................................. Commercial papers ........................................................................................................ Other financial institutions ............................................................................................ Dec. 31, 2010 Dec. 31, 2011 1,950 4,244 321 6,515 786 2,997 676 4,459 Short-term debt decreased by (cid:1)2,056 million mainly due to net repayments ((cid:1)2,481 million), partially offset by a change in the scope of consolidation due to the divestment of Eni Gas Transport Deutschland SpA, Eni Gas Transport GmbH and Eni Gas Transport International SA ((cid:1)170 million) and currency and translation differences ((cid:1)138 million). Commercial papers of (cid:1)2,997 million ((cid:1)4,244 million at December 31, 2010) were issued by the Group’s financial subsidiaries Eni Finance International SA ((cid:1)2,111 million) and Eni Finance USA Inc ((cid:1)886 million). The break-down by currency of short-term debt is provided below: ((cid:1) million) Euro ................................................................................................................................. U.S. dollar ....................................................................................................................... Other currencies ............................................................................................................. Dec. 31, 2010 Dec. 31, 2011 2,919 3,403 193 6,515 2,896 1,430 133 4,459 In 2011, the weighted average interest rate on short-term debt was 1.1% (0.7% in 2010). At December 31, 2011, Eni had undrawn committed and uncommitted borrowing facilities amounting to (cid:1)2,551 million and (cid:1)9,346 million, respectively ((cid:1)2,498 million and (cid:1)7,860 million at December 31, 2010). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Charges for unutilized facilities were immaterial. At December 31, 2011, Eni did not report non-fulfillment of covenants or contractual violations in relation to borrowing facilities. 22 Trade and other payables ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Trade payables ................................................................................................................ Advances ........................................................................................................................ Other payables: - related to capital expenditures .................................................................................... - others ............................................................................................................................ 13,111 3,139 1,856 4,469 6,325 22,575 13,436 2,313 2,280 4,883 7,163 22,912 Increased trade receivables amounting to (cid:1)325 million primarily related to the Gas & Power segment ((cid:1)708 million) and, as decrease, to the Refining & Marketing segment ((cid:1)309 million). Advances of (cid:1)2,313 million ((cid:1)3,139 million at December 31, 2010) related to prepayments and advances on contract work in progress for (cid:1)1,037 million and for (cid:1)795 million, respectively ((cid:1)1,539 million and (cid:1)1,042 million at December 31, 2010, respectively) and other advances for (cid:1)481 million ((cid:1)558 million at December 31, 2010). Advances on contract work the Engineering & Construction segment. Other advances for (cid:1)42 million ((cid:1)251 million at December 31, 2010) pertained to in progress were in respect of F-50 prepayments received by gas customers relating to gas off-takes for the year lower than the annual minimum quantity thus triggering the take-or-pay clause. The Company expects that those customers will make up the associated volumes within end of the next year. Other payables were as follows: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Payables due to: - suppliers in relation to investing activities ................................................................. - joint venture operators in exploration and production activities .............................. - other .............................................................................................................................. Other payables: - joint venture operators in exploration and production activities .............................. - employees ..................................................................................................................... - social security entities ................................................................................................. - non-financial government entities .............................................................................. - other .............................................................................................................................. 1,224 304 328 1,856 2,078 571 261 628 931 4,469 6,325 1,544 468 268 2,280 2,356 589 269 137 1,532 4,883 7,163 Other payables of (cid:1)1,532 million ((cid:1)931 million at December 31, 2010) included payables due to gas suppliers for (cid:1)719 million ((cid:1)214 million at December 31, 2010) relating to the triggering of the take-or-pay clause, net of the amounts paid by Eni for the year. Payables to related parties are described under Note 42 – Transactions with related parties. The fair value of trade and other payables matched their respective carrying amounts considering the short-term maturity of trade payables. 23 Income taxes payable ((cid:1) million) Italian subsidiaries .......................................................................................................... Foreign subsidiaries ....................................................................................................... Dec. 31, 2010 Dec. 31, 2011 300 1,215 1,515 390 1,702 2,092 Income tax expenses are described under Note 39 – Income taxes. 24 Other taxes payable ((cid:1) million) Excise and customs duties ............................................................................................. Other taxes and duties .................................................................................................... Dec. 31, 2010 Dec. 31, 2011 930 729 1,659 1,049 847 1,896 F-51 25 Other current liabilities ((cid:1) million) Fair value of non-hedging and trading derivatives ...................................................... Fair value of cash flow hedge derivatives .................................................................... Other liabilities ............................................................................................................... Dec. 31, 2010 Dec. 31, 2011 656 475 489 1,620 1,668 121 448 2,237 The fair value of non-hedging derivative contracts and derivatives contracts held for trading is presented below: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments Derivatives on exchange rate Currency swap ................................................ Interest currency swap ................................... Other ............................................................... Derivatives on interest rate Interest rate swap ........................................... Derivatives on commodities Over the counter ............................................. Future .............................................................. Other ............................................................... 162 18 1 181 11 11 354 10 100 464 656 4,776 116 141 5,033 25 25 430 430 5,488 1,582 29 1,611 1,504 1,504 2,277 161 442 2,880 5,995 448 6 1 455 3 3 1,066 63 81 1,210 1,668 3,979 116 4,095 3,829 418 4,247 8,342 8,076 23 8,099 735 735 4,620 173 548 5,341 14,175 Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques commonly used on the marketplace. Fair values of non-hedging and trading derivatives of (cid:1)1,668 million ((cid:1)656 million at December 31, 2010) consisted of: (i) (cid:1)1,587 million ((cid:1)621 million at December 31, 2010) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to movements in foreign currencies, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) (cid:1)80 million ((cid:1)35 million at December 31, 2010), of commodity trading derivatives entered by the Gas & Power segment in order to optimize the economic margin as provided by the new risk management strategy; and (iii) (cid:1)1 million, of derivatives embedded in the pricing formulas of certain long-term supply contracts of gas in the Exploration & Production segment. The fair value of cash flow hedge derivatives amounted to (cid:1)121 million ((cid:1)475 million at December 31, 2010) and pertained to the Gas & Power segment for (cid:1)119 million ((cid:1)244 million for the Gas & Power segment and (cid:1)231 million for the Exploration & Production segment at December 31, 2010). Fair value pertaining to the Gas & Power segment related to derivatives that were designated to hedge exchange rate and commodity risk exposures as described under Note 13 – Other current assets. A cash flow hedge transaction was settled in 2011 in the Exploration & Production segment relating the sale of 9 mmBBL part of a multi-year transaction which hedged 125.7 mmBBL in the 2008-2011 period. Fair value of contracts expiring by end of 2012 is disclosed under Note 13 – Other current assets; fair value of contracts expiring beyond 2012 is disclosed under Note 30 – Other non-current liabilities and under Note 20 – Other non-current receivables. The effects of the evaluation at fair value of cash flow hedge derivatives are disclosed under Note 32 – Shareholders’ equity and under Note 36 – Operating expenses. The nominal value of cash flow hedge derivatives referred to purchase and sale commitments for (cid:1)3,409 million and (cid:1)452 million, respectively ((cid:1)1,805 million and (cid:1)849 million at December 31, 2010, respectively). Information on the hedged risks and the hedging policies is disclosed under Note 34 – Guarantees, commitments and risks – Risk factors. F-52 Non-current liabilities 26 Long-term debt and current portion of long-term debt ((cid:1) million) At December 31, Current maturity Long-term maturity Maturity range 2010 2011 2012 2013 2014 2015 2016 After Total Banks ............................................ Ordinary bonds ............................ Other financial institutions .......... 2012-2029 2012-2040 2012-2023 7,224 13,572 472 21,268 9,654 15,049 435 25,138 1,601 397 38 2,036 1,329 1,607 57 2,993 3,681 1,337 46 5,064 629 2,231 48 2,908 1,285 1,492 48 2,825 1,129 7,985 198 9,312 8,053 14,652 397 23,102 Long-term debt, including the current portion of long-term debt, of (cid:1)25,138 million ((cid:1)21,268 million at December 31, 2010) increased by (cid:1)3,870 million. The increase comprised new issuance net of repayments made for (cid:1)3,585 million and currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for (cid:1)143 million. Debt from banks of (cid:1)9,654 million included amount against committed borrowing for (cid:1)4,107 million. Debt from other financial institutions of (cid:1)435 million ((cid:1)472 million at December 31, 2010) included (cid:1)15 million of finance lease transactions ((cid:1)17 million at December 31, 2010). Eni entered into long-term borrowing facilities with the European Investment Bank. In 2011, Eni entered into long-term borrowing facilities with Citibank Europe Plc providing for conditions similar to those applied by the European Investment Bank. These borrowing facilities are subject to the maintenance of certain financial ratios based on Eni’s consolidated financial statements or a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees would be provided to be agreed upon with the lenders. At December 31, 2010 and 2011, the amount of short and long-term debt subject to restrictive covenants was (cid:1)1,685 million and (cid:1)2,316 million, respectively. A possible non-compliance with those covenants would be immaterial to the Company’s ability to finance its operations. As of the balance sheet date, Eni was in compliance with those covenants. Bonds of (cid:1)15,049 million consisted of bonds issued within the Euro Medium Term Notes Program for a total of (cid:1)10,802 million and other bonds for a total of (cid:1)4,247 million. F-53 The following table provides a break-down of bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2011: Discount on bond issue and accrued expense Amount ((cid:1) million) Issuing entity Euro Medium Term Notes: - Eni SpA ........................................ - Eni SpA ........................................ - Eni SpA ........................................ - Eni SpA ........................................ - Eni SpA ........................................ - Eni SpA ........................................ - Eni SpA ........................................ - Eni Finance International SA ... - Eni Finance International SA ... - Eni Finance International SA ... - Eni Finance International SA ... - Eni Finance International SA ... - Eni Finance International SA ... 1,500 1,500 1,500 1,250 1,250 1,000 1,000 539 459 300 197 16 35 10,546 Other bonds: - Eni SpA ................................. - Eni SpA ................................. - Eni SpA ................................. - Eni SpA ................................. - Eni SpA ................................. - Eni SpA ................................. - Eni USA Inc ......................... - Eni UK Holding Plc ............. 1,000 1,109 1,000 215 348 271 309 1 4,253 14,799 Total Currency Maturity % rate from to from to 61 45 9 68 (1) 17 33 11 3 7 3 256 11 (5) (9) 1 (4) (6) 250 1,561 1,545 1,509 1,318 1,249 1,017 1,033 550 462 307 200 16 35 10,802 1,011 1,104 991 215 349 271 305 1 4,247 15,049 EUR EUR EUR EUR EUR EUR EUR GBP YEN EUR USD EUR USD EUR EUR EUR EUR USD USD USD GBP 2018 2012 2017 2013 2016 2013 2019 2014 2017 2020 2018 2021 2037 2031 2015 2015 2013 2015 2017 2015 2017 2020 2040 2027 2013 4.750 1.150 3.750 4.450 5.000 4.625 4.125 5.875 4.750 4.000 3.500 6.125 2.810 5.600 4.800 variable variable 4.000 4.875 variable variable 4.150 5.700 7.300 variable As of December 31, 2011, bonds maturing within 18 months ((cid:1)1,705 million) were issued by Eni SpA ((cid:1)1,545 million), Eni Finance International SA ((cid:1)159 million) and Eni UK Holding Plc ((cid:1)1 million). During the 2011, Eni SpA and Eni Finance International SA issued bonds for (cid:1)1,319 million and (cid:1)174 million, respectively. The following table provides a break-down by currency of long-term debt and its current portion and the related weighted average interest rates. Euro................................................................................ U.S. dollar...................................................................... British pound ................................................................. Japanese yen .................................................................. Other currencies ............................................................ Dec. 31, 2010 ((cid:1) million) Average rate (%) Dec. 31, 2011 ((cid:1) million) Average rate (%) 18,895 1,415 527 426 5 21,268 3.5 5.7 5.5 2.0 6.8 22,196 1,926 551 462 3 25,138 3.2 5.0 5.3 2.0 6.3 As of December 31, 2011, Eni had undrawn committed long-term borrowing facilities of (cid:1)3,201 million ((cid:1)4,901 million at December 31, 2010). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Charges for unutilized facilities were immaterial. F-54 Fair value of long-term debt, including the current portion of long-term debt amounted to (cid:1)27,103 million ((cid:1)22,607 million at December 31, 2010): ((cid:1) million) Ordinary bonds................................................................................................................ Banks................................................................................................................................ Other financial institutions ............................................................................................. Dec. 31, 2010 Dec. 31, 2011 14,790 7,306 511 22,607 16,895 9,727 481 27,103 Fair value was calculated by discounting the expected future cash flows at discount rates ranging from 0.7% to 3.1% (0.8% and 4.1% at December 31, 2010). At December 31, 2011, Eni did not pledge restricted deposits as collateral against its borrowings. Information on net borrowings In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as endorsed by IASB less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities. Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced according to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies. ((cid:1) million) Dec. 31, 2010 Current Non- current Total Current Dec. 31, 2011 Non- current A. Cash and cash equivalents ............................ 1,549 B. Available-for-sale securities ......................... 109 C. Liquidity (A+B) .......................................... 1,658 D. Financing receivables ................................ 6 E. Short-term debt towards banks .................... 1,950 499 F. Long-term debt towards banks .................... 410 G. Bonds ............................................................ H. Short-term debt towards related parties ...... 127 I. Other short-term debt ................................... 4,438 54 L. Other long-term debt .................................... M. Total borrowings (E+F+G+H+I+L) ........ 7,478 N. Net borrowings (M-C-D) ........................... 5,814 6,725 13,162 418 20,305 20,305 1,549 109 1,658 6 1,950 7,224 13,572 127 4,438 472 27,783 26,119 1,500 37 1,537 28 786 1,601 397 503 3,170 38 6,495 4,930 8,053 14,652 397 23,102 23,102 Total 1,500 37 1,537 28 786 9,654 15,049 503 3,170 435 29,597 28,032 Available-for-sale securities of (cid:1)37 million ((cid:1)109 million at December 31, 2010) were held for non-operating purposes. The Company held at the reporting date certain held-to-maturity and available-for-sale securities which were destined to operating purposes amounting to (cid:1)287 million ((cid:1)308 million at December 31, 2010), of which (cid:1)220 million ((cid:1)267 million at December 31, 2010) were held to hedge the loss reserve of Eni Insurance Ltd. Those securities are excluded from the calculation above. F-55 Financing receivables of (cid:1)28 million ((cid:1)6 million at December 31, 2010) were held for non-operating purposes. The Company held at the reporting date certain financing receivables which were destined to operating purposes amounting to (cid:1)630 million ((cid:1)656 million at December 31, 2010), of which (cid:1)345 million ((cid:1)470 million at December 31, 2010) were in respect of financing granted to unconsolidated entities which executed capital projects and investments on behalf of Eni’s Group companies and a (cid:1)250 million cash deposit ((cid:1)159 million at December 31, 2010) to hedge the loss reserve of Eni Insurance Ltd. Those financing receivables are excluded from the calculation above. 27 Provisions for contingencies ((cid:1) million) Provision for site restoration, abandonment and social projects .............. Provision for environmental risks ............ Provision for legal and other proceedings Provision for taxes ..................................... Loss adjustments and actuarial provisions for Eni’s insurance companies .................. Provision for losses on investments ......... Provision for redundancy incentives ........ Provision for onerous contracts ................ Provision for OIL insurance cover ........... Provision for long-term construction contracts ................................ Provision for coverage of unaccounted-for gas .............................. Provision for the supply of goods ............. Other (*) ....................................................... _______ Carrying amount at Dec. 31, 2010 New or increased provisions Initial recognition and changes in estimates Reversal of utilized provisions Reversal of unutilized provisions Currency translation differences Accretion discount Carrying amount at Dec. 31, 2011 Other changes 5,741 3,104 692 357 398 200 202 108 79 22 31 288 570 11,792 803 253 (3) 206 241 66 4 53 99 77 20 59 39 232 1,096 (3) 803 247 (153) (194) (123) (49) (59) (121) (64) (21) (33) (132) (949) (22) (81) (1) (28) (19) (1) 157 9 8 1 3 1 (2) (92) (246) (2) 177 (21) (7) 336 (37) (53) 1 1 (1) 23 (261) (166) (185) 6,780 3,084 1,074 344 343 172 163 125 98 60 54 28 410 12,735 (*) Each individual amount included herein does not exceed (cid:1)50 million. Provisions for site restoration, abandonment and social projects amounted to (cid:1)6,780 million. Those provisions comprised the discounted estimated costs that the Company expects to incur for decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration ((cid:1)6,404 million). The additions for the year amounted to (cid:1)803 million and were primarily due to estimates revisions and the initial recognition of abandonment costs taken in connection with new field start-up in the Exploration & Production segment for (cid:1)918 million. Furthermore, costs associated with certain of social projects were recognized pertaining to oil development programs in Val d’Agri and in the North Adriatic area with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality of Ravenna for (cid:1)19 million. Also a decrease was recognized due to changed timing assumptions of future expenditures for dismantling and restoring gas storage sites of Stoccaggi Gas Italia SpA for (cid:1)137 million (for more information see Note 16 – Intangible assets). An amount of (cid:1)253 million was recognized through profit and loss as accretion charge of the period. The discount rates adopted ranged from 1.4% to 9.3% (from 2.1% to 8.9% at December 31, 2010). Main expenditures associated with site restoration and abandonment operations will be incurred over a 30-year period starting from 2017. Provisions for environmental risks amounted to (cid:1)3,084 million. Those provisions comprised the estimated costs for environmental clean-up and restoration of certain industrial sites which were owned or held in concession by the Company, and subsequently divested, shut-down or liquidated. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to perform certain cleaning-up and restoration projects and reliable cost estimation is available. Such provision comprised the cost estimate relating to a proposal for a global environmental transaction filled with the Ministry of the Environment, Land and Sea on January 26, 2011, according to Article 2 of Law Decree 208/2008 ((cid:1)1,109 million). In accordance with the Law, the competent in particular The Institute for Environmental Protection and Research (ISPRA) and technical offices, F-56 the Evaluator Commission for investment supporting planning and management of environmental activities (COVIS) started a preliminary assessment which is currently ongoing. At December 31, 2011, provisions for environmental risks were primarily related to Syndial SpA ((cid:1)2,497 million) and the Refining & Marketing segment ((cid:1)404 million). Additions of (cid:1)206 million primarily related to Syndial SpA ((cid:1)142 million) and the Refining & Marketing segment ((cid:1)35 million). Reversal of utilized provisions of (cid:1)194 million primarily related to Syndial SpA ((cid:1)88 million) and the Refining & Marketing segment ((cid:1)75 million). Provisions for legal and other proceedings of (cid:1)1,074 million comprised the expected liabilities due to failure to perform certain contractual obligations and estimated future losses on pending litigation including legal, antitrust and administrative matters. These provisions represented the Company’s best estimate of the expected probable liabilities and primarily related to the Gas & Power segment ((cid:1)555 million) and Syndial SpA ((cid:1)281 million). Additions of (cid:1)241 million included a charge amounting to (cid:1)69 million following a sentence recently issued by the Court of Justice of the European Community in connection with an antitrust proceeding in the European sector of rubbers. The matter is fully disclosed under Note 34 – Guarantees, commitments and risks – Legal Proceedings. Reversals of utilized and unutilized provision comprised reversals for (cid:1)65 million and (cid:1)10 million, respectively, related to the settlement of the Agrifactoring/Serfactoring proceeding. Other changes for the year of (cid:1)336 million included an amount reclassified from the Parent Company Eni SpA which was previously reported in the provision for the supply of goods (see below) ((cid:1)261 million). Provisions for taxes of (cid:1)344 million primarily included charges for unsettled tax claims in connection with uncertain applications of the tax regulation for foreign subsidiaries of the Exploration & Production segment ((cid:1)254 million) and of the Engineering & Construction segment ((cid:1)64 million). Loss adjustments and actuarial provisions of Eni’s insurance companies of (cid:1)343 million represented the expected liabilities accrued on the basis for third parties claims. Such liabilities were partly offset by a receivable of (cid:1)90 million recognized towards insurance companies for reinsurance contracts. Provisions for losses on investments of (cid:1)172 million were made with respect to certain investees for which expected or incurred losses exceeded carrying amounts (more information is disclosed under Note 17 – Investments). Provisions for redundancy incentives of (cid:1)163 million were recognized with a restructuring program involving the Italian personnel for the period 2010-2011 in compliance with Law No. 223/1991 which provided a scheme for early retirement. An addition amounting to (cid:1)99 was accrued to adjustment the expected liability to take account of changed retirement requirements introduced by Law 214/2011. Provisions for onerous contracts of (cid:1)125 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on a re-gasification project in the United States. Provisions for the OIL mutual insurance scheme of (cid:1)98 million included the estimated future increase of insurance charges, as a result of accidents that occurred in past periods that will be recognized to the mutual insures over the next 5 years by Eni. Provisions for long-term construction contracts of (cid:1)60 million related to the Engineering & Construction segment ((cid:1)45 million) and the Exploration & Production segment ((cid:1)15 million). A provision of (cid:1)54 million was accrued to take into account the expected volumes of gas that Snam Rete Gas SpA is required to supply over the next two years to balance the lower volumes of the network lost gas that will be charged to the shippers in the same period. Provisions for the supply of goods in the amount of (cid:1)28 million included the estimated costs of supply contract revisions made by Eni SpA. Other changes of (cid:1)261 million concerned a reclassification to provision for legal and other proceedings. F-57 28 Provisions for employee benefits ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 TFR ................................................................................................................................. Foreign pension plans .................................................................................................... Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans .................................................................................... Other benefits ................................................................................................................. 423 295 108 206 1,032 394 334 104 207 1,039 Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement, determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code. The benefit is paid upon retirement as a lump sum, the amount of which corresponds to the total of the provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in the law regime, from January 1, 2007 accruing benefits have been contributing to a pension fund or a treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, contributions of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be treated in accordance to a defined contribution scheme. Amounts already accrued before January 1, 2007 continue to be accounted for as defined benefits to be assessed based on actuarial assumptions. Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement. Group companies provide healthcare benefits to retired managers. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company. Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers both of which normally vest over a three-year period upon fulfillment of certain performance conditions. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses which will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets upon the same period. Provisions for the long-term incentive scheme are assessed on the basis of the estimated trends of a performance indicator as benchmarked against a group of international oil companies. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration. F-58 Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following: ((cid:1) million) Foreign pension plans 2010 Present value of benefit liabilities and plan assets at beginning of year ........ Current cost ................................................... Interest cost .................................................... Amendments .................................................. Expected return on plan assets ..................... Employee contributions ................................ Actuarial gains/losses ................................... Benefits paid .................................................. Curtailments and settlements ........................ Currency translation differences and other changes .......................................... Present value of benefit liabilities and plan assets at end of year .................... 2011 Present value of benefit liabilities and plan assets at beginning of year ........ Current cost ................................................... Interest cost .................................................... Amendments .................................................. Expected return on plan assets ..................... Employee contributions ................................ Actuarial gains/losses ................................... Benefits paid .................................................. Curtailments and settlements ........................ Currency translation differences and other changes .......................................... Present value of benefit liabilities and plan assets at end of year .................... TFR Gross liability Plan assets FISDE and other foreign medical plans Other benefits Total 447 22 8 (42) 1,146 42 36 9 1 (22) (28) (113) (2) 38 (500) (20) (30) (4) 9 115 (38) 115 2 6 188 50 6 4 (7) 6 (45) 1,396 94 70 9 (20) (29) (8) (113) 2 1 (1) 433 1,109 (468) 120 206 1,400 433 20 1,109 41 39 6 (13) (50) (24) (26) (468) (17) (36) (7) 15 120 2 6 206 53 4 3 (12) (55) 1,400 96 69 6 (17) (36) (41) (128) 1 (35) (57) (1) (1) (93) 391 1,110 (570) 118 207 1,256 Other benefits of (cid:1)207 million ((cid:1)206 million at December 31, 2010) primarily concerned the deferred monetary incentive plan for (cid:1)118 million ((cid:1)126 million at December 31, 2010), Jubilee awards for (cid:1)61 million ((cid:1)59 million at December 31, 2010) and the long-term incentive plan for (cid:1)7 million ((cid:1)2 million at December 31, 2010). F-59 The reconciliation analysis of benefit obligations and plan assets was as follows: ((cid:1) million) Present value of benefit obligations with plan assets ................................... Present value of plan assets ................ Net present value of benefit obligations with plan assets ............. Present value of benefit obligations without plan assets ........................... Actuarial gains (losses) not recognized ..................................... Past service cost not recognized ........ Net liabilities recognized in provisions for employee benefits .... TFR Foreign pension plans FISDE and other foreign medical plans Other benefits Dec. 31, 2010 Dec. 31, 2011 Dec. 31, 2010 Dec. 31, 2011 Dec. 31, 2010 Dec. 31, 2011 Dec. 31, 2010 Dec. 31, 2011 874 (468) 406 235 (273) (73) 877 (570) 307 233 (139) (67) 120 (9) (3) 433 (10) 391 3 423 394 295 334 108 118 (11) (3) 104 206 207 206 207 The net liability for foreign employee pension plans of (cid:1)334 million ((cid:1)295 million at December 31, 2010) included the liabilities related to joint ventures operating in exploration and production activities for (cid:1)121 million and (cid:1)149 million at December 31, 2010 and 2011, respectively. A receivable of an amount equivalent to such liability was recorded. Costs charged to the profit and loss account were as follows: ((cid:1) million) 2010 Current cost ....................................... Interest cost ........................................ Expected return on plan assets ......... Amortization of actuarial gains (losses) ..................................... Effect of curtailments and settlements .................................. 2011 Current cost ....................................... Interest cost ........................................ Expected return on plan assets ......... Amortization of actuarial gains (losses) ..................................... Effect of curtailments and settlements .................................. TFR Foreign pension plans FISDE and other foreign medical plans Other benefits Total 22 22 20 20 42 36 (20) 8 5 71 41 39 (17) 8 2 73 2 6 8 2 6 8 50 6 7 63 53 4 57 94 70 (20) 15 5 164 96 69 (17) 8 2 158 F-60 The main actuarial assumptions used in the evaluation of post-retirement benefit obligations at year-end and in the estimate of costs expected for 2012 were as follows: (%) 2010 Discount rate.................................................................. Expected return rate on plan assets ............................. Rate of compensation increase .................................... Rate of price inflation .................................................. 2011 Discount rate ................................................................. Expected return rate on plan assets ............................. Rate of compensation increase .................................... Rate of price inflation .................................................. TFR Foreign pension plans FISDE and other foreign medical plans Other benefits 4.8 3.0 2.0 4.8 3.0 2.0 2.7-14.0 3.5-14.0 2.0-14.0 0.8-13.0 2.6-15.5 3.2-12.3 2.0-12.3 0.1-13.8 4.8 1.8-4.8 2.0 4.8 2.0 2.0 3.6-4.8 2.0 Italian plans were based on mortality tables prepared by Ragioneria Generale dello Stato (RG48), with the exception of the medical plan FISDE for which, starting from the end of 2011, were adopted mortality tables prepared by Istat (Istat Proiettate e Selezionate - IPS55). Expected return rates by plan assets have been determined by reference to quoted prices expressed in regulated markets. Plan assets consisted of the following: (%) Securities ........................................................................................................................ Bonds .............................................................................................................................. Real estate ....................................................................................................................... Other ............................................................................................................................... Total ................................................................................................................................ Plan assets 11.1 57.5 4.5 26.9 100.0 Expected return 5.8-6.1 2.0-12.3 5.2-6.0 0.5-12.3 The actual return of the plan assets amounted to (cid:1)24 million (the same amount as of December 31, 2010). With reference to healthcare plans, the effects deriving from a 1% change of the actuarial assumptions of medical costs were as follows: ((cid:1) million) 1% Increase 1% Decrease Impact on the current costs and interest costs ............................................................... Impact on net benefit obligation .................................................................................... 1 15 (1) (12) The amount expected to be accrued to employee benefit plans for 2012 amounted to (cid:1)121 million, of which (cid:1)71 million referred to defined benefit plans. F-61 The break-down of changes in the actuarial estimates of the net liability with respect to prior-year amounts due to the difference between actual data at the end of the reporting period and the corresponding prior-year actuarial assumptions is provided below: ((cid:1) million) 2007 Impact on benefit obligation......................................... Impact on plan assets .................................................... 2008 Impact on benefit obligation......................................... Impact on plan assets .................................................... 2009 Impact on benefit obligation......................................... Impact on plan assets .................................................... 2010 Impact on benefit obligation......................................... Impact on plan assets .................................................... 2011 Impact on benefit obligation......................................... Impact on plan assets .................................................... TFR Foreign pension plans FISDE and other foreign medical plans Other benefits (8) 7 (7) (1) 3 6 3 15 (62) 4 (16) (31) 3 (21) 10 1 2 4 3 3 1 2 The present value of liabilities for employee benefit plans and the fair value of plan assets consisted of the following: ((cid:1) million) Present value of liabilities TFR .................................................... Foreign pension plans ....................... FISDE and other foreign medical plans ..................................... Other benefits .................................... Fair value of plan assets Foreign pension plans ....................... Present value of net liabilities TFR .................................................... Foreign pension plans ....................... FISDE and other foreign medical plans ..................................... Other benefits .................................... Dec. 31, 2007 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2010 Dec. 31, 2011 476 621 92 118 1,307 (362) (362) 476 259 92 118 945 443 802 94 168 1,507 (453) (453) 443 349 94 168 1,054 447 1,146 115 188 1,896 (500) (500) 447 646 115 188 1,396 433 1,109 120 206 1,868 (468) (468) 433 641 120 206 1,400 391 1,110 118 207 1,826 (570) (570) 391 540 118 207 1,256 F-62 29 Deferred tax liabilities Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for (cid:1)4,045 million ((cid:1)3,421 million at December 31, 2010). ((cid:1) million) Amount at Dec. 31, 2010 Additions Deductions Currency translation differences Other changes Amount at Dec. 31, 2011 5,924 2,030 (531) 299 (602) 7,120 Deferred tax assets and liabilities consisted of the following: ((cid:1) million) Deferred tax liabilities ................................................................................................... Deferred tax assets available for offset ......................................................................... Deferred tax assets not available for offset .................................................................. Dec. 31, 2010 Dec. 31, 2011 9,345 (3,421) 5,924 (4,864) 1,060 11,165 (4,045) 7,120 (5,514) 1,606 Net deferred tax liabilities of (cid:1)7,120 million comprised: (i) an adjustment to deferred taxation due to a changed tax rate applicable to a production sharing agreement in the Exploration & Production segment ((cid:1)573 million), including an adjustment to deferred taxation which was recognized upon allocation of the purchase price as part of a business combination when the mineral interest was acquired by Eni; and (ii) the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedge for (cid:1)28 million of deferred tax liabilities. Further information on cash flow hedge derivatives is disclosed under Note 25 – Other current liabilities. The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below: Carrying amount at Dec. 31, 2010 Additions Deductions Currency translation differences Other changes Carrying amount at Dec. 31, 2011 5,698 1,320 (229) 223 213 7,225 ((cid:1) million) Deferred tax liabilities: - accelerated tax depreciation ....................... - difference between the fair value and the carrying amount of assets acquired following business combinations ................................ - site restoration and 1,209 abandonment (tangible assets) ................... 440 - application of the weighted average cost method in evaluation of inventories .......... - capitalized interest expense ........................ - other ............................................................. Deferred tax assets: - site restoration and abandonment (provisions for contingencies) .................... - depreciation and amortization .................... - accruals for impairment losses and provisions for contingencies ............... - unrealized intercompany profits ................ - assets revaluation as per Laws No. 342/2000 and No. 448/2001 ................ - carry-forward tax losses ............................. - other ............................................................. Net deferred tax liabilities .......................... 174 146 1,678 9,345 (1,555) (1,500) (1,717) (908) (637) (238) (1,730) (8,285) 1,060 339 73 49 21 228 2,030 (234) (333) (370) (72) (1) (235) (791) (2,036) (6) (21) (24) (9) (10) (238) (531) 24 45 307 71 18 147 270 882 351 43 9 24 299 (51) (58) 3 (9) (30) (145) 154 (264) 1,306 (54) (1) 1 127 22 (163) 33 (16) 131 (1) (4) 45 25 47 444 213 158 1,819 11,165 (1,979) (1,813) (1,796) (775) (621) (339) (2,236) (9,559) 1,606 F-63 Deductible temporary differences giving rise to deferred tax assets are recognized to the extent that is probable that sufficient taxable profit will be available against which part or all of the deductible temporary differences can be utilized. Italian taxation law, modified by Article 23 of Law Decree No. 98/2011, allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than the five subsequent years, and in many cases, indefinitely. The tax rate applied to determine the portion of carry-forwards tax losses to be utilized equaled to an average rate of 17.6% for Italian companies, by considering the different taxation for energy companies and companies included in the consolidation statement for fiscal purposes, and an average rate of 32.1% for foreign companies. Carry-forward tax losses amounted to (cid:1)1,480 million and can be used indefinitely for (cid:1)1,313 million. Carry- forward tax losses regarded Italian companies for (cid:1)153 million and foreign companies (cid:1)1,327 million. Carry- forward tax losses for which are probable the offsetting against future taxable profit amounted to (cid:1)1,124 million and were in respect of Italian companies for (cid:1)153 million and of foreign subsidiaries for (cid:1)971 million. Deferred tax assets recognized on these losses amounted to (cid:1)27 million and (cid:1)312 million, respectively. 30 Other non-current liabilities ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Fair value of non-hedging and trading derivatives ...................................................... Fair value of cash flow hedge derivatives .................................................................... Current income tax liabilities ........................................................................................ Other payables ................................................................................................................ Other liabilities ............................................................................................................... 344 157 40 67 1,586 2,194 591 37 70 2,202 2,900 Derivative fair values were estimated on the basis of market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation techniques commonly used on the marketplace. The fair value of non-hedging derivative contracts and derivatives contracts held for trading is presented below: ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments Derivatives on exchange rate Currency swap ................................................ Interest currency swap ................................... Derivatives on interest rate Interest rate swap ........................................... Derivatives on commodities Over the counter ............................................ Future ............................................................. Other .............................................................. 1 16 17 147 147 155 25 180 344 48 228 276 16 16 521 521 813 17 117 134 2,999 2,999 541 72 613 3,746 1 1 255 255 310 3 22 335 591 50 50 3,760 14 3,774 3,824 3 3 4,136 4,136 416 126 542 4,681 Fair values of non-hedging and trading derivatives of (cid:1)591 million ((cid:1)344 million at December 31, 2010) consisted of: (i) (cid:1)568 million ((cid:1)328 million at December 31, 2010) of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net business exposures to foreign currency exchange rates, interest rates or commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions; (ii) (cid:1)14 million of derivatives embedded F-64 in the pricing formulas of long-term gas supply contracts in the Exploration & Production segment; and (iii) (cid:1)9 million ((cid:1)16 million at December 31, 2010) of trading derivatives on commodities entered by the Gas & Power segment consistently with the new risk management strategy designed to optimize margins. Fair value of cash flow hedge derivatives amounted to (cid:1)37 million ((cid:1)157 million at December 31, 2010) and pertained to the Gas & Power segment ((cid:1)157 million at December 31, 2010). Those derivatives were designated to hedge exchange rate and commodity risk exposures as described under Note 13 – Other current assets. Fair value of contracts expiring beyond 2012 is disclosed under Note 20 – Other non-current receivables; fair value of contracts expiring by 2012 is disclosed under Note 25 – Other current liabilities and under Note 13 – Other current assets. The effects of fair value evaluation of cash flow hedge derivatives are disclosed under Note 32 – Shareholders’ equity and under Note 36 – Operating expenses. The nominal value of these derivatives referred to purchase and sale commitments for (cid:1)340 million and (cid:1)310 million, respectively ((cid:1)383 million and (cid:1)612 million at December 31, 2010). Information on the hedged risks and the hedging policies is shown under Note 34 – Guarantees, commitments and risks - Risk factors. The Group’s liability for current income taxes for (cid:1)40 million at December 31, 2010, was due for a special tax (with a rate lower than the statutory tax rate) relating to an option to increase the deductible tax bases of certain tangible and other assets to their carrying amounts as permitted by the 2008 Budget Law. During the 2011, the residual amount of such liability was reclassified as current liability. Other liabilities of (cid:1)2,202 million ((cid:1)1,586 million at December 31, 2010) comprised advances received from Suez following a long-term agreement for supplying natural gas and electricity of (cid:1)1,061 million ((cid:1)1,353 million at December 31, 2010) and advances relating to amounts of gas which were collected below the minimum take for the year by certain of Eni’s clients, reflecting take-or-pay clauses contained in the long-term sales contracts ((cid:1)299 million). 31 Assets held for sale and liabilities directly associated with assets held for sale As of December 31, 2011, non-current assets held for sale and liabilities directly associated with non-current assets held for sale of (cid:1)230 million and (cid:1)24 million pertained to non-strategic assets in the Exploration & Production segment. 32 Shareholders’ equity Non-controlling interest Profit attributable to non-controlling interest and the non-controlling interest in consolidated subsidiaries related to: ((cid:1) million) Saipem SpA .................................................................. Snam Rete Gas SpA ..................................................... Hindustan Oil Exploration Co Ltd .............................. Tigáz Zrt ....................................................................... Others ............................................................................ Net profit Shareholders’ equity 2010 2011 Dec. 31, 2010 Dec. 31, 2011 503 537 13 12 1,065 552 385 (6) 12 943 2,406 1,705 146 83 182 4,522 2,802 1,730 123 74 192 4,921 F-65 Eni shareholders’ equity ((cid:1) million) Share capital ................................................................................................................... Legal reserve .................................................................................................................. Reserve for treasury shares ............................................................................................ Reserve related to the fair value of cash flow hedging derivatives net of the tax effect ....................................................................... Reserve related to the fair value of available-for-sale securities net of the tax effect ........................................................................................ Other reserves ................................................................................................................. Cumulative currency translation differences ................................................................ Treasury shares ............................................................................................................... Retained earnings ........................................................................................................... Interim dividend ............................................................................................................. Net profit for the period ................................................................................................. Dec. 31, 2010 Dec. 31, 2011 4,005 959 6,756 (174) (3) 1,518 539 (6,756) 39,855 (1,811) 6,318 51,206 4,005 959 6,753 49 (8) 1,421 1,539 (6,753) 42,531 (1,884) 6,860 55,472 Share capital At December 31, 2011, the Parent Company’s issued share capital consisted of 4,005,358,876 shares (nominal value (cid:1)1 each) fully paid-up (the same amount as of December 31, 2010). On May 5, 2011, Eni’s Shareholders’ Meeting declared a dividend distribution of (cid:1)0.50 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2010 dividend of (cid:1)1.00 per share, of which (cid:1)0.50 per share paid as interim dividend. The balance was payable on May 26, 2011, to shareholders on the register on May 23, 2011. Legal reserve This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law. Reserve for treasury shares The reserve for treasury shares represents the reserve which was established in previous reporting period to repurchase the Company shares in accordance with the decisions of Eni’s Shareholders’ Meetings. The Company has no ongoing share repurchase plan. The amount of (cid:1)6,753 million ((cid:1)6,756 million at December 31, 2010) included treasury shares purchased. F-66 Reserve for available-for-sale financial instruments and cash flow hedging derivatives net of the related tax effect The valuation at fair value of available-for-sale financial instruments and cash flow hedging derivatives, net of the related tax effect, consisted of the following: ((cid:1) million) Available-for-sale financial instruments Cash flow hedge derivatives Gross reserve Deferred tax liabilities Net reserve Gross reserve Deferred tax liabilities Net reserve Gross reserve Total Deferred tax liabilities Reserve as of December 31, 2009........ Changes of the year 2010 ............. Foreign currency translation differences ... Amount recognized in the profit and loss account ........................... Reserve as of December 31, 2010........ Changes of the year 2011 ............. Amount recognized in the profit and loss account ........................... Reserve as of December 31, 2011 ....... Other reserves 6 (9) (3) (6) (9) (1) 1 1 1 5 (8) (3) (5) (8) Net reserve (434) 6 (2) (714) 47 (4) 275 (33) 2 (439) (708) 14 (2) 38 (4) 274 (32) 2 396 (143) 253 396 (143) 253 (275) 101 (174) (278) 101 (177) 76 (7) 69 70 (6) 64 276 77 (122) (28) 154 49 276 68 (122) (27) 154 41 Other reserves amounted to (cid:1)1,421 million ((cid:1)1,518 million at December 31, 2010) and related to: • a reserve of (cid:1)1,137 million represented an increase in Eni’s shareholders’ equity associated with a business combination under common control which took place in 2009, whereby the Parent Company Eni SpA divested the subsidiaries Italgas SpA and Stoccaggi Gas Italia SpA to Snam Rete Gas SpA with a corresponding decrease in the non-controlling interest ((cid:1)1,142 million at December 31, 2010); a reserve of (cid:1)247 million represented an increase in Eni’s shareholders’ equity associated with a business combination under common control, whereby the Parent Company Eni SpA divested the subsidiary Snamprogetti SpA to Saipem SpA with a corresponding decrease in the non-controlling interest (the same amount as of December 31, 2010); a reserve of (cid:1)157 million deriving from Eni SpA’s equity (the same amount as of December 31, 2010); a reserve of (cid:1)14 million related to the effect of treasury shares sold following the exercise of stock options by Saipem and Snam Rete Gas managers; a negative reserve of (cid:1)119 million represented an increase in Eni’s shareholders’ equity associated with the acquisition of the residual 44.21% pertaining to the non-controlling interest of Altergaz SA; a negative reserve of (cid:1)25 million as of December 31, 2010 pertained to stock warrants of Altergaz SA owned by its shareholder Eni G&P France BV. During the 2011 the stock warrants were exercised and converted into shares of Altergaz SA; a negative reserve of (cid:1)15 million referred to the share of “Other comprehensive income” on equity- accounted entities (negative for (cid:1)3 million at December 31, 2010). • • • • • • Cumulative foreign currency translation differences The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro. Treasury shares A total of 382,654,833 ordinary shares (382,863,733 at December 31, 2010) with nominal value of (cid:1)1 each, were held in treasury, for a total cost of (cid:1)6,753 million ((cid:1)6,756 million December 31, 2010). The Company has no ongoing share repurchase plan. An amount of 11,873,205 treasury shares (15,737,120 at December 31, 2010) F-67 at a cost of (cid:1)240 million ((cid:1)328 million at December 31, 2010) were available for the 2004-200516 and 2006-2008 stock option plans. The decrease of 3,863,915 shares consisted of the following: Number of shares at December 31, 2010 ........................................ Rights exercised ................................................................................... Rights cancelled ................................................................................... Number of shares at December 31, 2011 ........................................ Stock option 15,737,120 (208,900) (3,655,015) (3,863,915) 11,873,205 At December 31, 2011, options outstanding were 11,873,205. Options regarded the 2004 stock-based compensation plan for 628,100 shares with an exercise price of (cid:1)16.576 per share, the 2005 plan for 3,281,500 shares with an exercise price of (cid:1)22.514, the 2006 plan for 2,201,950 shares with a weighted average exercise price of (cid:1)23.121, the 2007 plan for 1,876,980 shares with a weighted average exercise price of (cid:1)27.451 and the 2008 plan for 3,884,675 shares with an exercise price of (cid:1)22.540. More information about stock option plans is disclosed under Note 36 – Operating expenses. Interim dividend The interim dividend for the year 2011 amounted to (cid:1)1,884 million corresponding to (cid:1)0.52 per share, as resolved by the Board of Directors on September 8, 2011, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 22, 2011. Distributable reserves At December 31, 2011, Eni shareholders’ equity included distributable reserves of (cid:1)50,500 million. Reconciliation of net profit and shareholders’ equity of the Parent Company Eni SpA to consolidated net profit and shareholders’ equity ((cid:1) million) Net profit Shareholders’ equity As recorded in Eni SpA’s Financial Statements ... Excess of net equity in individual accounts of consolidated subsidiaries over their corresponding carrying amounts in the statutory accounts of the Parent Company ................................................ Consolidation adjustments: - difference between purchase cost and underlying carrying amounts of net equity ....... - elimination of tax adjustments and compliance with Group account policies .......... - elimination of unrealized intercompany profits ....... - deferred taxation ........................................................ - other adjustments ....................................................... Non-controlling interest ............................................... As recorded in Consolidated Financial Statements ......................... 2010 2011 Dec. 31, 2010 Dec. 31, 2011 6,179 4,213 34,724 35,255 1,297 3,972 20,122 24,355 (574) 389 14 100 (22) 7,383 (1,065) (320) (248) 115 71 7,803 (943) 4,732 4,400 (667) (4,601) 1,410 8 55,728 (4,522) (673) (4,291) 1,337 10 60,393 (4,921) 6,318 6,860 51,206 55,472 (16) The vesting period for the 2002 and 2003 assignments expired during the 2010 and 2011, respectively. F-68 33 Other information Main acquisitions Altergaz SA In December 2010, Eni increased its shareholding in Altergaz SA, a company marketing natural gas in France to retail and middle market clients, as founding partners of the company exercised a put option on a 15% stake. Eni took control of the entity. An excess purchase cost of (cid:1)106 million was allocated to assets and liabilities of the entity. That amount comprised (cid:1)39 million of consideration to the partners who exercised the put rights and (cid:1)67 million of reassessment at fair value of the stake already held by Eni before the change of control. The final allocation of the purchase costs of Altergaz SA is disclosed below: ((cid:1) million) Altergaz SA Preliminary allocation as of Dec. 31, 2010 Final allocation as of Dec. 31, 2011 Current assets ..................................................................................................................... Property, plant and equipment .......................................................................................... Intangible assets ................................................................................................................. Goodwill ............................................................................................................................. Investments ......................................................................................................................... Other non-current assets ..................................................................................................... Assets acquired ................................................................................................................. Current liabilities ................................................................................................................ Deferred tax liabilities ....................................................................................................... Provisions for contingencies ............................................................................................. Other non-current liabilities .............................................................................................. Liabilities acquired .......................................................................................................... Non-controlling interest ..................................................................................................... Eni’s shareholders equity ................................................................................................ 308 1 4 97 13 423 315 (7) 2 310 7 106 387 1 4 95 13 5 505 384 (7) 2 11 390 9 106 F-69 Supplemental cash flow information ((cid:1) million) 2009 2010 2011 Effect of investment of companies included in consolidation and businesses Current assets ................................................................................... Non-current assets ............................................................................ Net borrowings ................................................................................. Current and non-current liabilities .................................................. Net effect of investments ............................................................... Non-controlling interests ................................................................. Fair value of investments held before the acquisition of control .. Purchase price ................................................................................ less: Cash and cash equivalents .............................................................. Cash flow on investments .............................................................. Effect of disposal of consolidated subsidiaries and businesses Current assets ................................................................................... Non-current assets ............................................................................ Net borrowings ................................................................................. Current and non-current liabilities .................................................. Net effect of disposals .................................................................... Fair value of share capital held after the sale of control ................ Gain on disposal ............................................................................... Non-controlling interest ................................................................... Selling price ..................................................................................... less: Cash and cash equivalents .............................................................. Cash flow on disposals ................................................................... 34 Guarantees, commitments and risks Guarantees Guarantees were as follows: 7 47 4 (29) 29 29 (4) 25 409 316 13 (457) 281 (7) (76) 198 (55) 143 82 855 (267) (302) 368 (149) 309 (46) 482 (267) 215 122 (4) 118 (3) 115 115 618 136 257 (662) 349 727 (5) 1,071 (65) 1,006 ((cid:1) million) Dec. 31, 2010 Dec. 31, 2011 Consolidated subsidiaries .............................. Unconsolidated entities controlled by Eni ... Joint ventures and associates ......................... Others.............................................................. Unsecured guarantees Other guarantees 10,853 156 1,005 261 12,275 6,077 5 6,082 Total 10,853 156 7,082 266 18,357 Unsecured guarantees Other guarantees 10,953 164 1,135 269 12,521 6,159 1 6,160 Total 10,953 164 7,294 270 18,681 Other guarantees issued on behalf of consolidated subsidiaries of (cid:1)10,953 million ((cid:1)10,853 million at December 31, 2010) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for (cid:1)7,396 million ((cid:1)7,309 million at December 31, 2010), of which (cid:1)5,065 million related to the Engineering & Construction segment ((cid:1)5,427 million at December 31, 2010); (ii) VAT recoverable from tax authorities for (cid:1)1,097 million ((cid:1)1,076 million at December 31, 2010); and (iii) insurance risk for (cid:1)319 million reinsured by Eni ((cid:1)387 million at December 31, 2010). At December 31, 2011, the underlying commitment covered by such guarantees was (cid:1)10,577 million ((cid:1)10,718 million at December 31, 2010). Other guarantees issued on behalf of unconsolidated subsidiaries of (cid:1)164 million ((cid:1)156 million at December 31, 2010) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for (cid:1)157 million ((cid:1)152 million at December 31, 2010). At December F-70 31, 2011, the underlying commitment covered by such guarantees was (cid:1)45 million ((cid:1)81 million at December 31, 2010). Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates of (cid:1)7,294 million ((cid:1)7,082 million at December 31, 2010) primarily concerned: (i) an unsecured guarantee of (cid:1)6,074 million ((cid:1)6,054 million at December 31, 2010) given by Eni SpA to Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating to the Milan-Bologna train link by CEPAV (Consorzio Eni per l’Alta Velocità) Uno; consortium members, excluding unconsolidated entities controlled by Eni, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) unsecured guarantees, letters of patronage and other guarantees given to banks in relation to loans and lines of credit received for (cid:1)1,051 million ((cid:1)792 million at December 31, 2010), of which (cid:1)669 million related to a contract released by Eni SpA on behalf of Blue Stream Pipeline Co BV (Eni 50%) to a consortium of international financial institutions ((cid:1)648 million at December 31, 2010); and (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds for (cid:1)108 million ((cid:1)113 million at December 31, 2010). At December 31, 2011, the underlying commitment covered by such guarantees was (cid:1)810 million ((cid:1)639 million at December 31, 2010). Unsecured and other guarantees given on behalf of third parties of (cid:1)270 million ((cid:1)266 million at December 31, 2010) consisted primarily of: (i) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments of fees in connection with the re-gasification activity ((cid:1)232 million). The expected commitment has been valued at (cid:1)224 million ((cid:1)222 million at December 31, 2010) and it has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”; and (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit for (cid:1)33 million on behalf of minor investments or companies sold ((cid:1)24 million at December 31, 2010). At December 31, 2011 the underlying commitment covered by such guarantees was (cid:1)252 million ((cid:1)258 million at December 31, 2010). Commitments and risks Commitments and risks were as follows: ((cid:1) million) Commitments ................................................................................................................. Risks ................................................................................................................................ Dec. 31, 2010 Dec. 31, 2011 17,226 1,499 18,725 15,992 2,165 18,157 Commitments of (cid:1)15,992 million ((cid:1)17,226 million at December 31, 2010) were essentially related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to (cid:1)9,710 million ((cid:1)10,654 million at December 31, 2010); (ii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Angola LNG Supply Service for the acquisition of re-gasified gas at the Pascagoula plant (USA) that came into force at the start of the re-gasification service (October 2011) until 2031. The expected commitment has been valued at (cid:1)3,267 million ((cid:1)4,031 million at December 31, 2010) and it has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”; (iii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of re-gasification capacity of Pascagoula’s terminal (6 BCM/y) over a twenty-year period (2011-2031). The expected commitment has been valued at (cid:1)1,252 million ((cid:1)1,239 million at December 31, 2010) and it has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”; (iv) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron LNG Llc for the acquisition of re-gasification capacity at the Cameron plant (USA) (6 BCM/y) over a twenty-year period (until 2029). The expected commitment has been valued at (cid:1)1,274 million ((cid:1)1,018 million at December 31, 2010) and it has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”; (v) commitments for the acquisition of certain companies in Belgium ((cid:1)214 million). The acquisitions were finalized in January 2012; (vi) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest (cid:1)142 million in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oil fields in Val d’Agri ((cid:1)149 million at December 31, 2010). The commitment has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”; and (vii) a commitment entered into by Eni USA Gas Marketing Llc for the contract of gas transportation from the Cameron plant (USA) to the American network. The expected commitment has been valued at (cid:1)108 million ((cid:1)113 million at December 31, 2010) and it has included in the off-balance sheet commitments of the following paragraph “Liquidity risk”. F-71 Risks of (cid:1)2,165 million ((cid:1)1,499 million at December 31, 2010) primarily concerned potential risks associated with the value of assets of third parties under the custody of Eni for (cid:1)1,867 million ((cid:1)1,202 million at December 31, 2010) and contractual assurances given to acquirers of certain investments and businesses of Eni for (cid:1)298 million ((cid:1)297 million at December 31, 2010). Non-quantifiable commitments Following the integration signed on April 19, 2011, Eni confirmed to RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) on October 15, 1991, to guarantee a correct and timely execution of the first lot of constructions relating to the section Milan-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as General Contractor. In order to pledge the guarantee given, the regulation of CEPAV Due binds the associates to give proper sureties and guarantees on behalf of Eni. Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain of Eni’s assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity. Risk factors FOREWORD The main risks that the Company is facing and actively monitoring and managing are: (i) the market risk deriving from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) the credit risk deriving from the possible default of a counterparty; (iii) the liquidity risk deriving from the risk that suitable sources of funding for the Group’s operations may not be available; (iv) the country risk in the upstream business; (v) the operational risk; (vi) risks associated with the current downturn in the gas market and the possible evolution of regulations in the Italian gas market; and (vii) the specific risks deriving from exploration and production activities. Financial risks are managed in respect of guidelines defined by the parent company, targeting to align and coordinate Group companies’ policies on financial risks (“Eni Guidelines on Management and Control of Financial Risks”). In 2011, Eni adopted a new business model, approved by the Board of Directors on December 15, 2011, aiming to pool and integrate management of commodity risks and to develop Asset Backed Trading activities. In order to organically regulate these new tools with a view of controlling financial risks, reviews of the principles included in the Guidelines have been implemented in 2011. Market risk Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the Parent Company’s (Eni SpA) finance department, Eni Finance International, Eni Finance USA and Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular Eni SpA and Eni Finance International manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative financial contracts are managed by the Parent Company as well as the activity of negotiating emission trading certificates. The commodity risk of each business unit (Eni’s divisions or subsidiaries) is managed by Eni Trading business unit, with Eni Trading & Shipping executing the negotiation of the respective hedging derivatives. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to changes in transactional exchange rates and interest rates as well as to optimize exposure to commodity prices fluctuations and its relative exchange rate risk. Eni does not enter into derivative transactions on interest rates or exchange rates on a speculative basis. F-72 Commodity derivatives are entered into with the aim of: a) hedging certain underlying commodity prices set in contractual arrangements with third parties. Hedging derivatives can be entered also to hedge highly probable future transactions; b) effectively managing the economic margin (positioning). It consists in entering purchase/sale commodity contracts in both commodity and financial markets aiming at altering the risk profile associated to a portfolio of physical assets of each business unit in order to improve margins associated to those assets in case of favorable trends in the commodity pricing environment; c) arbitrage. It consists in entering purchase/sale commodity contracts in both commodity and financial markets, targeting the possibility to earn a profit (or reducing the logistical costs associated to owned assets) leveraging on price differences in the marketplace; d) proprietary trading. It consists in entering purchase/sale commodity contracts in both commodity and financial markets, targeting to earn an uncertain profit, should certain expectations fulfill about a favorable trend in the commodity pricing environment; e) Asset Backed Trading (ABT). It consists in entering proprietary trading activities in commodity and financial markets, in order to maximize the economic value of the flexibilities associated with Eni’s assets and contracts. Price risks related to asset backed trading activities are mitigated by the natural hedge granted by the assets’ availability. Such risk management activity can be implemented through strategies of dynamic forward trading where the underlying items are represented by the Company’s assets. The framework defined by Eni’s policies and guidelines prescribes that measurement and control of market risk be performed on the basis of maximum tolerable levels of risk exposure defined in terms of limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre- defined time horizon, or in accordance with value-at-risk techniques. Those techniques make a statistical assessment of the market risk on the Group’s activity, i.e., potential gain or loss in fair values, due to changes in market conditions taking account of the correlation existing among changes in fair value of existing instruments. Eni’s finance departments define maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of value-at-risk, pooling Group companies risk positions. Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with established banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the Parent Company finance department. With regard to the commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of value-at-risk and stop loss in connection with exposure deriving from commercial activities and from Asset Backed Trading activities as well as exposure deriving from proprietary trading executed by the subsidiary Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools Group companies requests for negotiating commodity derivatives, ensuring execution services to the Trading Business Unit. The strategic risk is the economic risk which is intrinsic to each business unit. Exposure to that kind of risk does not undergo any systematic hedging or managing activities due to a strategic decision made by the Company, except for extraordinary business or market conditions. Therefore, internal risk policies and guideline do not foresee any mandate to manage, or any maximum tolerable level of risk exposure. To date, exposure to the strategic risk is associated with plans approved by Eni’s Board of Directors reflecting strategic decisions, plans for commercial development of proved and unproved oil and gas reserves, long-term gas supply contracts for the portion not balanced by in-place or highly probable sale contracts, refining margins and minimum compulsory stock. Relating to refining margins, the Board of Directors defines the maximum level of product volumes associated to these margins to be entered to the Asset Backed Trading. Any hedging activity of the strategic risk is the sole responsibility of Eni’s top management, due to the extraordinary conditions that may lead to such a decision. This kind of transaction is not subject to specific risk limits due to nature; however it is subject to monitoring and assessment activities. The three different market risks, for which management and control have been summarized above, are described below. F-73 Exchange rate risk Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency- denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice-versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance departments which pools Group companies positions, hedging the Group net exposure through the use of certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value on the basis of market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. The Value at risk (Var) techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period. Interest rate risk Changes in interest rates affect the market value of financial assets and liabilities of the company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. Borrowing requirements of Group companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be accounted for under the hedge accounting method in accordance with IAS 39. Value at risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, with a 99% confidence level and a 20-day holding period. Commodity risk Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil and gas prices generally has a negative impact on Eni’s results of operations and vice-versa. Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable margins. In order to accomplish this, Eni uses derivatives traded on the organized markets of ICE and NYMEX (futures) and derivatives traded over the counter (swaps, forward, contracts for differences and options) with the underlying commodities being crude oil, refined products or electricity. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable evaluation techniques. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. Value at risk deriving from commodity exposure is measured daily on the basis of a historical simulation technique, with a 95% confidence level and a one-day holding period. The following table shows amounts in terms of value at risk, recorded in 2011 (compared with 2010) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. Var values are stated in U.S. dollars, the currency most widely used in oil products markets. (Exchange and Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%) ((cid:1) million) 2010 2011 Interest rate (a) ...................................... Exchange rate ...................................... 2.82 0.99 1.09 0.13 1.55 0.50 1.60 0.51 5.34 0.85 1.07 0.15 2.65 0.44 2.92 0.34 High Low Average At year-end High Low Average At year-end _______ (a) Value at risk deriving from interest rate exposure includes the Eni Finance USA Inc department, since February 2010. F-74 (Commodity risk - Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%) (U.S. $ million) 2010 2011 Area oil, products (a) ............................ Area Gas & Power (b) .......................... 46.08 101.62 4.40 40.06 23.53 61.76 10.49 43.30 56.92 100.04 11.64 31.58 32.90 57.54 11.64 66.08 High Low Average At year-end High Low Average At year-end _______ (a) (b) Area oil, products refers to Eni Trading & Shipping, Polimeri Europa and the Refining & Marketing Division, including also consolidated entities outside Italy. The Gas & Power area refers to the Gas & Power Division, including also consolidated entities outside Italy. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of the business. The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty on a daily basis. Exceptional market conditions have forced the Group to adopt contingency plans and under certain circumstances to suspend eligibility to be a Group financial counterparty. Actions implemented also have been intended to limit concentrations of credit risk by maximizing counterparty diversification and turnover. Counterparties have also been selected on more stringent criteria particularly in transactions on derivatives instruments and with maturity longer than a three-month period. Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks. The actions implemented as part of Eni’s financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. In particular in 2011, Eni issued bonds to the retail Italian investors for a total amount of (cid:1)1.3 billion, of which (cid:1)1.1 billion at fixed rate, and approximately (cid:1)215 million at variable rate. In February 2012, Eni issued bonds addressed to institutional investors on the euro market for (cid:1)1 billion. The above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short-term commitments and due obligations also preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit particularly the committed ones. At present, the Group F-75 believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. At December 31, 2011, Eni maintained short-term committed and uncommitted unused borrowing facilities of (cid:1)11,897 million, of which (cid:1)2,551 million were committed, and long-term committed unused borrowing facilities of (cid:1)3,201 million. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial. Eni has in place a program for the issuance of Euro Medium Term Notes up to (cid:1)15 billion, of which about (cid:1)10.5 billion were drawn as of December 31, 2011. The Group has credit ratings of A and A-1 respectively for long and short-term debt assigned by Standard & Poor’s and A2 and P-1 assigned by Moody’s; the outlook is negative in both ratings. The tables below summarize the Group main contractual obligations (undiscounted) for finance debt repayments, including expected payments for interest charges, and trade and other payables maturities outstanding at year-end. Finance debt repayments including expected payments for interest charges The tables below summarize the Group main contractual obligations for finance debt repayments, including expected payments for interest charges. Dec. 31, 2010 ((cid:1) million) 2011 2012 2013 2014 2015 2016 and thereafter Total Maturity year Non-current liabilities ............... Current financial liabilities ....... Fair value of derivative instruments ................................. Interest on finance debt ............. Guarantees to banks .................. 963 6,515 1,131 8,609 720 339 3,583 2,485 2,009 2,815 9,413 276 3,859 712 74 2,559 654 18 2,027 563 48 2,863 460 85 9,498 1,726 21,268 6,515 1,632 29,415 4,835 339 Dec. 31, 2011 ((cid:1) million) 2012 2013 2014 2015 2016 2017 and thereafter Total Maturity year Non-current liabilities ............... Current financial liabilities ....... Fair value of derivative instruments ................................. Interest on finance debt ............. Guarantees to banks .................. 1,635 4,459 1,789 7,883 832 576 3,010 5,076 2,936 2,840 9,378 303 3,313 761 74 5,150 664 87 3,023 553 52 2,892 485 112 9,490 1,595 24,875 4,459 2,417 31,751 4,890 576 Trade and other payables The tables below summarize the Group trade and other payables by maturity. Dec. 31, 2010 ((cid:1) million) Trade payables .............................................................. Advances, other payables ............................................ Maturity year 2011 2012-2015 2016 and thereafter 13,111 9,464 22,575 29 29 38 38 Total 13,111 9,531 22,642 F-76 Dec. 31, 2011 ((cid:1) million) Trade payables .............................................................. Advances, other payables ............................................ Maturity year 2012 2013-2016 2017 and thereafter 13,436 9,476 22,912 32 32 38 38 Total 13,436 9,546 22,982 Expected payments by period under contractual obligations and commercial commitments In addition to finance debt and trade payables presented in the financial statements, the Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations are take-or-pay clauses in contracts of the Gas & Power segment, whereby the Company obligations consist of off-taking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors. The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis. ((cid:1) million) Maturity year Operating lease obligations (a) Decommissioning liabilities (b) Environmental liabilities (c) .... Purchase obligations (d) ............ Gas: - take-or-pay contracts ............... - ship-or-pay contracts ............... Other take-or-pay or ship-or-pay obligations .............. Other purchase obligations (e) ... Other obligations ..................... Memorandum of intent relating Val d’Agri .................... _______ 2012 2013 2014 2015 2016 839 98 269 21,401 19,972 1,034 170 225 4 534 179 306 21,034 19,688 988 165 193 4 440 305 251 20,943 19,656 919 176 192 4 250 95 221 20,131 18,932 898 172 129 3 161 165 81 17,743 16,587 847 161 148 3 2017 and thereafter 255 13,287 798 191,118 182,112 5,816 1,079 2,111 124 Total 2,479 14,129 1,926 292,370 276,947 10,502 1,923 2,998 142 4 22,611 4 22,057 4 21,943 3 20,700 3 18,153 124 205,582 142 311,046 (a) (b) (c) (d) (e) Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings. Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well- plugging, abandonment and site restoration. Environmental liabilities do not include the environmental charge of 2010 amounting to (cid:1)1,109 million for the proposal to the Italian Ministry for the Environment to enter into a global transaction related to nine sites of national interest because the dates of payment are not reasonably estimable. Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S. ((cid:1)2,750 million). F-77 Capital expenditure commitments In the next four years, Eni plans to make capital expenditures of (cid:1)59.6 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at December 31, 2011. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties. Such costs are included in the amounts shown. ((cid:1) million) Maturity year 2012 2013 2014 2015 2016 and thereafter Committed on major projects ....................... Other committed projects ............................. 6,103 7,411 13,514 6,275 5,446 11,721 5,013 3,498 8,511 3,309 2,709 6,018 12,286 3,073 15,359 Total 32,986 22,137 55,123 The amount shown in the table above include committed expenditures to execute environmental investments, following Eni’s proposal to the Italian Ministry for the Environment for a global settlement on certain environmental issues. Other information about financial instruments The carrying amount of financial instruments and relevant economic effect as of and for the years ended December 31, 2010 and 2011 consisted of the following: ((cid:1) million) Held-for-trading financial instruments Non-hedging derivatives (a) ........................ Held-to-maturity financial instruments Securities (b) ................................................. Available-for-sale financial instruments Securities (b) ................................................. Receivables and payables and other assets/liabilities valued at amortized cost Trade and receivables and other (c)............. Financing receivables (b) ............................. Trade payables and other (d)........................ Financing payables (b) ................................. Assets at fair value through profit or loss (fair value option) Investments (b).............................................. Net assets (liabilities) for hedging derivatives (e) ......................... _______ 2010 Finance income (expense) recognized in Carrying amount Profit and loss account Equity Carrying amount 2011 Finance income (expense) recognized in Profit and loss account Equity 46 35 382 23,998 2,150 22,642 27,783 (13) 1 9 (110) 84 26 (535) 17 62 (9) 262 76 1 8 (6) 24,730 2,174 22,982 29,597 (65) 112 (123) (851) (320) (402) 47 32 (309) 76 (a) (b) (c) (d) (e) In the profit and loss account, economic effects were recognized as income within “Other operating income (loss)” for (cid:1)188 million (income for (cid:1)118 million in 2010) and as expense within “Finance income (expense)” for (cid:1)112 million (expense for (cid:1)131 million in 2010). Income or expense were recognized in the profit and loss account within “Finance income (expense)”. In the profit and loss account, economic effects were essentially recognized as expense within “Purchase, services and other” for (cid:1)142 million (expense for (cid:1)128 million in 2010) (impairments net of reversal) and as income for (cid:1)77 million within “Finance income (expense)” (income for (cid:1)18 million in 2010) (positive exchange rate differences at year-end and amortized cost). In the profit and loss account, exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were primarily recognized within “Finance income (expense)”. In the profit and loss account, income or expense were recognized within “Net sales from operations” and “Purchase, services and other” as expense for (cid:1)292 million ((cid:1)414 million at December 31, 2010) and within “Finance income (expense)” for (cid:1)17 million (income for (cid:1)13 million in 2010) (time value component). F-78 Fair value of financial instruments Following the classification of financial assets and liabilities, measured at fair value in the balance sheet, is provided according to the fair value hierarchy defined on the basis of the relevance of the inputs used in the measurement process. In particular, on the basis of the features of the inputs used in making the measurements, the fair value hierarchy shall have the following levels: (a) Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities; (b) Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities that have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices); and (c) Level 3: inputs not based on observable market data. Financial instruments measured at fair value in the balance sheet as of at December 31, 2011, were classified as follows: (i) level 1, “Other financial assets held for trading or available for sale” and “Non-hedging derivatives - Future”; and (ii) level 2, derivative instruments different from “Future” included in “Other current assets”, “Other non-current receivables”, “Other current liabilities” and “Other non-current liabilities”. During the 2011, no transfers were done between the different hierarchy levels of fair value. The table below summarizes the amount of financial instruments valued at fair value: ((cid:1) million) Note Dec. 31, 2010 Dec. 31, 2011 Current assets Other financial assets available for sale .......................................... Non-hedging derivatives - Future ................................................... Other non-hedging derivatives ........................................................ Cash flow hedge derivatives ............................................................ Non-current assets Non-hedging derivatives - Future ................................................... Other non-hedging derivatives ........................................................ Cash flow hedge derivatives ............................................................ Current liabilities Non-hedging derivatives - Future ................................................... Other non-hedging derivatives ........................................................ Cash flow hedge derivatives ............................................................ Non-current liabilities Non-hedging derivatives - Future ................................................... Other non-hedging derivatives ........................................................ Cash flow hedge derivatives ............................................................ (8) (13) (13) (13) (20) (20) (20) (25) (25) (25) (30) (30) (30) 382 33 593 210 420 102 10 646 475 344 157 262 68 1,494 157 2 712 33 63 1,605 121 3 588 37 Legal Proceedings Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements. The following is a description of the most significant proceedings currently pending. Unless otherwise indicated below, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably. 1. Environment 1.1 Criminal proceedings Eni SpA (i) Investigation of the quality of groundwater in the area of the refinery of Gela. In 2002, the Public Prosecutor of Gela commenced a criminal investigation concerning the refinery of Gela to ascertain the quality of groundwater in the area of the refinery. Eni is charged of having breached environmental rules concerning the pollution of water and soil and of illegal disposal of liquid and solid waste materials. The preliminary hearing phase was closed for one employee who would stand trial, while the preliminary hearing phase is ongoing for other defendants. During the hearings the Judge admitted as plaintiffs three environmental associations. On May 14, 2010, F-79 following the examination, the Court of Gela issued a sentence whereby on one side criminal accusation against the above mentioned employee was dismissed as a result of the statute of limitations, on the other side the defendant was condemned to the payment of legal costs and of a compensation to the plaintiffs. The amount of the compensation will be determined by a resolution of a Civil Court. The proceeding is pending before the Second Degree Court. (ii) Alleged negligent fire (Priolo). The Public Prosecutor of Siracusa commenced an investigation regarding certain Eni managers who were previously in charge of conducting operations at the refinery of Priolo (Eni Refining & Marketing Division divested this asset to ERG Raffinerie Mediterranee SpA in July 31, 2002) to ascertain whether they acted with negligence in connection with a fire that occurred at the Priolo plants on April 30 and May 1-2, 2006. After preliminary investigations the Public Prosecutor requested the opening of a proceeding against the mentioned managers for negligent behavior. The Ministry for the Environment has been acting as plaintiff. After the review of the technical appraiser and of the indictments issued by the Public Prosecutor, the proceeding has been continuing with the debate phase. (iii) Groundwater at the Priolo site – Prosecuting body: Public Prosecutor of Siracusa. The Public Prosecutor of Siracusa (Sicily) has started an investigation in order to ascertain the level of contamination of the groundwater at the Priolo site. The Company has been notified that a number of its executive officers are being investigated who were in charge at the time of the events subject to probe, including chief executive officers and plant general managers of the Company’s subsidiaries AgipPetroli SpA (now merged into the Parent Company Eni SpA in the Refining & Marketing Division), Syndial and Polimeri Europa. According to the technical survey the ground and the groundwater at the Priolo site should be considered polluted according to Legislative Decree No. 152/2006. This contamination was caused by a spill-over made in the period prior to 2001 and not subsequent to 2005; the equipment still operating on the site represent another source of risk, in particular the ones owned by ISAB Srl (ERG). According to the findings, the Public Prosecutor requested the dismissal of the proceeding. The decision of the Judge on the dismissal of the proceeding is still pending. (iv) Fatal accident Truck Center Molfetta – Prosecuting body: Public Prosecutor of Trani. On March 3, 2008, in the Municipality of Molfetta a fatal accident occurred that caused the death of four workers deputed to the cleaning of a tank car owned by the company FS Logistica, part of the Italian Railways Group. The tank was used for the transportation of liquid sulfur produced by Eni in the refinery of Taranto and destined to the client company Nuova Solmine. Consequently a criminal action commenced against certain employees of FS Logistica and of its broker “La Cinque Biotrans” and, under the provisions of Legislative Decree 231/2001, against the two above mentioned companies and the company responsible for the clean-up of the tank car - Truck Center. On October 26, 2009, the First Degree Court concluded that both the above mentioned persons and the three companies were guilty. Additionally, the documentation related to the trial was forwarded to the Public Prosecutor of Trani in order to ascertain the eventual responsibilities of Eni and Nuova Solmine employees in relation to the fatal accident and also to the Public Prosecutors of Taranto and Grosseto (competent for Nuova Solmine) in order to ascertain eventual irregularities in the procedures of handling and transporting liquid sulfur. Following the sentence, the Public Prosecutor of Trani commenced an investigation against a number of employees of Nuova Solmine and an employee of Eni’s Refining & Marketing Division, responsible for marketing liquefied sulfur. On May 11, 2010, Eni SpA, eight employees of the company and a former employee were notified of closing of the investigation that objected the manslaughter, grievous bodily harm and illegal disposal of waste materials. A number of defendants filled defensive memoranda. The Public Prosecutor has removed three defendants and transmitted evidence to the Judge for the Preliminary Investigations requesting to dismiss the proceeding. The Judge for the Preliminary Investigations accepted the above mentioned request. The Judge scheduled the hearing for the positions not dismissed to April 19, 2011, when the Judge admitted as plaintiffs against the above mentioned individuals all the parts, excluding the relative of one of the victims, whose position have been declared inadmissible lacking of cause of action. The Judge declared inadmissible all the requests in acting as plaintiff against Eni, under the provisions of Legislative Decree No. 231/2001 and of recent case law. Eni SpA and its indicted employees requested to stand a summary procedure. The Judge for the Preliminary Hearings accepted this request and also resolved to deny that Eni stand trial for civil responsibility at the summary procedure. On December 5, 2011 the Judge pronounced an acquittal sentence for the individuals involved and for Eni SpA, as the indictments are groundless. (v) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria – Prosecuting body: Public Prosecutor of Castrovillari. On June 11, 2010, the Company received a notification of a judicial measure for the preventive seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria, following a prior seizure of other areas in the same Municipalities notified through a judicial measure on February 2010. The above mentioned decisions were the result of an investigation commenced after the damage of the HDPE covering the zinc ferrites generated in the industrial site of Pertusola Sud and basing on the Court’s conclusions illegally stored in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria. The F-80 impounded areas are those where the above mentioned waste was stored. The proceeding is in the phase of the preliminary hearings. The circumstances object of investigation are the same considered in the criminal action concluded in 2008 with an acquittal sentence for one of the defendants while the Judge dismissed the accusation for all the other defendants as a result of the statute of limitations. In this case the criminal accusation is of omitted clean-up. Syndial SpA gave the availability for the removal of the waste materials, the related operations are still pending. All the operations for the removal of the waste materials from the three landfills were completed by the end of September 2011. The Public Prosecutor commenced investigations on the external areas subject to preventive seizure as disclosed above in order to identify further waste materials that should be removed. Syndial entered a transaction agreement with the Municipality of Cerchiara for the recognition of damages caused by the unauthorized landfills. The Municipality of Cerchiara renounced to all claims in relation to the circumstances investigated in the criminal proceeding. (vi) Gas & Power Division – Industrial site of Praia a Mare. Based on complaints filed by certain offended persons, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors which those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. On the basis of the findings of independent appraisal reports, in the course of 2009 the Public Prosecutor resolved that a number of ex-manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants would stand trial for culpable manslaughter, culpable injuries, environmental disaster and negligent conduct about safety measures on the workplace. The proceeding will continue with the debate phase. Syndial SpA (vii) Syndial SpA (company incorporating EniChem Agricoltura SpA – Agricoltura SpA in liquidation – EniChem Augusta Industriale Srl - Fosfotec Srl) – Proceeding about the industrial site of Crotone. In 2010, the Public Prosecutor of Crotone started an inquiry about a landfill site located in the municipal area. The landfill site was taken over by Eni’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial waste from Montedison activities till 1989 and then no more waste was discharged there. Eni’s subsidiary started a plan to put on safety the landfill site. On May 3, 2011, the Public Prosecutor notified certain persons, including a number of managers of Eni’s subsidiaries, who took over the ownership of the landfill site in the course of the years that criminal investigations have commenced. The Public Prosecutor has charged the investigated persons with the alleged crimes of environmental disaster and poisoning of substances used in the food chain due to the circumstance that the landfill site was partially located under the seabed. In addition the Public Prosecutor has claimed the alleged crime of omitted clean-up of the area. The Public Prosecutor requested the performance of probationary evidence. The defending counsel filed memoranda claiming that Eni’s managers were not involved in the handling of the landfill site. Investigations are ongoing. In the next hearing the Judge for the Preliminary Hearing will identify the expert in charge of made the technical assessment requested by the Public Prosecutor. (viii) Porto Torres – Prosecuting body: Public Prosecutor of Sassari. In March 2009, the Public Prosecutor of Sassari (Sardinia) resolved to commence a criminal trial against a number of executive officers and managing directors of companies engaging in petrochemicals operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial. The charge involves environmental damage and poisoning of water and crops. The Province of Sassari, the Association Anpana (animal preservation), the company Fratelli Polese Snc, situated in the industrial site and the Municipality of Porto Torres have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine fauna of the industrial port of Porto Torres. The Judge also resolved that Syndial SpA, Polimeri Europa SpA, Ineos Vinyls and Sasol Italy SpA would bear civil liability. Then, the Judge based on the memoranda filed by the defending counsels resolved that all defendants would stand trial before a jurisdictional body of the Italian criminal law which is charged with judging the most serious crimes. Thus the Judge accepted the conclusions of the Public Prosecutor that claimed the crimes of environmental damage and poisoning of water and crops. The proceeding continues with the debate phase. 1.2 Civil and administrative proceeding Syndial SpA (former EniChem SpA) (i) Alleged pollution caused by the activity of the Mantova plant. In 1992, the Ministry for the Environment summoned EniChem SpA (now Syndial SpA) and Montecatini SpA (now Edison SpA) before the Court of Brescia. F-81 The Ministry requested, primarily, environmental remediation for the alleged pollution caused by the activity of the Mantova plant from 1976 until 1990, and provisionally, in case there was no possibility to remediate, the payment of environmental damages. Edison agreed on a settlement with the Ministry whereby Edison quantified compensation for environmental damage freeing from any obligation Syndial, which purchased the plant in 1989. Negotiations between the parts for the quantification of the environmental damage (relating only to 1990) are underway; the judgment has been postponed to the hearing of May 24, 2012. (ii) Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. On December 13, 2002, EniChem SpA (now Syndial SpA), jointly with Ambiente SpA (now merged into Syndial SpA) and European Vinyls Corporation Italia SpA (EVC Italia, then Ineos Vinyls SpA, actually Vinyls Italia SpA) was summoned before the Court of Venice by the Province of Venice. The province requested compensation for environmental damages that initially were not quantified, allegedly caused to the lagoon of Venice by the Porto Marghera plants, which were already the subject of two previous criminal proceedings against employees and managers of the defendants. EVC Italia and the actual company, Vinyls Italia, presented an action to be indemnified by Eni’s Group companies in case the alleged pollution is proved. The Province of Venice, in the preliminary stage of the proceeding, filed claims amounting to (cid:1)287 million. Syndial submitted its written reply evidencing that the above mentioned damage quantification has been made lacking of probations for the damage and based on evidence that allowed the Court of First and Second Instance to disclaim EniChem of any responsibility through definitive sentence. In the hearing on October 16, 2009, scheduled to review the technical appraisal, the Court declared the interruption of the proceeding because Vinyls Italia had undergone a reorganization procedure. The proceeding has been suspended until April 22, 2010 when the Province of Venice pursuant to Article 303 of the Code of Civil Procedure restarted the proceeding. The proceeding continued with the review the position of Vinyls and Syndial. The judgment is still pending. (iii) Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone – Prosecuting Bodies: the Council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region. The Council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region requested Syndial to appear before the Civil Court of Milan to face charges of causing environmental damage caused by the operations of Pertusola Sud SpA (merged in EniChem, now Syndial) in the Crotone site. This first degree proceeding was generated in January 2008, by the unification of two different actions, the first brought by Calabria Region in October 2004, the second one by the Council of Ministers, the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region commenced in February 2006. The Calabria Region is claiming compensation amounting to (cid:1)129 million for the site environmental remediation and clean-up on the basis of the cost estimation provided in the remediation plan submitted by the Delegated Commissioner, plus additional compensation amounting to a preliminary estimate of (cid:1)800 million relating to environmental damage, estimated increases in the regional health expenditures and damage to the public image to be fairly determined during the civil proceeding. The Council of Ministers, the Ministry for the Environment and the Delegated Commissioner is claiming compensation amounting to (cid:1)129 million for the site environmental remediation and clean-up (this request is analogous to that of the Calabria Region) and eventual compensation for other environmental damage to be fairly determined during the civil proceeding. In February 2007 the Ministry for the Environment filed with the Court an independent appraiser’s report issued by APAT that estimated a refundable environmental damage amounting to (cid:1)1,920 million, including the remediation and clean-up expenditures, increased by (cid:1)1,620 million from the original amount of (cid:1)129 million, and an estimation of environmental damage and other damage items amounting approximately to (cid:1)300 million. The amounts estimated by the independent appraiser, added to the claim of the Calabria Region, generate a total of (cid:1)2,720 million of potential compensation. In May and September 2007 Syndial presented its own technical advice that, based on what the Company believes to be well-founded circumstances, vigorously object the independent appraiser’s findings filed by the Ministry for the Environment on site contamination, the responsibility of Syndial in the contamination of the site, the criteria of estimate remediation costs, which according to the Company are erroneous, arbitrary and technically inadequate. In 2008, Eni’s subsidiary Syndial took charge of performing certain clean-up activities and on December 5, 2008, presented a global project to clean-up and remediate all interested areas. As for the approval procedure of the above mentioned project all interested parties approved the removal of the dump from the seafront to another area, the construction of an hydraulic barrier and of the related treatment plant of the groundwater (providing that if the subsequent monitoring would demonstrate the efficiency of the plant, Eni’s subsidiary would build-up a physical barrier in the seafront) and the start-up of the first lot of activities on the soil through in situ technologies on condition that all the waste present in the areas, recognized after a specific inspection. The environmental provision made by the Company is progressively utilized as the execution of the clean-up activities progresses. On October 7, 2009, an independent appraiser report was filed that reviewed the environmental status of the site and estimated the remediation costs while the estimate of both the health damage caused by the pollution and the environmental damage would be issued in a further independent appraiser report. The findings of the independent appraisers are substantially in line with the issues expressed by Syndial on the measures for the environmental remediation and clean-up, based on a risk analysis aimed to define F-82 effective and specific actions. The clean-up project, approved to a great extent by the Ministry for the Environment and the Calabria Region, has been considered substantially adequate. The independent appraisers affirmed the necessity of clean-up measures that were not planned by Syndial on one of the external areas (the so-called archaeological area) and considered being unnecessary the dredging of sea sediments. The estimated clean-up costs are in line with the estimate made by Syndial. The independent appraiser report is less favorable to Syndial because it identifies as source of the contamination the recent management of the production slag. The independent appraiser report evaluated that the production technology was a BAT (Best Available Technology), instead the slag treatment could be performed in a more respectful way for the environment and the products (the so-called Cubilot) lacked the physic-chemical characteristic of stability that would avoided the emission of polluting agents in the soil. As regards the quantification of the environmental damage different by the remediation, the independent report APAT provided by the Ministry for the Environment quantified the damage for the lack of fruition of the site basing on the remediation costs that were significantly reduced by the independent appraiser report. In case the Judge resolves on the responsibility of Syndial in the contamination of the site based on the conclusions of the independent appraiser report, the Company could be liable, for the environmental damage different from the goods fruition (damage to the community, increases in the regional health expenditures), at least in part and as far as the damage is actually probed. On November 14, 2009, Syndial filed its objections to the independent appraiser report, sharing the conceptual model adopted by the independent appraiser report but demonstrating that the site contamination should be charged mainly to past management of the pollution slag on part of other operators that operated the site until the ’70s. On November 11, 2009 the Calabria Region filed its objection to the independent appraiser report affirming that the environmental damage to the surrounding areas of the site has not been assessed by the independent appraisers. The hearing for the review of the independent appraiser report and of the parts objections, assigned to another Judge, took place on April 13, 2010. During the hearing the Calabria Region required the revise of the independent appraiser report. The Judge rejected the request. As regards the ascertainment of the existence of a residual environmental damage not remedied by the clean-up activities, the Board State of Lawyers on behalf of the Ministry for the Environment requested an evaluation of the impact of the new regulation on the above mentioned damage. Syndial filed a document explaining the modification of the environmental damage regulation. The Judge scheduled the deadline for the filing of the counterparts’ objections to such document for September 16, 2010, and September 30, 2010, for the submission of Syndial reply. The findings related to the modification of the Environmental Damage regulation introduced by the Article 5-bis of the Law Decree No. 135/2009 submitted by all the parties will be discussed in the next hearing scheduled for November 17, 2010. On September 15, 2010, the Calabria Region submitted a memorandum objecting to the documents filed by Syndial in the hearing of April 13, 2010. In September 30, 2010, Syndial filed a memorandum on the impact of the new Italian regulation about the environmental damage as per Law Decree No. 135/2009 on the proceeding. With the act of December 21, 2010, the Judge deemed the acquired elements sufficient for the closing of the proceeding. The hearing for the final decision was postponed to November 16, 2011, for the filing of the outcome. In the hearing of November 16, 2011, the Ministry for the Environment, the Council of Ministers, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region filed their outcome confirming the requests included in the summon and requested a new independent technical assessment. Syndial objected the inadmissibility of all the requests filed by the counterparts. All the parts involved in the proceeding filed their final memoranda with the Court. On February 24, 2012, the Court sentenced Syndial to correctly execute the environmental clean-up of the site and to pay to the Presidency of the Council of Ministers and the Ministry for Environment the sum of (cid:1)56.2 million plus interest charges accrued from the plaintiffs’ claims, while rejecting the claims of the Calabria Region. Eni accrued an environmental risk provision that is progressively utilized for the clean-up activities. However, discussions have been going on in order to arrange for a possible transaction of all environmental claims pending on this matter. (iv) Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore – Prosecuting body: Ministry for the Environment. With a temporarily executive decision dated July 3, 2008, the District Court of Turin sentenced the subsidiary Syndial SpA (former EniChem) to compensate for environmental damages that were allegedly caused when EniChem managed an industrial plant at Pieve Vergonte during the 1990- 1996 period, as claimed by the Ministry for the Environment. Specifically, the Court sentenced Syndial to pay the Italian Ministry for the Environment compensation amounting to (cid:1)1,833.5 million, plus legal interests that accrue from the filing of the decision. Syndial and Eni technical-legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary deem the amount of the environmental damage to be absolutely ill-founded as the sentence has been considered to lack sufficient elements to support such a material amount of the liability charged to Eni and its subsidiary with respect to the volume of pollutants ascertained by the Italian Environmental Minister. On occasion of the 2008 consolidated financial statements, management confirmed its stance of making no loss provision for this proceeding on the basis of the above mentioned technical legal advice, in concert with external consultants on accounting principles. In July 2009, Eni’s subsidiary Syndial filed an appeal against the above mentioned sentence, also requesting suspension of the sentence effectiveness. The Ministry for the Environment, in the appeal filed, requested to the Second Instance Court to adjust the first degree sentence F-83 condemning Syndial to the payment of (cid:1)1,900 million or alternatively (cid:1)1,300 million in addition to the amount assessed by the First Degree Court. In the hearing on December 11, 2009, the Second Instance Court considering the modification of Environmental Damage regulation introduced by the Article 5-bis of the Law Decree No. 135/2009 and following a request of the Board of State Lawyers decided the postponement to May 28, 2010, pending the Decree of the Ministry for the Environment related to the determination of the quantification criteria for the monetary compensation of the environmental damage pursuant to the above mentioned Article 5-bis of the Law Decree No. 135/2009. The Board of State Lawyers committed itself to not examine the sentence until the next hearing. In the hearing of May 28, 2010, Syndial requested a further postponement still pending the above mentioned Decree of the Ministry for the Environment. The Board of State Lawyers agreed to the request, justifying he postponement with the negotiation in place between the parties for the global solution of the proceeding, committing itself to not examine the sentence until the next hearing. The Judge decided the postponement to June 15, 2012. Another administrative proceeding is ongoing regarding a Ministerial Decree enacted by the Italian Ministry for the Environment. The decree provides that Syndial executes the following tasks: (i) the upgrading of a hydraulic barrier to protect the site; and (ii) the design of a project for the environmental remediation of Lake Maggiore. The Administrative Court of Piemonte rejected Syndial’s opposition against the outlined environmental measures requested by the Ministry for the Environment. However, the Court judged the prescriptions of the Ministry regarding the remediation of the site to be plain findings of an environmental enquiry to ascertain the state of the lake. Syndial has filed an appeal against the decision of the Court before an upper degree body, also requesting suspension of the effectiveness of the decision. The appeal has been put on hold considering that a plan to ascertain the environmental status of the site has been approved by all interested parties, including the Ministry and local Municipalities pursuant to the statement on April 28, 2009, which included certain recommendations. Syndial appealed against this statement and the related Ministerial Decree of approval in order to avoid the case to give implicit consent to the request (appealed by the Company) of the Minister that claimed that Syndial is obliged to execute the clean-up. On the contrary, Syndial has agreed on the scope of the plan to ascertain the environmental status of the site, as it has been actually implementing it. Syndial also presented a clean-up project for the groundwater and the soil, that hasn’t been approved, as the above mentioned prescriptions that have been prescribed are the object of the Company opposition in the above mentioned proceeding. In case Syndial should be found guilty, it would incur remediation and clean-up expenses, actually not quantifiable, that would be offset against any compensation for the environmental damage that Eni’s subsidiary is condemned to pay with regard to civil proceeding pending before the Second Instance Court of Turin. (v) Action commenced by the Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage. The Municipality of Carrara commenced an action before the Court of Genova requesting Syndial SpA to remediate and restore previous environmental conditions at the Avenza site and the payment of unavoidable environmental damage (amounting to (cid:1)139 million), further damages of various types (e.g. damage to the natural beauty of this site) amounting to (cid:1)80 million as well as damages relating to loss of profit and property amounting to approximately (cid:1)16 million. This request is related to an accident that occurred in 1984, as a consequence of which EniChem Agricoltura SpA (later merged into Syndial SpA), at the time owner of the site, carried out safety and remediation works. The Ministry for the Environment joined the action and requested environmental damage payment – from a minimum of (cid:1)53.5 million to a maximum of (cid:1)93.3 million – to be broken down among the various companies that ran the plant in the past. Syndial summoned Rumianca SpA, Sir Finanziaria SpA and Sogemo SpA, who ran the plant in previous years, in order to be guaranteed. A report produced by an independent expert charged by the Judge was filed with the Court. The findings of this report quantify the residual environmental damage at (cid:1)15 million. With a sentence of March 2008, the Court of Genova rejected all claims made by the Municipality of Carrara and the Ministry for the Environment. Both plaintiffs filed an appeal against this decision in June 2008 confirming the requests issued in the first judgment. Syndial filed in the appeal hearing, disputing the plaintiffs’ claims. The proceeding is underway without any further investigation. The hearing has been postponed to June 13, 2011 for the filing of the pleadings. In this hearing the parties filed their pleadings and the Judge postponed the hearing for the final decision to October 6, 2011. In this hearing the Court upheld the final decision without recommencing the investigation phase as requested by the Ministry for the Environment and the Municipality of Carrara. With the decision No. 1026 of October 22, 2011 the Second Instance Court confirmed the decision issued in the first judgment and rejected all the claims made by Municipality of Carrara, the Ministry for the Environment and Legambiente considering them without factual and legal basis, also deciding to offset the legal expenses between the parties. The administrations involved in the proceeding could still file an appeal before the Third Instance Court in the prescribed terms. (vi) Ministry for the Environment – Augusta harbor. The Italian Ministry for the Environment with various administrative acts prescribed companies running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Polimeri Europa, Syndial and Eni R&M. Pollution has been detected in this area primarily due to a high mercury concentration which is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above mentioned companies opposed said administrative actions, objecting in particular to the way in which remediation F-84 works have been designed and information on concentration of pollutants has been gathered. The Regional Administrative Court of Catania with the Sentence No. 1254/2007 annulled the said decisions. The Ministry and the Municipalities of Augusta and Melilli filed a claim for the revocation of the decision and requested the suspension of sentence effectiveness with the Administrative Council of the Sicily Region which accepted the claim. The recommendations, which the Council’s decision related, have been restated by the Ministry for the Environment with further administrative resolutions that have been appealed by the Eni companies. Again the Regional Administrative Court of Catania reiterated its decision to suspend the effectiveness of the Ministry’s acts. In January 2008 the Regional Court of Catania accepted further claims on this matter. In June 2008 the Ministry for the Environment and the Municipalities of Melilli and Augusta filed an appeal against the decision of the Regional Court of Catania with the Administrative Council of the Sicily Region, without a resolution of the issue of suspending the effectiveness of the Regional Court’s decisions. The hearing for the examination of both appeal pending with the Administrative Council of the Sicily Region that has been originally scheduled on December 11, 2008, has been postponed sine die due to preliminary issues pending with the Court of Justice of the European Community. In April 2008, the Eni companies challenged certain administrative acts of December 20, 2007 related to the execution of further clean-up and remediation works of sediments in the Augusta harbor. In this proceeding the Regional Court of Catania has ordered an independent appraiser report, issued on February 20, 2009, that resulted favorable to the objections of the objecting companies. The proceeding is pending. In May 2008, the Eni companies also challenged with the Regional Court of Catania, requesting the suspension of administrative act effectiveness, certain decisions of an Administrative Body on March 6, 2008 (and other subsequent decisions). Those decisions were intended to enlarge the scope of the already approved project of environmental remediation and clean-up of the groundwater trough works of physic limitation and the new criteria used by the Administration Body in the restitution of the areas to their legitimate use. With regard to this last proceeding, basing on a request of the appealing companies, the Regional Court of Catania requested the decision of the Court of Justice of EU to decide on the correct application of the community principle, that represent the basis for the all appeals’ decision particularly the principles of the liability associated with the environmental damage, the proportionality in bearing the expenditures associated with environmental remediation and clean-up, as well as a criteria of reasonableness and diligent execution in remedying an environmental damage. On March 9, 2010, the European Court gave a sentence that basically represented a favorable outcome for Eni’s subsidiaries involved in the matter. Specifically, the European Court confirmed the community principle of the liability associated with the environmental damage, whereby central to its correct interpretation is the relation between cause and effect and the identification of the entity that is actually liable for polluting. In the hearing of October 21, 2010, the Court upheld the appeals filed by the counterparts while the filing of the Court’s decisions is still pending. On April 29, 2011 the Regional Administrative Court resolved that a number of the above mentioned decision could be overruled by certain administrative acts, thus requesting to specify to the Ministry for the Environment the decisions that could be considered still effective and the overruled ones. After the hearing of July 21, 2011 the Regional Administrative Court unified all the claims filed by the companies in a single procedure. The hearing for the discussion of all the claims took place on February 23, 2012; the Regional Administrative Court upheld the appeals filed by the counterparts while the filing of the Court’s decisions is still pending. It must be noted that the Public Prosecutor of Siracusa commenced a criminal action against an unknown party in order to verify the effective contamination of the Augusta harbor and the connected risks on the execution on the clean-up project proposed by the Ministry. The technical assessment disposed by the Public Prosecutor generated the following outcomes: a) no public health risk in the Augusta harbor; b) absence of any involvement on part of Eni companies in the contamination; and c) drainages dangerousness. Based on those findings, the Public Prosecutor decided to dismiss the proceeding. Eni SpA (vii) Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe – Prosecuting body: Delegated Commissioner. In March 2009 Eni and its subsidiary Sofid (now Eni Adfin) were notified of a bankruptcy clawback as part of a reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe which commenced under the provisions of Ministry of Production Activities, on November 30, 2004. The request regarded the override of all the payments made by those entities to Eni and Eni Adfin, as Eni agent for the receivables collection, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, for a total estimated amount of (cid:1)46 million plus interest. Eni and Eni Adfin were admitted as defendants. After the conclusion of the investigation phase and the filing of the final statements of the case and the memorandum of objections, the decision is still pending. Eni accrued a risk provision with respect to this proceeding. (viii) Claim for preventive technical inquiry – Court of Gela. On February 2012, Raffineria di Gela SpA, Syndial SpA and Eni SpA (R&M Division) were notified a claim issued by 18 parents of child born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aims at verifying the relation of causality between the malformation pathologies suffered by the children of the recurring parties and the environmental pollution caused by the Gela site (pollution deriving by the existence and activities at the industrial F-85 plants of the Gela refinery and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. At the actual stage the claims filed by the plaintiffs have not been made public. In any case, the same issue was purpose of previous inquiries in a number of proceedings, all resolved without the ascertainment of any illicit behavior on part of Eni or its subsidiaries. 2. Other judicial or arbitration proceedings Saipem SpA (i) CEPAV Uno and CEPAV Due. Saipem holds interests in the CEPAV Uno (50.36%) and CEPAV Due (52%) consortia that in 1991 signed two contracts with TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the construction of two railway tracks for high speed/high capacity trains from Milan to Bologna (almost completed) and from Milan to Verona (under construction). CEPAV Uno: with regard to the project for the construction of the line from Milan to Bologna, an Addendum to the contract between CEPAV Uno and TAV was signed on June 27, 2003, redefining certain terms and conditions of the contract. Subsequently, the CEPAV Uno Consortium requested a time extension for the completion of works and a claim amounting to (cid:1)800 million then increased to (cid:1)1,770 million. CEPAV Uno and TAV failed to solve this dispute amicably. CEPAV Uno opened an arbitration procedure as provided for under terms of the contract on April 27, 2006. The preliminary investigation of the arbitration procedure is still pending. On July 30, 2010 the independent consultants filed their finding that resulted partially favorable to the Company and in the subsequent hearings the counterparts filed their motion on preliminary issues and the related objections. In the next hearing of May 20, 2011 the independent consultants filed further reports on the above mentioned issue. The deadline for the submission of the arbitration determination has been scheduled for December 31, 2013. The next hearing has been scheduled for March 15, 2012. The Judge also scheduled the deadline for the filing of the final statements of the case and the memorandum of objections related to the second report of the independent consultants for December 30, 2011 and February 15, 2012, respectively. On March 23, 2009, the Arbitration Committee determined the TAV right to extend the assessment made by the independent accounting consultant to the subcontractors appointed by the Consortium, the contractors, or assignees. Basing on the alleged invalidity of Arbitration Committee determination, on April 8, 2010, the Consortium notified to the counterparts the appeal to this decision requesting its suspension before the Appeal Court of Rome. In the hearing of September 22, 2010 the proceeding has been postponed to October 9, 2013 for the review of the findings. CEPAV Due: with regard to the project for the construction of a high-speed railway from Milan to Verona, in December 2004, CEPAV Due presented the final project, prepared in accordance with Law No. 443/2001 on the basis of the preliminary project approved by an Italian governmental Authority (CIPE). As concerns the arbitration procedure, commenced on December 28, 2000, requested by CEPAV Due against TAV for the recognition of costs incurred by the Consortium in the ten-year period from 1991 through 2000 plus damages suffered, in January 2007, the Arbitration Committee determined the Consortium’s right to recover the costs incurred in connection with the design activities performed. The technical independent survey to assess the amount of compensation was submitted on October 19, 2009. The trial ended on February 23, 2010, with the resolution of the arbitration that required TAV to pay to CEPAV Due Consortium an amount of (cid:1)44,176,787 plus legal interest and compensation for inflation accrued from the submission of the arbitration until the date of effective damage payment; the Court also required TAV to pay (cid:1)1,115,000 plus interest and compensation for inflation accrued from October 30, 2000, until the date of effective damage payment. TAV filed with the Second Instance Court of Rome an appeal against the partial arbitration committee’s determination of January 2007. The hearing for the examination of the pleadings has been scheduled initially for January 28, 2011, and subsequently postponed since the negotiations for the settlement of the proceeding are ongoing. In February 2007, the Consortium CEPAV Due notified to TAV a second request of arbitration following the Law Decree No. 7 of December 31, 2007, that revoked the concessions awarded to TAV resulting in the annulment of arrangements signed between TAV and the Consortium to build the high-speed railway section from Milan to Verona. The European Court of Justice was requested to rule on this matter. Subsequently, Law No. 133/2008 established again the concessions awarded to TAV resulting in the continuation of the arrangements between the CEPAV Due Consortium and a new entity in charge of managing the Italian railway system. The second arbitration proceeding continued in order to determinate the damages suffered by the Consortium even in the period prior to the revocation of the concession. The arbitration proceeding was suspended, since the negotiations between the parties in order to sign the integration to the existing agreement and to settle the arbitration already closed and the pending one are underway. The deadline for the submission of the arbitration determination was for December 31, 2010. On March 7, 2011, RFI proposed to CEPAV Due an agreement in order to settle all the existing claims between the parts. On March 15, 2011, CEPAV Due adhered to the agreement. On August 2011, RFI finalized the agreement with the payment of the requested amount. On November 16, 2011, the arbitration committee declared the termination of the arbitration; and on January 20, 2012, the counterparts renounced to all claims before the Appeal Court of Rome. F-86 (ii) Fos Cavaou. An arbitration proceeding before the International Chamber of Commerce of Paris between the client company Société du Terminal Methanier Fos Cavaou (“STMFC”) and the contractor STS, a French consortium participated by Saipem SA (50%), Technimont SpA (49%) and Sofregaz SA (1%) is pending. On July 11, 2011 the counterparts tried to define a settlement agreement under the provisions of the Regulations of Conciliation and Arbitration of the Internaltional Chamber of Commerce of Paris. The settlement procedure was concluded unsuccessfully on December 31, 2011 because STMFC refused the postponement of the deadline. On January 24, 2012 STS was notified by the secretariat of the International Arbitration Court of the International Chamber of Commerce the commencement of an arbitration procedure issued by STMFC. The memorandum filed by STMFC supporting the arbitration proceeding claimed the payment of (cid:1)264 million for damage payment, delay penalties and costs incurred for the termination of the works. Approximately (cid:1)142 million of the total amount requested related to loss of profit, which is an item that cannot be compensated based on the existing contractual provisions with the exception of fraudulent and serious culpable behavior. The existence of fraudulent and serious culpable behaviors performed by STS that could exclude the contractual limitation of responsibility could be probably considered without factual and legal basis. STS is preparing its defensive memorandum, including a counter claim for a total amount of approximately (cid:1)150 million as damage repayment due to the excessive interference of STMFC in the execution of the works and payment of extra works not recognized by the client. 3. Antitrust, EU Proceedings, Actions of the Authority for Electricity and Gas and of Other Regulatory Authorities 3.1 Antitrust Eni SpA (i) Abuse of dominant position of Snam alleged by the Italian Antitrust Authority. In March 1999, the Italian Antitrust Authority concluded its investigation started in 1997 and: (i) found that Snam SpA (merged in Eni SpA in 2002) abused its dominant position in the market for the transportation and primary distribution of natural gas relating to the transportation and distribution tariffs applied to third parties and the access of third parties to infrastructure; (ii) fined Snam for (cid:1)2 million; and (iii) ordered a review of the practices relating to such abuses. Snam believes it has complied with existing legislation and appealed the decision with the Regional Administrative Court of Lazio requesting its suspension. On May 26, 1999, stating that these decisions are against Law No. 9/1991 and the European Directive 98/30/EC, this Court granted the suspension of the decision. The Authority did not appeal this decision. The decision on the merit of this dispute is still pending before the same Administrative Court. (ii) European Commission’s investigations on players active in the natural gas sector. In 2011 Eni divested its interests in the international gas transport pipelines and carriers on the routes from Northern Europe and Russia. The transaction was part of the commitments agreed upon with the European Commission with a view to settle an ongoing antitrust proceeding about the alleged unjustified refusal on part of Eni to grant access to the above mentioned infrastructures to third parties, connected with the Italian gas transport system. The execution of the commitments, which related to the divestment of Eni’s interests in the entities owning the TENP (Germany), Transitgas (Switzerland) and TAG (Austria) pipelines, the latter sold to an entity controlled by the Italian State due its strategic relevance, permitted to Eni to settle the above mentioned antitrust proceeding without the ascertainment of any illicit behavior and consequently without sanctions. (iii) Inquiry in relation to gas transportation. In March 2012, the Italian Antitrust Authority started an inquiry targeting alleged anti competitive behavior charged to Eni in connection with the refusal to dispose of secondary transport capacity on the Transitgas and TAG pipelines to third parties. The inquiry is expected to be concluded by March 15, 2013. (iv) Inquiry in relation to unfair marketing practices in the retail gas & power sector. In February 2012, the Italian Antitrust Authority informed Eni of the start of an inquiry targeting alleged violation – in the period October 2008-January 2012 – of the legislation on the unfair marketing practices against 80 consumers, in relation to the activation of gas and electricity supply contracts. The preliminary investigation should be finalized within 150 days. Eni SpA, Polimeri Europa SpA and Syndial SpA (v) Inquiries in relation to alleged anti-competitive agreements in the area of elastomers – Prosecuting Body: European Commission. In December 2002, inquiries were commenced concerning alleged anti-competitive agreements in the field of elastomers. The most important inquiry referred to BR and ESBR elastomers and was finalized on November 29, 2006, when the Commission fined Eni and its subsidiary Polimeri Europa for an amount F-87 of (cid:1)272.25 million. Eni and its subsidiary filed claims against this decision before the European Court of First Instance in February 2007. The hearings took place in October 2009. In July 13, 2011, the First Instance Court filed the decision to reduce the above mentioned fine to the amount of (cid:1)181.5 million. The companies involved in the decision and the European Commission filed a claim before the European Court of Justice. In consideration of the above mentioned decision of the European Commission and pending the outcome, Polimeri Europa presented a bank guarantee for (cid:1)200 million and paid the residual amount of the fine. In August 2007, with respect to the above mentioned decision of the European Commission, Eni submitted a request for a negative ascertainment with the Court of Milan aimed at proving the non-existence of alleged damages suffered by tire BR/SBR manufacturers. The Court of Milan declared the appeal inadmissible appealing against a sentence of the Appeal Court of Milan. The sentence for the appeal is still pending. Eni accrued a risk provision with respect to this proceeding. Pending the outcome, a risk provision was accrued. 3.2 Regulation (i) Distribuidora de Gas Cuyana SA. Formal investigation of the agency entrusted with the regulations for the natural gas market in Argentina. Enargas started a formal investigation on some operators, among them Distribuidora de Gas Cuyana SA, a company controlled by Eni. Enargas stated that the company improperly applied conversion factors to volumes of natural gas invoiced to customers and requested the company to apply the conversion factors imposed by local regulations from the date of the default notification (March 31, 2004) without prejudice to any damage payment and fines that may be decided after closing the investigation. In April 2004 the company filed a defensive memorandum. On April 28, 2006, the company formally requested the acquisition of documents from Enargas in order to have access to the documents on which the allegations are based. (ii) Preliminary investigation of the Authority for Electricity and Gas on the billing of the tariff balance to final gas clients and periodicity of the billing. On July 26, 2011 the Authority for Electricity and Gas (Resolution VIS 75/11) sentenced the termination of an investigation against Eni (commenced under the provisions of Resolution VIS 36/10 of May 25, 2010) imposing a fine amounting to (cid:1)722,000. Eni paid the sanction and filed a claim before the Regional Administrative Court against the sentence in order to defense its rights and interests. 4. Court inquiries (i) EniPower SpA. In June 2004, the Milan Public Prosecutor commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. These inquiries were widely covered by the media. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately dismissed. The Court presented EniPower (commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of process in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In its meeting of August 10, 2004, Eni’s Board of Directors examined the aforementioned situation and Eni’s CEO approved the creation of a task force in charge of verifying the compliance with Group procedures regarding the terms and conditions for the signing of supply contracts by EniPower and Snamprogetti and the subsequent execution of works. The Board also advised divisions and departments of Eni to cooperate fully in every respect with the Court. From the inquiries performed, no default in the organization emerged, nor deficiency in internal control systems. External experts have performed inquiries with regard to certain specific aspects. In accordance with its transparency and firmness guidelines, Eni took the necessary steps in acting as plaintiff in the expected legal action in order to recover any damage that could have been caused to Eni by the illicit behavior of its suppliers and of their and Eni employees. In the meantime, preliminary investigations have found that both EniPower and Snamprogetti are not to be considered defendants in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearings requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parts under the provisions of Legislative Decree No. 231/2001. Further employees of the companies involved were identified as defendants to account for their civil responsibility. After the filing of the pleadings occurred in the hearing of July 12, 2011, the proceeding was postponed to September 20, 2011. In that date the Court of Milan concluded that nine persons were guilty for the above mentioned crimes. In addition they were condemned jointly and severally to the payment of all F-88 damages to be assessed through a dedicated proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations while the trial ended with an acquittal for 15 individuals. In relation to the companies involved in the proceeding, the Court found that 7 companies are liable based on the provisions of Legislative Decree No. 231/2001, imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni group companies, reversing a prior decision made by the Court. This decision was made probably on the basis of a pronouncement made by a supreme court which stated the illegitimacy of the constitution as plaintiffs made by any legal entity which is indicted under the provisions of Legislative Decree No. 231/2001. The Court filed the ground of the judgment in December 19, 2011. (ii) Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties in favor to the closing of certain transactions with two oil product trading companies. Within such investigation, on March 10, 2005, the Public Prosecutor of Rome notified Eni of two judicial measures for the seizure of documentation concerning Eni’s transactions with the said companies. Eni is acting as plaintiff in this proceeding. The Judge for the Preliminary Hearings rejected most of the dismissal requests issued by the Public Prosecutor. Basing on the decision of the Judge for the Preliminary Hearings, the Public Prosecutor of Rome notified Eni, as injured part, the summon against two former managers of the company charged of aggravated fraud related to the relevant patrimonial damage caused to the injured part through the abuse of working relations and activities. The first hearing, scheduled for January 27, 2010, was postponed to March 30, 2010. In the hearing of March 30, 2010, Eni was admitted as plaintiff against all the defendants. Subsequently the legal defense of one of the former managers opted for the “non-conditioned” plea-bargain. The Judge removed this position from the main proceeding postponing the related hearing to the same date of the principal one. In the hearing of June 23, 2010 related to the position of a former manager of Eni, the Public Prosecutor, made a request of acquittal coherently with the previous request of dismissal of that defendant. Eni legal defense asked the conviction of the defendant. After the debate, in the hearing of July 13, 2010, the Court acquitted that defendant. The Court would file the grounds of the judgment within the next 90 days. After definition of the preliminary investigation requests, the proceeding was postponed few times. In the hearing of December 7, 2011 the review of the witnesses took place. Subsequently, the next hearing has been scheduled for October 19, 2012 in order to discuss about the statute of limitations. (iii) TSKJ Consortium. Investigations by U.S., Italian and other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by KBR, Technip, and JGC. Beginning in 1994, the TSKJ Consortium was involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem as of October 1, 2008. Eni holds a 43% participation in Saipem. In connection with the sale of Snamprogetti to Saipem, Eni agreed to indemnify Saipem for a variety of matters, including potential losses and charges resulting from the investigations into the TSKJ matter referred to below, even in relation to Snamprogetti subsidiaries. In recent years the proceeding was settled with the U.S. authorities and certain Nigerian authorities, which had been investing into the matter. The proceeding is still pending before Italian judicial authorities. The proceedings in the U.S.: in 2010, a global transaction to settle the proceeding was defined with the U.S. Authorities investigating the matter (the U.S. DoJ and the U.S. SEC) following long and complex discussions which commenced in 2009. Particularly, on July 2010, Snamprogetti Netherlands BV signed a deferred prosecution agreement with the DoJ whereby the Department filed a deed which could lead to a criminal proceeding against Snamprogetti Netherlands BV for having violated certain rules of the FCPA if certain procedures are not met. Also the parties agreed upon a fine amounting to $240 million was accrued in a risk provision in the 2009 consolidated financial statements. Eni and Saipem assumed the role of guaranteeing the effective fulfillment of the obligations agreed upon by Snamprogetti Netherlands BV with the U.S. Department of Justice, considering the contractual obligations assumed by Eni to indemnify Saipem as part of the divestment of Snamprogetti. If Snamprogetti Netherlands BV fulfills the obligations set by the agreement, the Department will refrain from continuing the criminal proceeding once a two-year frame has elapsed (which can be increased up to three years). The relevant cash settlement occurred in July 2010. In addition Snamprogetti Netherlands BV and the parent company Eni being an entity listed on the NYSE reached an agreement with the U.S. SEC whereby the two companies agreed to be subpoenaed and be judged having allegedly violated certain rules of the Security and Exchange Act of 1934 without pleading guilty. They both agreed to pay jointly and severally an amount of $125 million to the SEC in relation to the disgorgement of profit. The relevant cash settlement occurred in July as Eni actually paid the amount considering the contractual obligations assumed by Eni to indemnify Saipem as part of the divestment of Snamprogetti. F-89 The proceedings in Italy: beginning in 2004, the TSKJ matter has prompted investigations by the Public Prosecutor’s office of Milan against unknown persons. Since March 10, 2009, the Company has received requests of exhibition of documents from the Public Prosecutor’s office of Milan. The events under investigation cover the period since 1994 and also concern the period of time subsequent to the June 8, 2001, enactment of Italian Legislative Decree No. 231 concerning the liability of legal entities. An adverse conclusion of the investigations cannot be excluded which may have a significant impact on the Company’s result. Under present conditions, due to the complexity of the legal and factual analyses – including questions concerning jurisdiction and the application of statutes of limitations – it is not possible at this time to reasonably quantify the potential losses that may arise from these proceedings, in case any negative developments occur. On August 12, 2009, a decree issued by the Judge for the Preliminary Investigations at the Court of Milan was served on Eni (and on July 31, 2009 on Saipem SpA, as legal entity incorporating Snamprogetti SpA). The decree set a hearing in Court in relation to a proceeding ex Legislative Decree No. 231 of June 8, 2001 whereby the Public Prosecutor of Milan is investigating Eni SpA and Saipem SpA for liability of legal entities arising from offences involving international corruption charged to former managers of Snamprogetti SpA. The Public Prosecutor of Milan requested Eni SpA and Saipem SpA to be debarred from activities involving – directly or indirectly – any agreement with the Nigerian National Petroleum Corporation and its subsidiaries. The events referred to the request of precautionary measures of the Public Prosecutor of Milan cover TSKJ Consortium practices during the period from 1995 to 2004. In this regard, the Public Prosecutor claimed the inadequacy and violation of the organizational, management and control model adopted to prevent those offences charged to people subject to direction and supervision. At the time of the events under investigation, the Company had adopted a code of practice and internal procedures with reference to the best practices at the time. Subsequently, such code and internal procedures have been improved aiming at the continuous improvement of internal controls. Furthermore, on March 14, 2008, Eni approved a new Code of Ethics and a new Model 231 reaffirming that the belief that one is acting in favor or to the advantage of Eni can never, in any way, justify – not even in part – any behaviors that conflict with the principles and contents of the Code. On November 17, 2009 the Judge for the Preliminary Investigations rejected the request of precautionary measures of disqualification filed by the Public Prosecutor of Milan against Eni and Saipem. The Public Prosecutor of Milan appealed the above mentioned decision before the Third Instance Court. The Court decided that the request of precautionary measures be admissible according to Legislative Decree No. 231/2001 even in the case of international corruption. The issue would be subsequently examined by the Re-examination Court of Milan. On February 18, 2011, the Public Prosecutor of Milan, with respect to the guarantee payment amounting to (cid:1)24,530,580, even in the interest of Saipem SpA, renounced to contest the decision of rejection of precautionary measures of disqualification for Eni SpA and Saipem SpA issued by the Judge for the Preliminary Hearings. In the hearing of February 22, 2011, the Re-examination Court, taking note of the above mentioned renounce, declared inadmissible the appeal of the Public Prosecutor of Milan and closed the proceeding related to the request of precautionary measures of disqualification for Eni SpA and Saipem SpA. On November 3, 2010, the defense of Saipem was notified the conclusion of the investigations relating to the proceeding pending before the Court of Milan trough a deed by which the Court evidenced the alleged violations made by the five former Snamprogetti SpA (now Saipem SpA) and Saipem SpA being the parent company of Snamprogetti. The deed does not involve the Eni Group parent company Eni SpA. The charged crimes involve alleged corruptive events that have occurred in Nigeria after July 31, 2004. It is also stated the aggravating circumstance that Snamprogetti SpA reported a relevant profit (estimated at approximately $65 million). On December 3, 2010, the defense of Saipem was notified the opening of a proceeding with the first hearing scheduled for December 20, 2010. The subsequent hearings were dedicated to the exposition of the motivations of counterparts and in the hearing of January 26, 2011, the Public Prosecutor requested five former workers of Snamprogetti SpA (now Saipem) and Saipem SpA (as legal entity incorporating Snamprogetti) to stand trial. The first hearing before the Court of Milan took place on May 10, 2011. In the hearing of February 2, 2012, the Public Prosecutor, even if considering that the term for the occurrence of the statute of limitations for the individuals who are acting as plaintiffs, raised an issue of constitutional legitimacy for the incompatibility between the internal and international legislation on the statute of limitation, in particular the OECD convention on the fight against international corruption. In the subsequent hearing of March 8, 2012 the defenses replicated to the Prosecutor issue on the constitutional legitimacy of the so-called “short-term statute of limitations” in relation to international corruption. The hearing on the constitutional legitimacy has been postponed to April 5, 2012. It must be noted that the Board of Directors of Eni and Saipem in 2009 and 2010, respectively approved new guidelines and anti- corruption policies regulating Eni and Saipem management of the business. The guidelines integrated anti- corruption policies of the Company, aligning them to the international best practices, optimizing the compliance system and granting the highest respect of Eni, Saipem and their workers of the Code of Ethics, 231 Model and national and international anti-corruption policies. (iv) Gas metering. On May 28, 2007, a seizure order (in respect to certain documentation) was served upon Eni and other Group companies as part of a proceeding brought by the Public Prosecutor at the Courts of Milan. The order was also served upon five top managers of the Group companies in addition to third party companies and their top managers. The investigation alleges behavior which breaches Italian criminal law, starting from 2003, regarding the use of instruments for measuring gas, the related payments of excise duties and the billing of clients as well as relations with the Supervisory Authorities. The allegation regards, inter-alia, the offense contemplated by F-90 Legislative Decree of June 8, 2001, No. 231, which establishes the liability of the legal entity for crimes committed by its employee in the interests of such legal entity, or to its advantage. Accordingly, notice of the commencement of investigations was served upon Eni Group companies (Eni, Snam Rete Gas and Italgas) as well as third party companies. On November 26, 2009, a notice of conclusion of the preliminary investigation was served to Eni’s Group companies whereby 12 Eni employees, also including former employees, are under investigation. The exceptions filed in the notice include: (i) violations pertaining to recognition and payment of the excise on natural gas amounting to (cid:1)20.2 billion; (ii) violations or failure in submitting the annual statement of gas consumption and/or in the annual declarations to be filed with the Duty Authority or the Authority for Electricity and Gas; and (iii) a related obstacle which has been allegedly posed to the monitoring functions performed by the Authority for Electricity and Gas. On February 22, 2011, 12 Eni employees, also including former employees were notified the schedule of the preliminary hearing. In relation to a modification in the relevant legislation the Public Prosecutor requested to dismiss the proceeding for two Snam Rete Gas employees in connection with the crime of using faked instruments of gas measurement in the commercial practice relating the measurement activities at the station of Mazara del Vallo. In the hearing of July 12, 2011 were examined indictment and defense witnesses, while the Judge for the Preliminary Hearing postponed the hearing for eventual objections of the Public Prosecutor to October 5, 2011. In this hearing the Judge for the Preliminary Hearing considering the memoranda filed by the parties sentenced: • • • to dismiss the position of a manager of the Eni G&P Division for all the alleged crimes relating the obstacle to the monitoring functions performed by the Authority for Electricity and Gas for years 2006, 2007, 2008 because the indictment was groundless; to dismiss the position of a GreenStream BV employee for all the alleged crimes relating the violations pertaining to lack of formal declaration and recognition or payment of excise duties on hydrocarbons as well as the obstacle to the monitoring functions performed by the Authority for Electricity and Gas because when the alleged crimes occurred the mentioned employee was not the legal representative of GreenStream BV; to dismiss the position of a Snam Rete Gas employee in relation to the crime relating the obstacle to the monitoring functions performed by the Authority for Electricity and Gas to the extent that a violation for omitted communication to Authority for Electricity and Gas would have allegedly occurred, because the indictment was groundless. In the hearing of November 4, 2011 the defendants filed their objections to the motions of the Public Prosecutor. In the subsequent hearing of January 24, 2012 the Judge resolved to dismiss the proceeding against all defendants as well as to release seizure of the measurement instruments. The decision could be appealed by the Public Prosecutor. On March 7, 2012, the external lawyers defending the company, were notified an appeal to the Third Instance Court filed by the Public Prosecutor of Milan. The act did not involve all the dismissed defendants, but only some positions. The schedule of the hearing before the Third Instance Court is still pending. On February 23, 2010, Eni, Snam Rete Gas and Italgas received a notification requesting the collection of documents related to procedures of constitution, definition, update and implementation of Model 231 in the period from 2003 to 2008. On May 18, 2010, the Public Prosecutor of Milan requested the closing of the proceeding relating to a number of defendants, including a top manager for which the Public Prosecutor found no evidence supporting the indictment in an eventual proceeding. The request has been preceded by an act of removal of the archived judicial position from the main proceeding. On January 24, 2012 the Judge for Preliminary Hearings decided to archive the above mentioned positions. As a result of a further dismissal of judicial position from the main proceeding, the Public Prosecutor of Milan notified to nine employees and former employees of Eni (in particular belonging to the Gas & Power Division) the conclusion of the investigation related to the crime under the provisions of Article 40 (violations pertaining to recognition and payment of the excise on mineral oils) of Legislative Decree No. 504 of October 26, 1995. The deed also disputed certain violations pertaining to subtraction of taxable amounts and missed payments of excise taxes on natural gas amounting to (cid:1)0.47 billion and (cid:1)1.3 billion, respectively. The Duty Authority of Milan, responsible for the collection of dodged taxes, considering the documentation filed by Eni, reduced the amount initially claimed by the Public Prosecutor to (cid:1)114 million of dodged taxes. The Duty Authority also stated that it would reassess that amount considering further evidence arising from the criminal proceeding. The Company was not notified the decision because the Judicial Authority has cleared the possibility that the Company may be liable in accordance with Legislative Decree 231 of 2001. In the subsequent hearing of October 28, the defendants, in order to analyze fully the various aspect of the criminal proceeding, asked a consistent postponement of the Preliminary Hearing, in order to evaluate the conclusion of the round table between the Duty Agency, AEEG and ANIGAS which have been assessing the technical aspects of the matter. After the review of the positions of the Public Prosecutor and the defendants, the Judge for the Preliminary Hearings postponed the hearing to May 7, 2012 and decided as probative integration to F-91 hear the Director of the Procedure and Control Excise Sector of the Regional Duty Direction of the Lombardia Region. (v) Agip KCO NV. In November 2007, the Public Prosecutor of Kazakhstan informed Agip KCO of the start of an inquiry for an alleged fraud in the award of a contract to the Overseas International Constructors GmbH in 2005. On April 2010, the above mentioned body has proposed an agreement on the matter. On March 4, 2011, the Finance Police of Kazakhstan communicated to Agip KCO the decision to dismiss the matter. (vi) Kazakhstan. On October 1, 2009, the Public Prosecutor of Milan requested a number of documents pursuant to Article 248 of the Italian Penal Code. Through this decision, part of a criminal proceeding against unknown parties, Eni SpA was requested to transmit – in relation to the alleged international corruption, embezzling pillage, and other crimes – audit reports and other documentation related to anomalies and critical issues on the management of the Karachaganak plant and the Kashagan project. The crime of “international corruption” mentioned in the said request of transmission of documents is sanctioned, in addition to the Italian criminal code, by Legislative Decree June 8, 2001, No. 231, which establishes the administrative responsibility of companies for crimes committed by their employees on their behalf. Eni commenced the collection of the documentation in order to rapidly fulfill the requests of the Public Prosecutor. The Company has deposited in different phases the documents collected. The Company continues to fully collaborate with the Public Prosecutor providing also further documentation when available. On November 29, 2010, the Tributary Police of Milan requested to interview certain Eni managers in the field of the evolution on the management of contract assigned to Agip KCO to NCC and OIC consortia. Subsequently the Tributary Police convened two managers in order to interview them about the investigation commenced by the Public Prosecutor of Milan. (vii) Algeria. On February 4, 2011, Eni received by the Public Prosecutor of Milan a notification requesting the collection of documents pursuant to Article 248 of the Italian Penal Code. Through this decision, in relation to the crime of alleged international corruption, Eni SpA was requested to transmit: (i) the Saipem/Sonatrach contract signed on June 2009 related to the realization of the GK3 gas pipeline; (ii) the GALSI/Saipem/Technip contract signed in July 2009 related to the engineering of the ground section of the gas pipeline. The notification has been forwarded to Saipem SpA since this matter is in its area of responsibility. The crime of international corruption regards, interalia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231. Eni commenced the collection of the documentation in order to rapidly fulfill the requests of the Public Prosecutor, and on February 16, 2011 the Company has deposited the documents collected. In addition, even if there was not a formal request of the Public Prosecutor the Company has filed the documentation related to the MLE project (participated by the Company’s E&P division), for which investigations in Algeria are ongoing. Eni and Saipem continue to fully collaborate with the Public Prosecutor. Saipem has not received any further request on the case. (viii) Libya. On June 10, 2011 Eni received by the U.S. SEC a formal judicial request of collection and presentation of documents (subpoena) related to Eni’ s activity in Libya from 2008 to 2011. The subpoena is related to an ongoing investigation without further clarifications nor specific alleged violations in connection to “certain illicit payments to Libyan officials” possibly violating the U.S. Foreign Corruption Practice Act. At the end of December 2011, Eni received a request for the collection of further documentation aiming at integrating the subpoena previously received. Eni is fully collaborating with the U.S. SEC. (ix) Iraq. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were notified that a search warrant had been issued to search the offices and homes of certain employees of the Group and of certain third parties as a result of alleged illicit behavior in respect of awarding contracts in Iraq, where Eni group companies are involved as commissioning bodies. In particular the homes and offices of an employee of Eni Zubair and a manager of Saipem were searched by the authorities. The accusation is of criminal conspiracy and corruption in relation with the activity of Eni Zubair in Iraq and of Saipem in the “Jurassic” project in Kuwait. The Public Prosecutor of Milan has associated Eni Zubair, Eni and Saipem with the accusations as a result of the alleged illicit actions of their employees, who have also been described as non-loyal employees of Eni Group. The Eni Zubair employee resigned and the Company, accepting the resignation, reserved the right to take action against the individual to defend its interests and subsequently commenced a legal action against the other persons mentioned in the seizure act. Notwithstanding that the Eni Group companies are associated with these accusations, Eni SpA and Saipem SpA also received, at the same time the search warrant was issued, a notification pursuant to the Legislative Decree No. 231/2001. While the minuting of the seizure, Eni SpA asserted the Company had no involvement as all activities in Iraq are carried out by its subsidiary Eni Zubair. The Company also asserted that Eni Zubair and Eni SpA had no involvement with the alleged illicit activities subject to the prosecutor’s accusations. Eni SpA was notified by the Public Prosecutor a request of extension of the preliminary investigations that has led up to the involvement of another employee as well as other suppliers in the proceeding. Eni commissioned an external consulting firm to perform an audit that will be integrated by further evidence that is in the process of being acquired. According to the opinion of its legal team, the Company’s watch structure and Internal control committee, Saipem too commenced through its Internal Audit department an internal review about the project with the support F-92 of an external consultant. The internal review did not find any evidence of problematic elements, nor aspects which might be of any importance form a criminal standpoint in connection with the interested Saipem employee, nor irregularities of any kind; thus Saipem employee involved in the proceeding, that was prudently suspended by his function in the meanwhile, was readmitted in the company albeit in a different function. The Public Prosecutor disposed the release of seizure of the documentation owned by the employee in relation to this proceeding. On March 2, 2012, Saipem SpA was notified by the Public Prosecutor a request of extension of the preliminary investigation. 5. Tax Proceedings ITALY (i) Eni SpA. Dispute for the omitted payment of a municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented in December 1999, the Municipality of Pineto (Teramo) claimed Eni SpA to have omitted payment of a municipal tax on real estate for the period from 1993 to 1998 on four oil platforms located in the Adriatic Sea which constitute municipal waters. Eni was requested to pay a total of approximately (cid:1)17 million including interest and a fine. Eni filed a counterclaim stating that the sea where the platforms are located is not part of the municipal territory and the tax application as requested by the Municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the supreme degree Court overturned both judgments, declaring that a Municipality can consider requesting a tax on real estate in the sea facing its territory and with the decision of February 2005 sent the proceeding to another section of the Regional Tax Commission in order to judge on the matters of the proceeding. This commission requested an independent consultant to assessing the tax and technical aspects of the matter. The independent consultant confirmed that Eni’s offshore installations lack any ground to be subject to the municipal tax that was claimed by the local Municipality. Those findings were accepted by the Regional Tax Commission with a ruling made on January 19, 2009. On January 25, 2011, the Municipality notified to Eni an appeal to the Supreme Degree Court for the cancellation of the above mentioned sentence. Also on December 28, 2005, the Municipality of Pineto presented similar claims relating to the same Eni platforms for the years 1999 to 2004. The total amount requested was (cid:1)24 million including interest and penalties. Eni filed a claim against this claim which was accepted by the First Degree Judge with a decision of December 4, 2007. Similar formal assessments related to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima, Tortoreto, Pedaso, and also from 2009 the Gela Municipality. The total amounts of those claims were approximately (cid:1)7.5 million. The Company filed appeal against all those claims. OUTSIDE ITALY (i) Karachaganak. On December 14, 2011, the International companies operating the Karachaganak field (Eni co-operator, 32.5%) and the Republic of Kazakhstan signed a binding agreement for the settlement of a contractual claim as well as a certain tax disputes. The transaction is expected to be completed by June 2012 on satisfaction of conditions precedent. In particular, the Kazakh Tax Authorities claimed that Agip Karachaganak BV and Karachaganak Petroleum Operating BV, shareholder and operator of the Karachaganak contract, respectively, omitted payment of income taxes and other tax items for the period 2000-2009. Then, Kazakh authorities notified a claim on the recovery of expenditures incurred by the operating company in the period 2003-2009. In consideration of the above mentioned tax claims and of the terms of the agreement Eni incurred certain charges and accrued a risk provision for overall amount of $32 million. For further information about the agreement see section Operating review – Exploration & Production – Country updates, in the Operating and Financial Review. (ii) Eni Angola Production BV. In 2009 the Ministry of the Finance of Angola, following a fiscal audit, filed a notice of tax assessment for fiscal years 2002 to 2007 in which it claimed the improper deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as co-operator of the Cabinda concession. The Company filed an appeal against this decision. The judgment is still pending before the Supreme Court. Eni accrued a provision with respect to this proceeding. F-93 6. Settled proceedings The proceedings settled in 2011, mentioned in the Annual Report 2010 (Note 34), are the following: 1. Environment (i) Subsidence; (ii) Alleged damage – Prosecuting body: Public Prosecutor of Gela; (iii) Alleged negligent fire in the refinery of Gela. These proceedings were settled without consequences for Eni. 2. Other judicial or arbitration proceedings Syndial SpA (former EniChem SpA) (i) Serfactoring: disposal of receivables. On July 29, 2011, Eni’s subsidiaries and the plaintiff Agrifactoring agreed upon a global transaction to settle all outstanding matters and claims whereby Eni’s subsidiaries paid to Agrifactoring a cash compensation amounting to (cid:1)65 million. This sum has been already accrued in Eni’s consolidated financial statements to the risk provision. 5. Tax Proceedings Italy Eni SpA and Eni Adfin SpA (ii) Assessments for Padana Assicurazioni tax returns. In 2011 the Company defined all pending claims with the Italian Tax Authorities regarding the tax returns for years 2005, 2006 and 2007 filed by Padana Assicurazioni SpA, a Group subsidiary that was subsequently divested. The Tax Authorities have denied certain cost deductions and assessed a greater value for a business combination involving the Group subsidiary Eni Insurance Ltd in 2007. All claims have been settled by paying the global amount of (cid:1)46.7 million utilizing a risk provision accrued in 2010. Assets under concession arrangements Eni operates under concession arrangements mainly in the Exploration & Production segment and in some activities of the Gas & Power segment and the Refining & Marketing segment. In the Exploration & Production segment contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each Country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. Eni sustains all the operation risks and costs related to the exploration and development activities and it is entitled to the productions realized. In Production Sharing Agreement and in buy-back contracts, realized productions are defined on the basis of contractual agreements drawn up with State oil companies which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). With reference to natural gas storage in Italy, the activity is conducted on the basis of concessions with an original duration that does not exceed twenty years and it is granted by the Ministry of Productive Activities to persons that are consistent with legislation requirements and that can demonstrate to be able to conduct a storage program that meets the public interest in accordance with the Law. The operator is entitled to a maximum of two extensions of ten year each, if the storage programs are executed and all the obligations are fulfilled. In the Gas & Power segment the gas distribution activity is conducted on the basis of concessions granted by local public entities. In 2011, a specific Decree issued by the Italian Government established 177 territorial basins representing the lowest levels of aggregation of municipalities. The new concessions will be granted based on these new territorial basins. When an existing concession expires, the new operator who takes over the concession will award the previous operator a compensation for the distribution network based on an industrial assessment of the asset value. Tariffs for the distribution service are defined by the Italian Authority for Electricity and Gas. The Law provides the grant of distribution service exclusively by tender, with a maximum length of 12 years. In the Refining & Marketing segment several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. Such assets are amortized over the length of the concession (generally, 5 years for Italy). In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties on the basis of quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession. F-94 Environmental regulations Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in “Financial Review”, paragraph “Risk factors and uncertainties”. In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s consolidated financial statements, taking account of ongoing remedial actions, existing insurance policies and the environmental risk provision accrued in the consolidated financial statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys and the other possible effects of statements required by Legislative Decree No. 152/2006; (iii) new developments in environmental regulation; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries. Emission trading Legislative Decree No. 216 of April 4, 2006 implemented the Emission Trading Directive 2003/87/EC concerning greenhouse gas emissions and Directive 2004/101/EC concerning the use of carbon credits deriving from projects for the reduction of emissions based on the flexible mechanisms devised by the Kyoto Protocol. This European emission trading scheme has been in force since January 1, 2005, and on this matter, on November 27, 2008, the National Committee for Emissions Trading Scheme (Ministry for the Environment-Mse) published the Resolution 20/2008 defining emission permits for the 2008-2012 period. Eni was assigned permits corresponding to 127.3 million tonnes of carbon dioxide (of which, 25.8 in 2008, 25.8 in 2009, 25.5 in 2010, 25.3 in 2011, 24.9 in 2012) and in addition to approximately 3.8 million of permits expected to be assigned with respect to new plants in the five-year period 2008-2012. Emission quotas of new plants include only those physically assigned and recorded in the emissions registry. Emissions of carbon dioxide from Eni’s plants were lower than permits assigned in 2011. Against emissions of carbon dioxide amounted to approximately 24.2 millions tonnes, emission permits amounting to 26.4 million tonnes were assigned, determining a 2.2 million tonnes surplus. In addition to such surplus, a 0.16 million tonnes of permits (as increase in the availability of Eni) are to be included following the contract of Virtual Power Plan GDF Suez Energia Italia, primarily assigned to cover the emissions of the EniPower plants. For this reason, the total surplus amounted to about 2.3 million tonnes. 35 Revenues Net sales from operations ((cid:1) million) Net sales from operations ................................................................... Change in contract work in progress ................................................. 2009 2010 2011 83,519 (292) 83,227 98,864 (341) 98,523 109,147 442 109,589 Net sales from operations were stated net of the following items: ((cid:1) million) 2009 2010 2011 Excise taxes ......................................................................................... Exchanges of oil sales (excluding excise taxes) ............................... Services billed to joint venture partners ............................................ Sales to service station managers for sales billed to holders of credit cards ...................................................................................... Exchanges of other products .............................................................. 12,122 1,680 2,435 1,531 55 17,823 11,785 1,868 2,996 2,150 79 18,878 11,863 2,470 3,375 1,810 9 19,527 F-95 Net sales from operations of (cid:1)109,147 million included revenues recognized in connection with contract works in the Engineering & Construction segment for (cid:1)10,510 million ((cid:1)8,349 million and (cid:1)8,779 million in 2009 and 2010, respectively) and construction and development of the distribution network related to assets under concession agreements for (cid:1)364 million ((cid:1)357 million in 2010). Net sales from operations by business segment and geographic area of destination are disclosed under Note 41 – Information by industry segment and geographic financial information. Other income and revenues ((cid:1) million) 2009 2010 2011 Gains from sale of assets .................................................................... Gains on price adjustments under overlifting/underlifting transactions ................................................... Lease and rental income ..................................................................... Compensation for damages ................................................................ Contract penalties and other trade revenues ...................................... Other proceeds (*) ................................................................................ ________ (*) Each individual amount included herein does not exceed (cid:1)50 million. 306 148 100 54 31 479 1,118 266 50 84 47 52 457 956 114 99 97 67 28 528 933 Gains from the sale of assets of (cid:1)114 million included (cid:1)74 million to the Exploration & Production segment. 36 Operating expenses Purchase, services and other ((cid:1) million) 2009 2010 2011 Production costs - raw, ancillary and consumable materials and goods ............................................................................................. Production costs - services ................................................................. Operating leases and other .................................................................. Net provisions for contingencies ........................................................ Other expenses .................................................................................... less: - capitalized direct costs associated with self-constructed assets - tangible assets ...................................................................... - capitalized direct costs associated with self-constructed assets - intangible assets ................................................................... 40,311 13,520 2,567 1,055 1,527 58,980 48,261 15,400 3,066 1,407 1,309 69,443 60,724 14,034 3,113 551 1,214 79,636 (576) (243) (375) (53) 58,351 (65) 69,135 (70) 79,191 Services included brokerage fees related to the Engineering & Construction segment for (cid:1)12 million ((cid:1)79 million and (cid:1)26 million in 2009 and 2010, respectively). Costs incurred in connection with research and development activity recognized in profit and loss amounted to (cid:1)191 million ((cid:1)207 million and (cid:1)221 million in 2009 and 2010, respectively) as they did not meet the requirements to be recognized as long-lived assets. F-96 The item “Operating leases and other” included operating leases for (cid:1)1,305 million ((cid:1)1,220 million and (cid:1)1,400 million in 2009 and 2010, respectively) and royalties on the extraction of hydrocarbons for (cid:1)1,295 million ((cid:1)641 million and (cid:1)1,214 million in 2009 and 2010, respectively). Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below: ((cid:1) million) To be paid within 1 year ...................................................................... Between 2 and 5 years ......................................................................... Beyond 5 years ..................................................................................... 2009 2010 2011 886 2,335 1,034 4,255 1,023 2,278 752 4,053 839 1,385 255 2,479 Operating leases primarily regarded drilling rigs, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which may limit the ability of Eni to pay dividends, use assets or take on new borrowings. The decrease in the expected future minimum lease payments amounting to (cid:1)1,574 million related to the exclusion from the scope of consolidation of Eni Gas Transport International SA and Eni Gas Transport Deutschland SpA ((cid:1)1,086 million) which were divested. New or increased risk provisions net of reversal of unused provisions amounting to (cid:1)551 million ((cid:1)1,055 million and (cid:1)1,407 million in 2009 and 2010, respectively) mainly related to expected environmental liabilities amounting to (cid:1)184 million (net provisions of (cid:1)258 million and (cid:1)1,352 million in 2009 and 2010, respectively) and expected losses on contract penalties and litigations of (cid:1)160 million (net provisions of (cid:1)333 million in 2009 and net reversals of (cid:1)185 million in 2010). More information is provided under Note 27 – Provisions for contingencies. Payroll and related costs ((cid:1) million) 2009 2010 2011 Wages and salaries .............................................................................. Social security contributions .............................................................. Cost related to employee benefit plans .............................................. Other costs ........................................................................................... less: - capitalized direct costs associated with self-constructed assets - tangible assets ...................................................................... - capitalized direct costs associated with self-constructed assets - intangible assets ................................................................... 3,330 706 137 342 4,515 3,565 714 164 600 5,043 3,704 760 158 360 4,982 (280) (209) (185) (54) 4,181 (49) 4,785 (48) 4,749 Other costs of (cid:1)360 million ((cid:1)342 million and (cid:1)600 million in 2009 and 2010, respectively) comprised costs for defined contribution plans of (cid:1)113 million ((cid:1)122 million and (cid:1)104 million in 2009 and 2010, respectively) and provisions for redundancy incentives of (cid:1)209 million ((cid:1)134 million and (cid:1)423 million in 2009 and 2010, respectively). Cost related to employee benefit plans are described in Note 28 – Provisions for employee benefits. F-97 Average number of employees The Group average number and break-down of employees by category is reported below: (number) Senior managers ................................................................................... Junior managers.................................................................................... Employees ............................................................................................ Workers................................................................................................. 2009 2010 2011 1,653 13,255 37,207 26,533 78,648 1,569 13,122 37,589 26,550 78,830 1,580 13,324 38,590 25,819 79,313 The average number of employees was calculated as average between the number of employees at the beginning and end of the period. The average number of senior managers included managers employed and operating in foreign subsidiaries, whose responsibility and position are comparable to those of a senior manager. Stock-based compensation Stock option In 2009 Eni terminated any stock-based incentive schemes. Information provided below is about the residual activity of past stock incentive schemes. At December 31, 2011, 11,873,205 options were outstanding for the purchase of 11,873,205 Eni ordinary shares (nominal value (cid:1)1 each). The break-down of outstanding options was the following: Stock option plan 2004 ................................................................................................... Stock option plan 2005 ................................................................................................... Stock option plan 2006 ................................................................................................... Stock option plan 2007 ................................................................................................... Stock option plan 2008 ................................................................................................... Weighted- average strike price of rights outstanding as of Dec. 31, 2011 ((cid:1)) 16.576 22.514 23.121 27.451 22.540 Rights outstanding as of Dec. 31, 2011 (number) 628,100 3,281,500 2,201,950 1,876,980 3,884,675 11,873,205 At December 31, 2011, the residual lives of the schemes were 7 months for the 2004 plan, 1 year and 7 months for the 2005 plan, 7 months for the 2006 plan, 1 year and 7 months for the 2007 plan and 2 years and 7 months for the 2008 plan. The 2006-2008 stock option schemes provided that options can be exercised after three years from grant (vesting period). The strike price was calculated as the arithmetic average of official prices recorded on the Italian exchange in the month prior to grant. F-98 The scheme evolution is provided below: 2009 Average strike price ((cid:1)) Number of shares Market price (a) ((cid:1)) Number of shares 2010 Average strike price ((cid:1)) Market price (a) ((cid:1)) Number of shares 2011 Average strike price ((cid:1)) Market price (a) ((cid:1)) 23,557,425 23.540 16.556 19,482,330 23.576 17.811 15,737,120 23.005 16.398 (2,000) 13.743 16.207 (88,500) 14.941 16.048 (208,900) 14.333 16.623 (4,073,095) 13.374 14.866 (3,656,710) 26.242 16.918 (3,655,015) 23.187 17.474 19,482,330 23.576 17.811 15,737,120 23.005 16.398 11,873,205 23.101 15.941 7,298,155 21.843 17.811 8,896,125 23.362 16.398 11,863,335 23.101 15.941 Rights outstanding as of January 1 ........... Rights exercised in the period ................. Rights cancelled in the period ................. Rights outstanding as of December 31 ...... of which exercisable as of December 31 ...... _______ (a) Market price relating to new rights granted, rights exercised in the period and rights cancelled in the period corresponds to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of the Board of Directors resolution regarding the stock option assignment; (ii) the date on which the emission/transfer of the shares granted were recorded in the grantee’s securities account; and (iii) the date of the unilateral termination of employment for rights cancelled), weighted with the number of shares. Market price of stock at the beginning and end of the year is the price recorded at December 31. The fair value of stock options granted during the years 2004 and 2005 was (cid:1)2.01 and (cid:1)3.33 per share, respectively. For 2006, 2007 and 2008 the average fair value weighted with the number of options granted was (cid:1)2.89, (cid:1)2.98 and (cid:1)2.60 per share, respectively. The fair value was determined by applying the following assumptions: Risk-free interest rate ............................................................ (%) Expected life .......................................................................... (years) Expected volatility ................................................................. (%) Expected dividends ................................................................ (%) 3.2 8 19.0 4.5 2.5 8 21.0 4.0 4.0 6 16.8 5.3 4.7 6 16.3 4.9 4.9 6 19.2 6.1 2004 2005 2006 2007 2008 Costs of the year related to stock option plans amounted to (cid:1)3 million ((cid:1)12 million in 2009 and 2010). Compensation of key management personnel Compensation of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office at end of each year amounted (including contributions and ancillary costs) to (cid:1)35 million, (cid:1)33 million and (cid:1)34 million for 2009, 2010 and 2011, respectively, and consisted of the following: ((cid:1) million) 2009 2010 2011 Wages and salaries .............................................................................. Post-employment benefits .................................................................. Other long-term benefits ..................................................................... Indemnities upon termination of employment .................................. Stock option ......................................................................................... 20 1 10 4 35 20 1 10 2 33 21 1 10 2 34 Compensation of Directors and Statutory Auditors Compensation of Directors amounted to (cid:1)9.9 million, (cid:1)9.7 million and (cid:1)8.4 million for 2009, 2010 and 2011, respectively. Compensation of Statutory Auditors amounted to (cid:1)0.475 million, (cid:1)0.511 million and (cid:1)0.513 million in 2009, 2010 and 2011, respectively. F-99 Compensation included emoluments and other similar payments and social security compensations due for the positions as director or statutory auditor held at the Parent Company Eni SpA or other Group subsidiaries, which was recognized as cost to the Group, even if not subjected to personal income tax. Other operating (expense) income ((cid:1) million) 2009 2010 2011 Net gains (losses) on non-hedging derivatives .................................. Net gains (losses) on trading derivatives ........................................... Net gains (losses) on cash flow hedging derivatives ........................ 66 (11) 55 111 7 13 131 135 53 (17) 171 Gains (losses) on non-hedging derivatives related to the recognition through profit of fair value valuation as well as settlement of those derivatives on commodities which were not designated as hedges under IFRS. Also included in the item were fair value gains or losses on certain derivatives embedded in the pricing formulas of long- term gas supply contracts in the Exploration & Production segment ((cid:1)4 million). Gains or losses on fair value valuation or settlement related to certain trading derivatives entered into by the Gas & Power segment following the new risk management strategy designed to optimize margins. Gains or losses on cash flow hedging derivatives related to the ineffective portion of the hedging relationship which was recognized through profit and loss in the Gas & Power segment. Depreciation, depletion, amortization and impairments ((cid:1) million) 2009 2010 2011 Depreciation, depletion and amortization: - tangible assets .................................................................................... - intangible assets ................................................................................. Impairments: - tangible assets .................................................................................... - intangible assets ................................................................................. less: - reversal of impairments - tangible assets ....................................... - reversal of impairments - intangible assets.................................... - capitalized direct costs associated with self-constructed assets - tangible assets ....................................................................... - capitalized direct costs associated with self-constructed assets - intangible assets .................................................................... 6,658 2,110 8,768 990 62 1,052 (1) (4) (2) 9,813 7,141 1,744 8,885 257 441 698 (2) (2) 9,579 6,544 1,758 8,302 891 154 1,045 (15) (9) (3) (2) 9,318 F-100 37 Finance income (expense) ((cid:1) million) 2009 2010 2011 Finance income (expense) Finance income ................................................................................... Finance expense .................................................................................. Derivative financial instruments ......................................................... 5,950 (6,497) (547) (4) (551) 6,117 (6,713) (596) (131) (727) 6,379 (7,396) (1,017) (112) (1,129) The break-down by lenders or type of net finance gains or losses is provided below: ((cid:1) million) 2009 2010 2011 Finance income (expense) related to net borrowings Interest and other finance expense on ordinary bonds ...................... Interest due to banks and other financial institutions ....................... Interest from banks .............................................................................. Interest and other income on financing receivables and securities held for non-operating purposes ................................. Exchange differences Positive exchange differences ............................................................ Negative exchange differences ........................................................... Other finance income (expense) Capitalized finance expense ............................................................... Income from equity instruments ........................................................ Interest and other income on financing receivables and securities held for operating purposes ........................................ Interest on tax credits .......................................................................... Finance expense due to passage of time (accretion discount) (a)....... Other finance income .......................................................................... (423) (330) 33 47 (673) 5,572 (5,678) (106) 223 163 39 4 (218) 21 232 (547) (551) (215) 18 21 (727) 5,897 (5,805) 92 (610) (312) 22 19 (881) 6,191 (6,302) (111) 187 149 73 2 (251) 28 39 (596) 75 2 (247) (4) (25) (1,017) _______ (a) The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities. Derivative financial instruments consisted of the following: ((cid:1) million) 2009 2010 2011 Derivatives on exchange rate ............................................................. Derivatives on interest rate ................................................................. Derivatives on commodities ............................................................... 40 (52) 8 (4) (111) (39) 19 (131) 29 (141) (112) Net losses from derivatives of (cid:1)112 million (a net loss of (cid:1)4 million and (cid:1)131 million in 2009 and 2010, respectively) were recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. The lack of these formal requirements to qualify these derivatives as hedging instruments under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments. F-101 38 Income (expense) from investments Share of profit (loss) of equity-accounted investments ((cid:1) million) 2009 2010 2011 Share of profit of equity-accounted investments .............................. Share of loss of equity-accounted investments ................................. Decreases (increases) in the provision for losses on equity-accounted investments ....................................................... 693 (241) (59) 393 717 (149) (31) 537 678 (106) (28) 544 More information is provided in Note 17 – Equity-accounted investments. Other gain (loss) from investments ((cid:1) million) 2009 2010 2011 Dividends ............................................................................................. Gains on disposals, net ....................................................................... Other income (expense), net ............................................................... 164 16 (4) 176 264 332 23 619 659 1,125 (157) 1,627 Dividend income for (cid:1)659 million related to the Nigeria LNG Ltd ((cid:1)483 million), Trans Austria Gasleitung GmbH ((cid:1)82 million) and Saudi European Petrochemical Co “IBN ZAHR” ((cid:1)67 million) investees. In 2011 net gains on disposals amounted to (cid:1)1,125 million and pertained to the divestment of the 100% interest in Eni Gas Transport International SA ((cid:1)647 million), the 89% interest (entire stake own) in Trans Austria Gasleitung GmbH ((cid:1)338 million), the 100% interest in Gas Brasiliano Distribuidora SA ((cid:1)50 million) and the 46% interest (entire stake own) in Transitgas AG ((cid:1)34 million). Gains on disposals for 2010 of (cid:1)332 million essentially referred to the divestment of the 100% interest in Società Padana Energia SpA ((cid:1)169 million), the 25% stake in GreenStream BV ((cid:1)93 million) and the 100% interest in Distri RE SA ((cid:1)47 million). Gains on disposals for 2009 of (cid:1)16 million primarily referred to a price revision related to the sale done in 2008 of Gaztransport et Technigaz SAS ((cid:1)10 million). In 2011, other net income (expense) of (cid:1)157 million included the full write-down of the book value of the Ceska Rafinerska AS due to management’s expectations of incurring future losses driven by a negative outlook in the refining segment ((cid:1)157 million). F-102 39 Income taxes ((cid:1) million) 2009 2010 2011 Current taxes: - Italian subsidiaries ............................................................................ - foreign subsidiaries of the Exploration & Production segment ..... - foreign subsidiaries ........................................................................... Net deferred taxes: - Italian subsidiaries ............................................................................ - foreign subsidiaries of the Exploration & Production segment ..... - foreign subsidiaries ........................................................................... 1,724 5,989 483 8,196 (534) (733) (173) (1,440) 6,756 1,315 7,893 521 9,729 (474) (97) (1) (572) 9,157 1,408 8,286 635 10,329 (435) 936 (156) 345 10,674 Income taxes currently payable amounted to (cid:1)1,408 million and were in respect of the Italian corporate taxation (Ires for (cid:1)1,039 million and Irap for (cid:1)249 million) and corporate foreign taxes for (cid:1)120 million incurred by Italian subsidiaries. Deferred taxes recognized by foreign subsidiaries in the Exploration & Production segment comprised an adjustment to deferred taxation for (cid:1)573 million due to a changed tax rate applicable to a production sharing agreement, including an adjustment to deferred taxation which was recognized upon allocation of the purchase price as part of a business combination when the mineral interest was acquired by Eni. The effective tax rate was 57.8% (56.0% and 55.4% in 2009 and 2010, respectively) compared with a statutory tax rate of 43.1% (40.1% and 39.6% in 2009 and 2010, respectively). This was calculated by applying the Italian statutory tax rate on corporate profit of 38.0%17 (Ires) and a 3.9% corporate tax rate applicable to the net value of production (Irap) as provided for by Italian laws. The difference between the statutory and effective tax rate was due to the following factors: (%) 2009 2010 2011 Statutory tax rate ............................................................................... Items increasing (decreasing) statutory tax rate: - higher foreign subsidiaries tax rate .................................................. - impact of the supplemental Ires pursuant to the Law No. 7 of February 6, 2009 .............................. - impact pursuant to Law Decree No. 112/2008, Budget Law 2008 and enactment of a renewed tax framework in Libya..................... - permanent differences and other adjustments ................................. 40.1 13.3 2.4 0.2 15.9 56.0 39.6 15.0 1.5 (0.7) 15.8 55.4 43.1 12.2 0.9 1.6 14.7 57.8 The increase in the tax rate of foreign subsidiaries primarily related to a 16.5% increase in the Exploration & Production segment (16.1% in 2009 and 2010, respectively). In 2011, the increase for permanent differences and other adjustments of 1.6 percentage points were due to a non-deductible provision accrued to reflect the expected loss deriving from an antitrust proceeding in the European sector of rubbers (0.2 percentage points). In 2010, the decrease for permanent differences and other adjustments of 0.7 percentage points was due to a gain which was excluded from taxable profit relating a favorable outcome of an antitrust proceeding (0.6 percentage points). In 2009, the increase for permanent differences and other adjustments of 0.2 percentage points included the effect of a charge amounting to (cid:1)250 million related to the estimation of a fine for the TSKJ matter to the U.S. Authorities which was a non-deductible item, partially offset by deferred tax (17) Includes a 5.5% supplemental tax rate on taxable profit of energy companies in Italy (whose primary activity is the production and marketing of hydrocarbons and electricity and with annual revenues in excess of (cid:1)25 million) effective from January 1, 2008 and further increases of 1% effective from January 1, 2009, pursuant to the Law Decree No. 112/2008 (converted into Law No. 133/2008) and 4% effective from January 1, 2011, pursuant the Law Decree No. 138/2011 (converted into Law No. 148/2011) which enlarged the scope of application to include renewable energy companies and gas transport and distribution companies. F-103 assets which were recognized following the alignment of the tax base of certain oil&gas properties to their higher carrying amounts by paying a special tax and the partial deductibility of Irap from income taxes also applicable to previous reporting periods ((cid:1)222 million). In 2009, the impact pursuant to Law Decree No. 112/2008, the Budget Law 2008 and enactment of a renewed tax framework in Libya consisted of the following: (i) an adjustment amounting to (cid:1)230 million pertaining to income taxes due on the profit earned in Libya the previous year following the enactment of new criteria for revenues recognition for tax purposes; and (ii) a reduced deductibility in Italy of the cost of goods sold following the reduction in the gas volumes of inventories for (cid:1)64 million. 40 Earnings per share Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average of ordinary shares issued and outstanding during the period, excluding treasury shares. The average number of ordinary shares used for the calculation of the basic earnings per share outstanding at December 31, 2009, 2010 and 2011, was 3,622,405,852, 3,622,454,738 and 3,622,616,182, respectively. Diluted earnings per share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average of shares fully-diluted including shares outstanding in the year, with the exception of treasury shares and including the number of potential shares outstanding in connection with stock-based compensation plans. At December 31, 2009, 2010 and 2011 the number of potential shares outstanding were related to stock options plans. The average number of fully-diluted shares used in the calculation of diluted earnings was 3,622,438,937, 3,622,469,713 and 3,622,616,182 for the years ending December 31, 2009, 2010 and 2011, respectively. Reconciliation of the average number of shares used for the calculation for both basic and diluted earning per share was as follows: 2009 2010 2011 3,622,405,852 3,622,454,738 3,622,616,182 33,085 14,975 3,622,438,937 3,622,469,713 3,622,616,182 6,860 1.89 1.89 6,318 1.74 1.74 4,367 1.21 1.21 Average number of shares used for the calculation of the basic earnings per share ........................................................ Number of potential shares following stock options plans .............. Average number of shares used for the calculation of the diluted earnings per share .................................................... Eni’s net profit ............................................................ ((cid:1) million) ((cid:1) per share) Basic earning per share ............................................. ((cid:1) per share) Diluted earning per share ......................................... F-104 41 Information by industry segment and geographic financial information Information by industry segment Exploration & Production Gas & Power Refining & Marketing Petrochemicals Engineering & Construction Other activities Corporate and financial companies Intra-group profits Total 23,801 (13,630) 10,171 9,120 30,447 (635) 29,812 3,687 31,769 (965) 30,804 (102) 4,203 (238) 3,965 (675) 9,664 (1,315) 8,349 881 88 (24) 64 (436) 1,280 (1,152) 128 (420) (66) (66) (2) 277 154 1 311 172 142 83,227 12,055 1,055 7,365 981 754 204 435 8 83 (17) 9,813 142 42,729 310 32,135 (70) 12,244 2,583 50 11,611 (39) 355 1,031 (553) 1,989 10,918 2,044 9,161 1,494 4,684 9,486 1,686 635 37 742 145 213 5,967 1,630 51 1,868 1,461 44 57 29,497 (16,550) 12,947 13,866 29,576 (833) 28,743 2,896 43,190 (1,345) 41,845 149 6,141 (243) 5,898 (86) 10,581 (1,802) 8,779 1,302 105 (25) 80 (1,384) 1,386 (1,255) 131 (361) 33 (58) 199 2 35 1,146 7,051 1,399 409 135 516 10 50 79 92 49,573 388 34,943 68 14,356 1 3,076 12,715 (2) 362 (10) 754 1,974 12,330 2,370 10,048 1,058 6,197 9,690 1,685 711 30 874 251 174 5,760 1,552 54 2,898 8 1,307 22 109 29,121 (18,444) 10,677 15,887 34,731 (1,083) 33,648 1,758 51,219 (2,791) 48,428 (273) 6,491 (289) 6,202 (424) 11,834 (1,324) 10,510 1,422 85 (23) 62 (427) 1,365 (1,249) 116 (319) 53 137 57 11 79 201 6,440 1,100 839 250 631 6 13 75 393 102,135 15,394 5,828 34,793 32,685 13,695 98,523 16,111 1,407 (8) 12 100 100 (271) (20) 9,579 537 114,862 16,998 5,668 39,313 36,819 13,870 (917) (101) (150) (54) (54) (189) 109,589 17,435 551 (23) 9,318 119 56,139 276 36,357 100 15,031 3,066 95 13,521 (45) 378 (1) 810 (1,060) 2,317 13,844 2,375 10,893 890 5,972 9,435 1,721 866 38 761 216 179 5,437 1,090 37 3,020 7 1,095 10 128 (54) (28) 544 124,242 18,703 5,843 40,968 41,584 13,438 ((cid:1) million) 2009 Net sales from operations (a)........... Less: intersegment sales. Net sales to customers.... Operating profit .............. Net provisions for contingencies............. Depreciation, depletion, amortization and impairments ............. Share of profit (loss) of equity-accounted investments ..................... Identifiable assets (b) ....... Unallocated assets .......... Equity-accounted investments ..................... Identifiable liabilities (c).. Unallocated liabilities..... Capital expenditures....... 2010 Net sales from operations (a)........... Less: intersegment sales. Net sales to customers.... Operating profit .............. Net provisions for contingencies............. Depreciation, depletion, amortization and impairments ............. Share of profit (loss) of equity-accounted investments ..................... Identifiable assets (b)........ Unallocated assets .......... Equity-accounted investments ..................... Identifiable liabilities (c) .. Unallocated liabilities..... Capital expenditures....... 2011 Net sales from operations (a) ........... Less: intersegment sales. Net sales to customers.... Operating profit .............. Net provisions for contingencies............. Depreciation, depletion, amortization and impairments ............. Share of profit (loss) of equity-accounted investments ..................... Identifiable assets (b) ....... Unallocated assets .......... Equity-accounted investments ..................... Identifiable liabilities (c) .. Unallocated liabilities..... Capital expenditures....... _______ (a) (b) (c) Before elimination of intersegment sales. Includes assets directly associated with the generation of operating profit. Includes liabilities directly associated with the generation of operating profit. F-105 Starting from the Annual Report 2010, environmental provisions incurred by Eni SpA following the effect of inter-company guarantees given on behalf of Syndial SpA are reported in the segment information within “Other activities”. Prior period information has been restated accordingly. Intersegment revenues are conducted on an arm’s length basis. Geographic financial information Identifiable assets and investments by geographic area of origin ((cid:1) million) 2009 Identifiable assets (a) ............... Capital expenditures............... 2010 Identifiable assets (a) ............... Capital expenditures............... 2011 Identifiable assets (a) ............... Capital expenditures............... _______ Other European Union Rest of Europe Italy Americas Asia Africa Other areas Total 40,861 3,198 15,571 1,454 45,342 3,044 16,322 1,710 47,908 3,587 16,196 1,337 3,520 574 5,091 724 6,763 1,174 6,337 1,207 11,187 2,033 23,397 4,645 1,262 102,135 13,695 584 6,837 1,156 12,459 1,941 27,322 5,083 1,489 114,862 13,870 212 7,465 978 14,077 1,608 29,942 4,369 1,891 124,242 13,438 385 (a) Includes assets directly associated with the generation of operating profit. Net sales from operations by geographic area of destination ((cid:1) million) 2009 2010 2011 Italy ...................................................................................................... Other European Union ........................................................................ Rest of Europe ..................................................................................... Americas .............................................................................................. Asia ...................................................................................................... Africa ................................................................................................... Other areas ........................................................................................... 27,950 24,331 5,213 7,080 8,208 10,174 271 83,227 47,802 21,125 4,172 6,282 5,785 13,068 289 98,523 33,805 35,536 7,537 9,612 10,258 11,333 1,508 109,589 42 Transactions with related parties In the ordinary course of its business Eni enters into transactions regarding: (a) exchanges of goods, provision of services and financing with joint ventures, associates and non- consolidated subsidiaries; (b) exchanges of goods and provision of services with entities controlled by the Italian Government; (c) contributions to entities, controlled by Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment as well as research and development. In 2011, transactions with Eni Foundation were not material; (ii) Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with Enrico Mattei Foundation were not material. In application of the Consob Regulation No. 17221/2010, related to transactions with related parties and introduced by the Eni’s internal procedure approved by the Board of Directors on November 18, 2010, starting from January 1, 2011, the company Cosmi SpA and its relevant group’s companies, already mentioned in Eni annual F-106 reports up to the 2010, are not qualified as related parties through a member of the Board of Directors. However, according to the Eni’s internal procedure, the company Cosmi SpA is considered as a subject of interest of a member of the Board of Directors and, therefore, any operations carried out by Eni with such company are subjected to specific procedures, practices and obligations of transparency with the aim to guarantee their substantial and formal fairness. Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, on an arm’s length basis. Trade and other transactions Trade and other transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities controlled by the Italian Government in the 2009, 2010 and 2011, respectively, consisted of the following: 2009 ((cid:1) million) Name Joint ventures and associates Agiba Petroleum Co ........................ Altergaz SA...................................... ASG Scarl......................................... Azienda Energia e Servizi Torino SpA....................... Bayernoil Raffineriegesellschaft mbH............. Blue Stream Pipeline Co BV .......... Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG ....... CEPAV (Consorzio Eni per l’Alta Velocità) Uno.................. CEPAV (Consorzio Eni per l’Alta Velocità) Due.................. Fox Energy SpA............................... Gasversorgung Süddeutschland GmbH.................... Gruppo Distribuzione Petroli Srl.... InAgip doo ....................................... Karachaganak Petroleum Operating BV ................................... KWANDA - Suporte Logistico Lda ................................... Mellitah Oil & Gas BV ................... Petrobel Belayim Petroleum Co ..... Raffineria di Milazzo ScpA ............ Saipon Snc........................................ Super Octanos CA ........................... Trans Austria Gasleitung GmbH ............................ Transitgas AG .................................. Unión Fenosa Gas SA ..................... Other (*) ............................................. Unconsolidated entities controlled by Eni Agip Kazakhstan North Caspian Operating Co NV............................. Eni BTC Ltd .................................... Other (*) ............................................. Entities controlled by the Government Gruppo Enel ..................................... Gruppo Finmeccanica...................... GSE - Gestore Servizi Energetici ... Terna SpA ........................................ Other (*) ............................................. _______ Dec. 31, 2009 2009 Costs Revenues Receivables and other assets Payables and other liabilities Guarantees Goods Services Other Goods Services Other Other operating (expense) income 50 1 17 16 38 6 44 17 15 44 61 72 30 4 14 8 4 8 143 592 194 29 223 815 96 33 83 7 78 297 1,112 5 10 30 31 15 12 1 23 196 190 12 8 2 24 71 58 688 224 23 247 935 32 37 74 37 71 251 1,186 54 1 34 6,037 76 61 62 15 6,340 141 4 145 6,485 6,485 142 2 95 241 196 71 9 2 98 53 117 1,026 15 14 29 1,055 342 21 342 7 62 774 1,829 1 84 2 8 71 10 20 31 4 5 45 40 125 446 466 1 6 473 919 428 7 15 86 16 552 1,471 27 61 41 129 7 4 11 140 77 79 19 6 181 321 64 25 62 77 163 5 1 86 344 306 205 242 157 1 188 1,926 914 52 966 2,892 286 56 52 71 465 3,357 15 1 588 133 36 12 62 847 1 1 2 849 9 16 373 52 1 451 1,300 F-107 2 1 10 13 7 1 8 21 1 4 5 26 19 25 44 44 (*) Each individual amount included herein does not exceed (cid:1)50 million. 2010 ((cid:1) million) Name Joint ventures and associates ACAM Clienti SpA ........................ Agiba Petroleum Co ....................... Altergaz SA ..................................... Azienda Energia e Servizi Torino SpA ...................... Bayernoil Raffineriegesellschaft mbH ............ Blue Stream Pipeline Co BV ......... Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG ....... CEPAV (Consorzio Eni per l’Alta Velocità) Uno ................. CEPAV (Consorzio Eni per l’Alta Velocità) Due ................. Gasversorgung Süddeutschland GmbH ................... GreenStream BV ............................. Karachaganak Petroleum Operating BV .................................. KWANDA - Suporte Logistico Lda .................................. Mellitah Oil & Gas BV ................... Petrobel Belayim Petroleum Co .... Raffineria di Milazzo ScpA ........... Rosa GmbH ..................................... Saipon Snc ....................................... Super Octanos CA .......................... Supermetanol CA ............................ Trans Austria Gasleitung GmbH ... Transitgas AG ................................. Unión Fenosa Gas SA .................... Other (*) ............................................ Unconsolidated entities controlled by Eni Agip Kazakhstan North Caspian Operating Co NV ............. Eni BTC Ltd .................................... Other (*) ............................................ Entities controlled by the Government Gruppo Enel ..................................... Gruppo Finmeccanica...................... GSE - Gestore Servizi Energetici ... Terna SpA ........................................ Other (*) ............................................. _______ Dec. 31, 2010 2010 Costs Revenues Receivables and other assets Payables and other liabilities Guarantees Goods Services Other Goods Services Other Other operating (expense) income 14 2 1 13 20 28 6 3 4 39 51 30 8 21 7 2 8 11 138 406 177 22 199 605 83 44 94 35 62 318 923 2 5 65 32 14 12 3 13 253 1 137 34 20 23 13 69 8 51 755 285 22 307 1,062 44 44 104 41 44 277 1,339 1 19 821 58 57 32 1 37 6,054 76 53 58 11 6,290 27 1,015 5 95 78 51 152 5 3 95 346 225 714 266 149 70 232 2,486 2 894 152 3 155 6,445 6,445 4 6 1,021 20 50 466 115 651 1,672 48 942 3,428 318 37 71 74 500 3,928 56 262 2 121 62 1 8 157 50 2 1 60 35 817 5 5 822 128 22 462 55 44 711 1,533 1 2 37 6 2 7 17 33 3 7 29 37 91 272 917 23 940 1,212 471 9 16 28 5 529 1,741 28 50 78 5 2 7 85 1 81 31 4 117 202 2 1 1 1 12 17 7 4 11 28 9 21 30 58 3 38 41 41 (*) Each individual amount included herein does not exceed (cid:1)50 million. F-108 2011 ((cid:1) million) Name Joint ventures and associates ACAM Clienti SpA ......................... Agiba Petroleum Co ........................ Azienda Energia e Servizi Torino SpA....................... Bayernoil Raffineriegesellschaft mbH............. Blue Stream Pipeline Co BV .......... Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG ....... CEPAV (Consorzio Eni per l’Alta Velocità) Uno.................. CEPAV (Consorzio Eni per l’Alta Velocità) Due.................. Gasversorgung Süddeutschland GmbH.................... Gaz de Bordeaux SAS..................... Karachaganak Petroleum Operating BV ................................... KWANDA - Suporte Logistico Lda ................................... Mellitah Oil & Gas BV ................... Petrobel Belayim Petroleum Co ..... Petromar Lda.................................... Raffineria di Milazzo ScpA ............ Saipon Snc........................................ Super Octanos CA ........................... Supermetanol CA............................. Trans Austria Gasleitung GmbH .... Unión Fenosa Gas SA ..................... Other (*) ............................................. Unconsolidated entities controlled by Eni Agip Kazakhstan North Caspian Operating Co NV .............. Eni BTC Ltd..................................... Other (*) ............................................ Entities controlled by the Government Gruppo Enel ..................................... Gruppo Finmeccanica...................... GSE - Gestore Servizi Energetici ... Terna SpA ........................................ Other (*) ............................................. _______ Dec. 31, 2011 2011 Costs Revenues Receivables and other assets Payables and other liabilities Guarantees Goods Services Other Goods Services Other Other operating (expense) income 14 3 1 8 16 42 24 29 11 38 54 28 25 74 29 21 6 181 604 149 53 202 806 83 48 153 19 57 360 1,166 5 63 33 12 10 91 205 2 141 46 6 31 35 10 100 790 238 68 306 1,096 48 51 158 52 41 350 1,446 2 1 25 6,074 57 48 58 3 6,243 157 6 163 6,406 6,406 1,108 58 72 33 37 1,333 11 11 1,344 5 14 615 119 1 754 2,098 6 86 43 59 146 4 84 256 2 71 576 7 322 160 311 2,133 781 51 832 2,965 429 54 110 77 670 3,635 60 2 147 201 69 8 232 3 130 131 983 11 11 994 33 22 607 56 49 767 1,761 1 2 21 38 5 13 3 69 68 16 5 7 54 93 395 1,182 11 1,193 1,588 482 12 10 26 3 533 2,121 23 70 93 7 3 10 103 2 54 23 5 84 187 1 1 1 1 8 12 7 8 15 27 1 11 4 16 43 32 32 32 (*) Each individual amount included herein does not exceed (cid:1)50 million. Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned: • sale of natural gas to ACAM Clienti SpA, Gasversorgung Süddeutschland GmbH and Gaz de Bordeaux SAS; provisions of specialized services in upstream activities and Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Agip Kazakhstan North Caspian Operating Co NV, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only for Karachaganak Petroleum Operating BV, purchase of oil products and to Agip Kazakhstan North Caspian Operating Co NV, provisions of services by the Engineering & Construction segment; services charged to Eni’s associates are invoiced on the basis of incurred costs; gas transportation and distribution services from Azienda Energia e Servizi Torino SpA; payments of refining services to Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs; acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV, Trans Austria Gasleitung GmbH and, exclusively with Trans Austria Gasleitung GmbH, charges of fuel gas used as drive gas; • • • • F-109 • • • • • • • supply of oil products to Bronberger & Kessler und Gilg & Schweiger GmbH & Co KG and Raffineria di Milazzo ScpA on the basis of prices referred to the quotations on international markets of the main oil products, as they would be conducted on an arm’s length basis; transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with CEPAV (Consorzio Eni per l’Alta Velocità) Uno and related guarantees; guarantees issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due and Saipon Snc in relation to contractual commitments related to the execution of project planning and realization; planning, construction and technical assistance to support by KWANDA - Suporte Logistico Lda and Petromar Lda; acquisition of petrochemical products from Super Octanos CA and Supermetanol CA on the basis of prices referred to the quotations on international markets of the main products; performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and sales of LNG; guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd. Most significant transactions with entities controlled by the Italian Government concerned: • sale and transportation service of natural gas, the sale of fuel oil and the sale and purchase of electricity and the acquisition of electricity transmission service with Gruppo Enel; a long-term contract for the maintenance of new combined cycle power plants with Gruppo Finmeccanica; sale and purchase of electricity and green certificates with GSE - Gestore Servizi Energetici; sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with Terna SpA. • • • Financing transactions Financing transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities controlled by the Government in the 2009, 2010 and 2011, respectively, consisted of the following: 2009 ((cid:1) million) Name Joint ventures and associates Artic Russia BV ............................................. Bayernoil Raffineriegesellschaft mbH ......... Blue Stream Pipeline Co BV......................... Raffineria di Milazzo ScpA .......................... Trans Austria Gasleitung GmbH .................. Transmediterranean Pipeline Co Ltd ........... Other (*) ........................................................... Unconsolidated entities controlled by Eni Other (*) ........................................................... Dec. 31, 2009 2009 Receivables Payables Guarantees Charges Gains Income from equity instruments 70 133 171 149 125 648 78 78 726 1 112 113 34 34 147 170 692 85 24 971 1 1 972 1 12 5 3 3 24 3 3 27 2 2 2 2 4 _______ (*) Each individual amount included herein does not exceed (cid:1)50 million. F-110 2010 ((cid:1) million) Name Dec. 31, 2010 2010 Receivables Payables Guarantees Charges Gains Income from equity instruments Joint ventures and associates Artic Russia BV ............................................ Bayernoil Raffineriegesellschaft mbH ......... Blue Stream Pipeline Co BV ........................ GreenStream BV ........................................... Raffineria di Milazzo ScpA .......................... Trans Austria Gasleitung GmbH .................. Transmediterranean Pipeline Co Ltd ........... Other (*) .......................................................... Unconsolidated entities controlled by Eni Other (*) ........................................................... 104 119 459 144 141 105 1,072 53 53 1,125 3 8 2 75 88 39 39 127 648 120 24 792 1 1 793 _______ (*) Each individual amount included herein does not exceed (cid:1)50 million. 1 9 19 6 5 40 1 1 41 2011 ((cid:1) million) Name Joint ventures and associates Artic Russia BV ............................................. Bayernoil Raffineriegesellschaft mbH.......... Blue Stream Pipeline Co BV......................... CEPAV (Consorzio Eni per l’Alta Velocità) Due ................................ GreenStream BV ............................................ Raffineria di Milazzo ScpA........................... Société Centrale Electrique du Congo SA.... Transmediterranean Pipeline Co Ltd ............ Unión Fenosa Gas SA .................................... Other (*) ........................................................... Unconsolidated entities controlled by Eni Other (*) ........................................................... Entities controlled by the Government Gruppo Cassa Depositi e Prestiti................... Dec. 31, 2011 2011 Receivables Payables Guarantees Charges Gains Income from equity instruments 107 503 60 93 115 104 982 57 57 3 291 1 85 64 444 59 59 204 669 84 88 6 1,051 1 1 6 26 1 4 9 46 3 3 1 1 1,039 503 1,052 1 49 338 338 338 _______ (*) Each individual amount included herein does not exceed (cid:1)50 million. Most significant transactions with joint ventures, associates and non-consolidated subsidiaries concerned: • bank debt guarantee issued on behalf of Artic Russia BV, Blue Stream Pipeline Co BV, CEPAV (Consorzio Eni per l’Alta Velocità) Due, Société Centrale Electrique du Congo SA and Raffineria di Milazzo ScpA; financing loans granted to Bayernoil Raffineriegesellschaft mbH for capital expenditures in refining plants and to Société Centrale Electrique du Congo SA for the construction of an electric plant in Congo; the financing of the construction of natural gas transmission facilities and transport services with GreenStream BV and Transmediterranean Pipeline Co Ltd; • • F-111 • a cash deposit at Eni’s financial companies on behalf of Blue Stream Pipeline Co BV and Unión Fenosa Gas SA. Income from investments from Cassa Depositi e Prestiti related to a gain recorded on the divestment of the 89% interest (entire stake own) in Trans Austria Gasleitung GmbH to CDP Gas Srl. Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows The impact of transactions and positions with related parties on the balance sheet consisted of the following: ((cid:1) million) Dec. 31, 2009 Dec. 31, 2010 Dec. 31, 2011 Total Related parties Impact (%) Total Related parties Impact (%) Total Related parties Impact (%) Trade and other receivables..................... Other current assets ...... Other non-current financial receivables..... Other non-current assets.............................. Current financial liabilities........................ Trade and other payables......................... Other current liabilities Other non-current liabilities........................ 20,348 1,307 1,355 9 6.66 0.69 23,636 1,350 1,356 9 5.74 0.67 24,595 2,326 1,496 2 6.08 0.09 1,148 1,938 3,545 438 40 147 19,174 1,856 1,241 5 2,480 49 38.15 1,523 668 16 127 3,355 6,515 22,575 1,620 1,297 5 2,194 45 43.86 1,578 704 44.61 3 0.07 503 11.28 1,446 6.31 0.48 1.95 5.75 0.31 2.05 4,225 4,459 22,912 2,237 2,900 2.06 4.15 6.47 0.27 1.98 The impact of transactions with related parties on the profit and loss accounts consisted of the following: ((cid:1) million) Net sales from operations...................... Other income and revenues ................. Purchases, services and other........................ Payroll and related costs................... Other operating (expense) income.......... Financial income........... Financial expense ......... Other gain (loss) from investments .......... 2009 Related parties Total 83,227 3,300 1,118 26 58,351 4,999 15 44 27 (4) 4,181 55 5,950 (6,497) 176 Impact (%) Total 2010 Related parties Impact (%) Total 2011 Related parties Impact (%) 3.97 2.33 8.57 0.36 80.00 0.45 0.06 98,523 3,274 3.32 109,589 3,882 956 58 6.07 933 43 69,135 5,825 8.43 79,191 5,887 4,785 131 6,117 (6,713) 619 28 41 41 0.59 4,749 31.30 0.67 171 6,379 (7,396) 33 32 49 (1) 1,627 338 20.77 3.54 4.61 7.43 0.69 18.71 0.77 0.01 Transactions with related parties fell within the ordinary course of Eni’s business and were mainly conducted on an arm’s length basis. F-112 The main cash flows with related parties are provided below: ((cid:1) million) 2009 2010 2011 Revenues and other income ................................................................ Costs and other expenses .................................................................... Other operating (expense) income ..................................................... Net change in trade and other receivables and liabilities ................. Dividends and net interests ................................................................. Net cash provided by operating activities ..................................... Capital expenditures in tangible and intangible assets ..................... Disposal of investments ...................................................................... Change in accounts payable in relation to investments .................... Change in financial receivables .......................................................... Net cash used in investing activities ............................................... Change in financial liabilities ............................................................. Net cash used in financing activities ............................................... Total financial flows to related parties .......................................... 3,326 (4,999) 44 34 407 (1,188) (1,364) 19 83 (1,262) (14) (14) (2,464) 3,332 (5,825) 41 182 521 (1,749) (1,764) 10 128 (1,626) (23) (23) (3,398) 3,925 (4,504) 32 (140) 501 (186) (1,416) 533 (21) 104 (800) 348 348 (638) Disposals of investments for (cid:1)533 million related to the divestment of the entire 89% interest in Trans Austria Gasleitung GmbH to CDP Gas Srl, Gruppo Cassa Depositi e Prestiti. The impact of cash flows with related parties consisted of the following: ((cid:1) million) 2009 Related parties Total Impact (%) Total 2010 Related parties Impact (%) Total 2011 Related parties Impact (%) Cash provided by operating activities ....... Cash used in investing activities ........................ Cash used in financing activities ........................ 11,136 (1,188) .. 14,694 (1,749) .. 14,382 (186) .. (10,254) (1,262) 12.31 (12,965) (1,626) 12.54 (11,218) (800) 7.13 (1,183) (14) 1.18 (1,827) (23) 1.26 (3,223) 348 43 Significant non-recurring events and operations Non-recurring charge (income) consisted of the following: ((cid:1) million) 2009 2010 2011 Estimate of the charge from the possible resolution of the TSKJ matter ............................................................................... Fines sanctioned by Antitrust Authorities .......................................... 250 250 24 (270) (246) 69 69 In 2011, a non-recurring provision was made amounting to (cid:1)69 million to reflect the expected liabilities on an antitrust proceeding in the European sector of rubbers taking into account an unfavorable sentence issued by the Court of Justice of the European Community on the matter. In 2010, a non-recurring gain amounting to (cid:1)270 million related to the favorable settlement of an antitrust proceedings concerning alleged anti-competitive behavior charged to Eni regarding third party access to the import pipeline from Algeria in 2003. This resulted in a significantly lower fine imposed on the Company than the one sanctioned by the Antitrust Authority in 2003 and then accrued to profit and loss. Also in 2010 a charge of (cid:1)24 million related to a fine of $30 million for the TSKJ matter following the agreement with the Federal Government of Nigeria for the settling of the legal proceeding. F-113 44 Positions or transactions deriving from atypical and/or unusual operations In 2009, 2010 and 2011 no transactions deriving from atypical and/or unusual operations were reported. 45 Subsequent events On March 1, 2012, as part of their strategic partnership, Eni and Gazprom signed a preliminary agreement on the revision of the long-term 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 from 2012. For the agreement to become effective, it is necessary that the existing supply contracts be amended accordingly. F-114 Supplemental oil and gas information (unaudited) The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Amounts related to minority interests are not significant. Capitalized costs Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following: ((cid:1) million) Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total (8,020) 3,767 December 31, 2010 Consolidated subsidiaries Proved mineral interests............................. 10,576 32 Unproved mineral interests........................ 270 Support equipment and facilities ............... Incomplete wells and other........................ 909 Gross Capitalized Costs........................... 11,787 Accumulated depreciation, depletion and amortization......................... Net Capitalized Costs consolidated subsidiaries (a) (b) ................. Equity-accounted entities Proved mineral interests............................. Unproved mineral interests........................ Support equipment and facilities ............... Incomplete wells and other........................ Gross Capitalized Costs .......................... Accumulated depreciation, depletion and amortization......................... Net Capitalized Costs equity-accounted entities (a) (b) .................. December 31, 2011 Consolidated subsidiaries Proved mineral interests............................. 11,356 31 Unproved mineral interests........................ 285 Support equipment and facilities ............... 956 Incomplete wells and other........................ Gross Capitalized Costs........................... 12,628 Accumulated depreciation, depletion and amortization......................... Net Capitalized Costs consolidated subsidiaries (a) (b).................. Equity-accounted entities Proved mineral interests............................. Unproved mineral interests........................ Support equipment and facilities ............... Incomplete wells and other........................ Gross Capitalized Costs........................... Accumulated depreciation, depletion and amortization......................... Net Capitalized Costs equity-accounted entities (a) (b) ................. 3,995 (8,633) 10,616 320 33 584 11,553 14,051 570 1,391 2,069 18,081 17,057 2,006 716 1,089 20,868 1,989 39 70 4,644 6,742 5,552 1,561 21 107 7,241 6,617 1,979 53 1,444 10,093 1,674 42 6 84 1,806 68,132 6,549 2,560 10,930 88,171 (7,771) (8,558) (11,067) (756) (4,699) (5,591) (522) (46,984) 3,782 9,523 9,801 5,986 2,542 4,502 1,284 41,187 79 7 86 191 332 523 479 469 6 139 1,093 178 3 197 378 (73) (103) (350) (66) 13 420 743 312 927 469 16 668 2,080 (592) 1,488 11,481 325 34 1,778 13,618 15,519 582 1,442 2,755 20,298 19,539 2,893 923 898 24,253 2,523 40 85 5,333 7,981 6,136 1,543 41 136 7,856 8,976 1,409 61 1,029 11,475 1,889 204 13 2,106 77,419 7,027 2,884 12,885 100,215 (8,582) (9,750) (13,069) (906) (5,411) (6,806) (650) (53,807) 5,036 10,548 11,184 7,075 2,445 4,669 1,456 46,408 2 44 2 48 80 8 1 89 240 1,011 1,251 698 271 6 185 1,160 330 3 223 556 (2) (74) (131) (388) (89) 46 15 1,120 772 467 1,350 315 17 1,422 3,104 (684) 2,420 _______ (a) (b) The amounts include net capitalized financial charges totaling (cid:1)591 million in 2010 and (cid:1)614 million in 2011 for the consolidated subsidiaries and (cid:1)6 million in 2010 and (cid:1)11 million in 2011 for equity-accounted entities. The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The “Successful Effort Method” application would have led to an increase in net capitalized costs of (cid:1)3,410 million in 2010 and (cid:1)3,608 million in 2011 for the consolidated subsidiaries and of (cid:1)76 million in 2010 and (cid:1)101 million in 2011 for equity-accounted entities. F-115 Costs incurred Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following: ((cid:1) million) 2009 Consolidated subsidiaries Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (a) ........................................... Total costs incurred consolidated subsidiaries ......................... Equity-accounted entities Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (b)........................................... Total costs incurred equity-accounted entities ......................... 2010 Consolidated subsidiaries Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (a) ........................................... Total costs incurred consolidated subsidiaries ......................... Equity-accounted entities Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (b)........................................... Total costs incurred equity-accounted entities ......................... 2011 Consolidated subsidiaries Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (a) ........................................... Total costs incurred consolidated subsidiaries ......................... Equity-accounted entities Proved property acquisitions ..................... Unproved property acquisitions................. Exploration.................................................. Development (b)........................................... Total costs incurred equity-accounted entities ......................... _______ Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 298 54 317 1,401 27 42 284 2,121 114 727 20 1,086 11 83 159 423 131 43 242 858 467 222 1,228 7,820 52 462 841 2,070 2,474 1,106 676 1,274 514 9,737 6 3 9 1 62 63 9 94 103 25 47 72 41 206 247 114 890 84 2,674 406 1,909 6 1,031 223 359 119 1,309 26 160 1,012 8,911 1,004 2,758 2,315 1,037 582 1,428 186 9,923 40 742 782 34 579 613 4 7 11 2 200 202 4 46 50 35 114 149 45 367 412 754 1,210 8,282 38 815 853 100 1,921 57 128 1,487 697 482 1,698 2,021 1,672 2,877 6 935 941 156 385 60 971 240 70 541 1,031 310 10,246 5 2 7 3 3 5 659 664 8 68 76 9 154 163 27 886 913 (a) (b) Includes the abandonment costs of the assets for (cid:1)301 million in 2009, (cid:1)269 million in 2010 and (cid:1)918 million in 2011. Includes the abandonment costs of the assets for -(cid:1)6 million in 2009, -(cid:1)3 million in 2010 and (cid:1)15 million in 2011. Results of operations from oil and gas producing activities Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are stateowned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. F-116 Results of operations from oil and gas producing activities by geographical area consist of the following: ((cid:1) million) 2009 Consolidated subsidiaries Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment (a) ..................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of consolidated subsidiaries (b) Equity-accounted entities Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment......................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of equity-accounted entities (b) 2010 Consolidated subsidiaries Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment (a) ..................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of consolidated subsidiaries (b) Equity-accounted entities Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment......................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of equity-accounted entities (b) _______ Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 2,274 2,274 (271) (148) (40) (463) (125) 2,583 540 3,123 (517) (114) (921) (134) 1,738 5,037 6,775 (553) (20) (319) 4,386 586 4,972 (749) (445) (451) (956) (471) (1,502) (467) 1,227 (467) 1,437 (833) 4,456 (3,010) 1,358 (1,042) 245 739 984 (153) (20) (78) (186) 547 (180) 41 1,208 1,249 (78) (34) (204) 808 639 1,447 (273) (341) (535) (17) (1,108) 170 381 (67) (105) (2) 29 181 210 (41) (62) (186) (47) (126) 23 12,104 8,930 21,034 (2,635) (647) (1,551) (5,749) (1,277) 9,175 (5,578) 760 604 1,446 316 367 314 (107) (103) 3,597 15 15 (11) (3) (6) (1) 1 (5) 4 (1) 45 45 (7) (1) (15) 6 28 (14) 14 49 49 (7) (8) (35) (11) (12) (10) (22) 2,725 2,725 (278) (184) (35) (621) (560) 3,006 263 3,269 (555) (116) 2,094 6,604 8,698 (593) (300) (85) 5,314 1,696 7,010 (902) (700) (465) (615) 254 (1,063) (392) (1,739) (219) 1,047 (382) 2,237 (1,296) 6,265 (4,037) 2,985 (1,962) 324 890 1,214 (184) (6) (84) (161) 779 (291) 34 1,429 1,463 (150) (37) (263) (696) (138) 179 (119) 123 123 (9) (41) (26) (25) (37) (15) (20) (35) 1,139 562 1,701 (292) (204) (872) (45) 288 (154) 232 232 (34) (44) (41) (76) (41) (4) (40) (44) 69 289 358 (69) (25) (84) (25) 14,705 11,733 26,438 (3,023) (1,221) (1,199) (5,774) (1,286) 155 (36) 13,935 (8,277) 665 941 2,228 1,023 488 60 134 119 5,658 16 16 (16) (3) (4) (4) 6 (5) 4 (1) 65 65 (9) (2) (26) 12 40 (20) 20 69 69 (7) (4) (25) (10) 23 (17) 6 206 206 (9) (69) (35) (17) (67) 9 (33) (24) 356 356 (41) (72) (45) (72) (59) 67 (66) 1 (a) (b) Includes asset impairments amounting to (cid:1)576 million in 2009 and (cid:1)123 million in 2010. The “Successful Effort Method” application would have led to an increase of result of operations of (cid:1)320 million in 2009 and a decrease of (cid:1)385 million in 2010 for the consolidated subsidiaries and an increase of (cid:1)26 million in 2009 and a decrease of (cid:1)5 million in 2010 for equity-accounted entities. F-117 ((cid:1) million) 2011 Consolidated subsidiaries Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment (a) ..................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of consolidated subsidiaries (b) Equity-accounted entities Revenues: - sales to consolidated entities ................... - sales to third parties ................................. Total revenues ........................................... Operations costs.......................................... Production taxes ......................................... Exploration expenses.................................. D.D. & A. and Provision for abandonment......................................... Other income (expenses)............................ Pretax income from producing activities .................................. Income taxes ............................................... Results of operations from E&P activities of equity-accounted entities (b) _______ Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 3,583 3,583 (284) (245) (38) (606) (562) 3,695 514 4,209 (566) (113) (704) 142 1,956 5,090 7,046 (483) (165) (128) 5,945 1,937 7,882 (830) (853) (509) (843) (508) (1,435) (314) 411 1,268 1,679 (171) (6) (112) (160) 1,848 (761) 2,968 (2,043) 4,919 (3,013) 3,941 (2,680) 1,230 (413) 178 1,233 1,411 (183) (37) (177) (486) (151) 377 (157) 1,634 132 1,766 (364) (136) (901) 125 490 (184) 93 344 437 (88) (58) (103) 8 196 (120) 17,495 10,518 28,013 (2,969) (1,300) (1,165) (5,190) (1,420) 15,969 (9,371) 1,087 925 1,906 1,261 817 220 306 76 6,598 2 2 (1) (6) (4) (9) (9) 19 19 (11) (4) (1) 6 9 (4) 5 93 93 (10) (5) (24) 11 65 (35) 30 89 89 (9) (8) (23) (20) 29 (32) (3) 262 262 (17) (113) (9) (21) (51) 51 (4) 47 465 465 (47) (118) (28) (69) (58) 145 (75) 70 (a) (b) Includes asset impairments amounting to (cid:1)189 million in 2011. The “Successful Effort Method” application would have led to an increase of result of operations of (cid:1)118 million in 2011 for the consolidated subsidiaries and an increase of (cid:1)20 million in 2011 for equity-accounted entities. Oil and natural gas reserves Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un- weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2011, the average price for the marker Brent crude oil was $111 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation18 of part of its (18) From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. F-118 proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report19. In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2011, Ryder Scott Company and DeGolyer and MacNaughton19 provided an independent evaluation of almost 32% of Eni’s total proved reserves as of December 31, 201120, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three year period from 2009 to 2011, 85% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2011, the principal property not subjected to independent evaluation in the last three years is Kashagan (Kazakhstan). Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 57%, 55% and 49% of total proved reserves as of December 31, 2009, 2010 and 2011, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and “buy-back” contracts; proved reserves associated with such contracts represented 2%, 3% and 1% of total proved reserves on an oil-equivalent basis as of December 31, 2009, 2010 and 2011, respectively. Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 0.3%, 0.6% and 0.8% of total proved reserves as of December 31, 2009, 2010 and 2011, respectively, on an oil- equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant; and (iv) volumes of natural gas held in certain Eni storage fields in Italy. Proved reserves attributable to these fields include: (a) the residual natural gas volumes of the reservoirs; and (b) natural gas volumes from other Eni fields input into these reservoirs in subsequent periods. Proved reserves do not include volumes owned by or acquired from third parties. Gas withdrawn from storage is produced and thereby removed from proved reserves when sold. Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced. The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2009, 2010 and 2011. (19) (20) The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2011. Including reserves of equity-accounted entities. F-119 Crude oil (including condensate and natural gas liquids) (mmBBL) 2009 Reserves of consolidated subsidiaries at December 31, 2008 ........ of which: developed ................................. undeveloped ............................ Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2009......... Reserves of equity-accounted entities at December 31, 2008 ................. of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2009 ................. Reserves at December 31, 2009 .............. Developed................................................... Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped .............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... 2010 Reserves of consolidated subsidiaries at December 31, 2009......... of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2010......... Reserves of equity-accounted entities at December 31, 2009 ................. of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2010 ................. Reserves at December 31, 2010 .............. Developed................................................... Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped ............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... _______ Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia (a) America Australia and Oceania Total 186 111 75 57 10 (20) 277 222 55 40 8 74 (48) 823 613 210 129 10 38 (105) 783 576 207 2 78 15 5 (113) 911 298 613 (36) (26) 233 351 895 770 849 14 11 3 1 (2) 13 908 669 659 10 239 236 3 895 659 236 8 4 4 (1) 7 777 548 544 4 229 226 3 770 544 226 178 1 13 (108) (1) 75 1 22 (116) (2) 233 141 141 92 92 233 141 92 38 (23) 351 218 218 133 133 351 218 133 17 25 (44) 106 92 14 (35) 44 (21) 94 101 11 90 (51) 50 144 52 45 7 92 49 43 94 45 49 62 849 291 291 558 558 849 291 558 (37) (24) (17) 131 74 57 36 12 (26) 26 23 3 1 8 (3) 3,243 2,009 1,234 2 270 33 191 (362) 153 32 3,377 19 7 12 (3) 16 169 93 80 13 76 73 3 153 80 73 2 1 (22) 142 33 109 1 (6) (51) 86 3,463 2,035 2,001 34 1,428 1,376 52 3,377 2,001 1,376 335 2 61 (357) (3) 32 23 23 9 9 32 23 9 (3) 248 349 978 750 788 139 134 29 3,415 7 4 3 13 10 3 8 (2) (1) 19 997 674 656 18 323 322 1 6 756 537 533 4 219 217 2 788 251 251 537 537 50 7 43 (6) 44 183 44 39 5 139 100 39 16 13 3 (2) 12 117 (4) 139 273 87 62 25 186 72 114 86 34 52 12 117 (7) 208 3,623 2,003 1,951 52 1,620 1,464 156 29 20 20 9 9 248 183 183 65 65 349 207 207 142 142 (a) Proved reserves of equity-accounted entities at year end 2008 include 60% of the three former Yukos companies. From 2009, after the 51% call option exercised by Gazprom, values are reported at 29.4%. F-120 (mmBBL) 2011 Reserves of consolidated subsidiaries at December 31, 2010 ........ of which: developed ................................. undeveloped ............................ Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2011......... Reserves of equity-accounted entities at December 31, 2010 ................. of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2011 ................. Reserves at December 31, 2011 .............. Developed................................................... Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped .............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 248 183 65 34 (23) 349 207 142 58 2 9 (44) (2) 978 656 322 10 2 2 (75) 750 533 217 14 2 11 (100) (7) 788 251 537 139 39 100 (112) (20) (23) (13) 259 372 917 670 653 106 19 18 1 (2) 17 934 638 622 16 296 295 1 6 4 2 11 6 (1) 22 692 487 483 4 205 187 18 653 215 215 438 438 44 5 39 6 60 110 216 34 34 182 72 110 259 184 184 75 75 372 195 195 177 177 134 62 72 1 17 (20) 132 139 25 114 11 1 4 (4) 151 283 117 92 25 166 40 126 29 20 9 3,415 1,951 1,464 (15) 6 39 (302) (9) (4) 25 3,134 208 52 156 28 1 70 (7) 300 3,434 1,895 1,850 45 1,539 1,284 255 25 25 25 F-121 Natural gas (BCF) 2009 Reserves of consolidated subsidiaries at December 31, 2008 ........ of which: developed ................................. undeveloped ............................ Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2009 ........ Reserves of equity-accounted entities at December 31, 2008 ................ of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2009 ................ Reserves at December 31, 2009 ............. Developed .................................................. Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped ............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... 2010 Reserves of consolidated subsidiaries at December 31, 2009 ........ of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2010 ........ Reserves of equity-accounted entities at December 31, 2009 ................ of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2010 ................ Reserves at December 31, 2010 ............. Developed .................................................. Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped ............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... _______ Italy (a) Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia (b) America Australia and Oceania Total 2,844 2,031 813 97 1 (238) 1,421 1,122 299 149 25 26 (239) (2) 6,311 3,537 2,774 (309) 479 (587) 2,084 1,443 641 1 142 2,437 2,005 432 (204) (100) (94) 911 439 472 52 2 (151) 600 340 260 136 43 7 (155) (2) 606 221 385 (17) 4 (18) 17,214 11,138 6,076 137 (47) 25 519 (1,582) (4) 2,704 1,380 5,894 2,127 2,139 814 629 575 16,262 13 11 2 3 (2) 14 5,908 3,498 3,486 12 2,410 2,408 2 5,894 3,486 2,408 2 1 1 3 80 85 2,212 1,468 1,463 5 744 664 80 2,127 1,463 664 2,139 1,859 1,859 280 280 2,139 1,859 280 2,704 2,001 2,001 703 703 1,380 1,231 1,231 149 149 2,704 2,001 703 1,380 1,231 149 234 48 778 161 (179) 3,000 408 2,592 10 2 (12) (1,511) 1,487 2,301 756 539 217 1,545 275 1,270 814 539 275 211 2 631 506 506 125 123 2 629 506 123 41 (246) (48) 177 (204) 146 (609) (2) (161) (86) 4 (158) 5 (145) 3,015 420 2,595 18 80 (14) (1,511) 1,588 17,850 11,884 11,650 234 5,966 4,612 1,354 575 565 565 10 10 575 565 10 16,262 11,650 4,612 (18) 1,276 22 (35) 354 (1,644) (50) 2,644 1,401 6,207 2,127 1,874 871 530 544 16,198 14 12 2 6 6 (2) 85 5 80 (1) 34 2,644 2,061 2,061 583 583 1,401 1,103 1,103 298 298 24 6,231 3,122 3,100 22 3,109 3,107 2 118 2,245 1,554 1,550 4 691 577 114 1,874 1,621 1,621 253 253 1,487 217 1,270 44 (11) 1,520 2,391 774 560 214 1,617 311 1,306 2 2 2 18 22 552 437 431 6 115 99 16 1,588 234 1,354 51 58 (13) 544 539 539 5 5 1,684 17,882 11,211 10,965 246 6,671 5,233 1,438 (a) (b) Including, approximately 746, 769 and 767 BCF of natural gas held in storage at December 31, 2008, 2009 and 2010, respectively. Proved reserves of equity-accounted entities at year end 2008 include 60% of the three former Yukos companies. From 2009, after the 51% call option exercised by Gazprom, values are reported at 29.4%. F-122 (BCF) 2011 Reserves of consolidated subsidiaries at December 31, 2010 ........ of which: developed ................................. undeveloped ............................ Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of consolidated subsidiaries at December 31, 2011 ........ Reserves of equity-accounted entities at December 31, 2010 ................ of which: developed.................................. undeveloped.............................. Purchase of Minerals in Place.................... Revisions of Previous Estimates................ Improved Recovery .................................... Extensions and Discoveries ....................... Production ................................................... Sales of Minerals in Place.......................... Reserves of equity-accounted entities at December 31, 2011 ................ Reserves at December 31, 2011 ............. Developed .................................................. Consolidated subsidiaries........................... Equity-accounted entities........................... Undeveloped ............................................. Consolidated subsidiaries........................... Equity-accounted entities........................... _______ Italy (a) Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 2,644 2,061 583 9 80 4 (246) 1,401 1,103 298 199 3 18 (196) 6,207 3,100 3,107 2,127 1,550 577 1,874 1,621 253 871 560 311 436 (11) (142) (38) 9 (462) 18 (185) (84) (148) 530 431 99 51 131 (122) 544 539 5 96 (36) 16,198 10,965 5,233 9 671 3 180 (1,479) 2,491 1,425 6,190 1,949 1,648 685 590 604 15,582 2 24 22 2 (2) (2) 2,491 1,977 1,977 514 514 2 1,427 995 995 432 430 2 20 6,210 3,087 3,070 17 3,123 3,120 3 118 4 114 147 74 (1) 338 2,287 1,441 1,437 4 846 512 334 1,648 1,480 1,480 168 168 1,520 214 1,306 372 1,150 (9) 3,033 3,718 552 528 24 3,166 157 3,009 22 6 16 11 1,274 1,307 1,897 393 385 8 1,504 205 1,299 1,684 246 1,438 2 528 2,498 (12) 604 491 491 113 113 4,700 20,282 10,416 10,363 53 9,866 5,219 4,647 (a) Including, approximately 767 and 767 BCF of natural gas held in storage at December 31, 2010 and 2011, respectively. Standardized measure of discounted future net cash flows Estimated future cash inflows represent the revenues that would be received from production and are determined by applying year-end prices of oil and gas for the year ended December 31, 2008, and the average prices during the years ended December 31, 2009, 2010 and 2011 to estimated future production of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity. F-123 The standardized measure of discounted future net cash flows by geographical area consists of the following: ((cid:1) million) December 31, 2009 Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax...... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2009 ........ Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax...... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2009 .............................. Total consolidated subsidiaries and equity-accounted entities at December 31, 2009 .............................. December 31, 2010 Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax...... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2010 ........ Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax...... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2010 ............................... Total consolidated subsidiaries and equity-accounted entities at December 31, 2010 .............................. Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 26,243 (4,732) 22,057 (6,215) 59,413 33,676 (9,737) (7,771) 30,273 (6,545) 5,680 (1,427) 7,088 (1,797) 2,973 (529) 187,403 (38,753) (5,143) 16,368 (5,263) 11,105 (5,868) (5,375) 10,467 (6,621) 3,846 (1,455) (8,618) (5,134) 43,024 18,805 (9,894) (24,230) 8,911 18,794 (3,102) (9,160) (4,345) 19,383 (4,827) 14,556 (10,249) (1,409) 2,844 (636) 2,208 (520) (1,897) 3,394 (694) 2,700 (1,162) (214) 2,230 (563) 1,667 (771) (32,135) 116,515 (52,728) 63,787 (32,287) 5,237 2,391 9,634 250 (147) 5,809 427 (70) 4,307 1,688 2,389 (773) 1,538 652 (261) 896 (21) 82 (1) 81 (28) (137) 220 (45) 175 (80) (970) 646 (260) 386 (420) (40) 351 (126) 225 (82) 31,500 3,718 (1,251) (1,168) 1,299 (432) 867 (610) 53 95 (34) 143 257 5,237 2,391 9,687 5,904 4,307 1,654 1,681 896 31,757 30,047 (4,865) 27,973 (7,201) 86,728 45,790 (12,896) (13,605) 41,053 (6,686) 9,701 (3,201) 8,546 (2,250) 3,846 (611) 253,684 (51,315) (4,499) 20,683 (6,289) 14,394 (7,224) (6,491) 14,281 (9,562) 4,719 (1,608) (8,827) (5,310) 65,005 26,875 (37,108) (14,468) 27,897 12,407 (3,884) (13,117) (5,192) 29,175 (7,213) 21,962 (14,829) (3,489) 3,011 (872) 2,139 (419) (1,713) 4,583 (910) 3,673 (1,392) (221) 3,014 (805) 2,209 (850) (35,742) 166,627 (77,227) 89,400 (43,323) 7,170 3,111 14,780 498 (251) 8,523 750 (98) 7,133 (35) 212 (2) 210 (113) (128) 524 (69) 455 (160) 1,720 2,893 (972) (879) 1,042 (338) 704 (515) 2,281 7,363 (2,676) (1,188) 3,499 (2,145) 1,354 (852) 1,359 46,077 11,504 (3,997) (2,230) 5,277 (2,554) 2,723 (1,640) 97 295 189 502 1,083 7,170 3,111 14,877 8,818 7,133 1,909 2,783 1,359 47,160 F-124 ((cid:1) million) December 31, 2011 Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax...... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of consolidated subsidiaries at December 31, 2011 ........ Future cash inflows .................................... Future production costs.............................. Future development and abandonment costs .............................. Future net inflow before income tax ......... Future income tax....................................... Future net cash flows ............................... 10% discount factor.................................... Standardized measure of discounted future net cash flows of equity-accounted entities at December 31, 2011 .............................. Total consolidated subsidiaries and equity-accounted entities at December 31, 2011 .............................. Italy Rest of Europe North Africa Sub- Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total 38,200 (5,740) 37,974 (7,666) 109,825 59,263 (17,627) (15,191) 50,443 (7,845) 10,403 (3,852) 11,980 (2,687) 5,185 (813) 323,273 (61,421) (4,712) 27,748 (9,000) 18,748 (9,692) (7,059) 23,249 (15,912) 7,337 (2,572) (9,639) (5,734) 82,559 38,338 (46,676) (23,075) 35,883 15,263 (4,833) (16,191) (3,705) 38,893 (9,866) 29,027 (17,599) (2,842) 3,709 (1,124) 2,585 (559) (1,836) 7,457 (2,474) 4,983 (1,914) (35,751) (224) 4,148 226,101 (1,254) (109,381) 116,720 2,894 (54,482) (1,122) 9,056 4,765 21 (5) 19,692 10,430 1,866 (471) 649 (259) 11,428 2,026 6,141 (1,540) 3,069 15,067 (4,598) 1,772 (2) 14 (3) 11 (36) 354 (3) 351 (183) (147) 1,248 (189) 1,059 (475) (1,247) 3,354 (824) 2,530 (1,825) (1,754) 8,715 (5,368) 3,347 (2,155) 62,238 23,744 (6,873) (3,186) 13,685 (6,387) 7,298 (4,638) 11 168 584 705 1,192 2,660 9,056 4,776 19,860 11,014 11,428 2,731 4,261 1,772 64,898 F-125 Changes in standardized measure of discounted future net cash flows Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2009, 2010 and 2011, are as follows: ((cid:1) million) Standardized measure of discounted future net cash flows at December 31, 2008...................................................................................... Increase (Decrease): - sales, net of production costs ........................................................................ - net changes in sales and transfer prices, net of production costs ................ - extensions, discoveries and improved recovery, net of future production and development costs ............................................................... - changes in estimated future development and abandonment costs ............ - development costs incurred during the period that reduced future development costs .............................................................................. - revisions of quantity estimates ...................................................................... - accretion of discount ...................................................................................... - net change in income taxes ........................................................................... - purchase of reserves in-place ........................................................................ - sale of reserves in-place ................................................................................ - changes in production rates (timing) and other ........................................... Net increase (decrease) .................................................................................. Standardized measure of discounted future net cash flows at December 31, 2009 ..................................................................................... Increase (Decrease): - sales, net of production costs ........................................................................ - net changes in sales and transfer prices, net of production costs ................ - extensions, discoveries and improved recovery, net of future production and development costs ............................................................... - changes in estimated future development and abandonment costs ............ - development costs incurred during the period that reduced future development costs .............................................................................. - revisions of quantity estimates ...................................................................... - accretion of discount ...................................................................................... - net change in income taxes ........................................................................... - purchase of reserves in-place ........................................................................ - sale of reserves in-place ................................................................................ - changes in production rates (timing) and other ........................................... Net increase (decrease) .................................................................................. Standardized measure of discounted future net cash flows at December 31, 2010 ..................................................................................... Increase (Decrease):.......................................................................................... - sales, net of production costs ......................................................................... - net changes in sales and transfer prices, net of production costs................. - extensions, discoveries and improved recovery, net of future production and development costs........................................... - changes in estimated future development and abandonment costs ............. - development costs incurred during the period that reduced future development costs .......................................................................................... - revisions of quantity estimates....................................................................... - accretion of discount....................................................................................... - net change in income taxes ............................................................................ - purchase of reserves in-place ......................................................................... - sale of reserves in-place ................................................................................. - changes in production rates (timing) and other............................................. Net increase (decrease) .................................................................................. Standardized measure of discounted future net cash flows at December 31, 2011...................................................................................... Consolidated subsidiaries Equity- accounted entities Total 31,452 (17,752) 4,515 3,587 (9,915) 7,401 4,686 6,112 674 161 (7) 586 48 31,500 (22,194) 24,415 1,926 (6,464) 8,520 12,600 6,519 (11,802) (177) 1,234 14,577 38 31,490 (154) 286 22 (157) 208 (113) 29 (67) 81 84 219 257 (243) 406 1,409 (386) 368 143 53 (1,115) 191 826 (17,906) 4,801 3,609 (10,072) 7,609 4,573 6,141 607 161 74 670 267 31,757 (22,437) 24,821 3,335 (6,850) 8,888 12,743 6,572 (12,917) (177) 1,425 15,403 46,077 1,083 47,160 (23,744) 40,961 1,580 (3,890) 7,301 1,337 8,640 (17,067) 37 (146) 1,152 16,161 62,238 (300) 442 2,457 (392) 866 (87) 235 (1,678) 10 24 1,577 2,660 (24,044) 41,403 4,037 (4,282) 8,167 1,250 8,875 (18,745) 47 (146) 1,176 17,738 64,898 F-126 The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES Date: April 5, 2012 Eni SpA /s/ANTONIO CRISTODORO _______________________________________ Antonio Cristodoro Title: Head of Corporate Secretary’s Staff Office F-127 (This page intentionally left blank) EXHIBIT 1 Part I - Establishment - Name - Registered Office and Duration of the Company Eni SpA By-laws ARTICLE 1 1.1 “Eni S.p.A.” resulting from the transformation of Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953 is regulated by these By-laws. 1.2 The Company name may be written with an upper case or lower case initial. ARTICLE 2 2.1 The registered head office of the Company is located in Rome, Italy and the Company has two branches in San Donato Milanese (MI). 2.2 Main representative offices, affiliates and branches may be established and/or wound up in Italy or abroad in compliance with the law. ARTICLE 3 3.1 The Company is expected to exist until December 31, 2100. Its duration may be extended one or more times by resolution of the shareholders’ meeting. Part II - Corporate Purpose ARTICLE 4 4.1 The corporate purpose is the direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the field of hydrocarbons and natural gases, such as exploration and development of hydrocarbon fields, construction and operation of pipelines for transporting the same, processing, transformation, storage, utilisation and trade of hydrocarbons and natural vapours, all in respect of concessions provided by law. The Company also has the object of direct and/or indirect management, by way of shareholdings in companies, agencies or businesses, of activities in the fields of chemicals, nuclear fuels, geothermy, renewable energy sources and energy in general, in the sector of engineering and construction of industrial plants, in the mining sector, in the metallurgy sector, in the textile machinery sector, in the water sector, including derivation, drinking water, purification, distribution and reuse of waters; in the sector of environmental protection and treatment and disposal of waste, as well as in every other business activity that is instrumental, supplemental or complementary with the aforementioned activities. The Company also has the purpose of undertaking and managing the technical and financial co-ordination of subsidiaries and affiliated companies and the provision of financial assistance to them. The Company may undertake any transactions necessary or useful for the achievement of the corporate purpose; by way of example, it may initiate transactions involving real estate, moveable goods, trade and commerce, industry, finance and banking asset and liability transactions, and any action that is in any way connected with the corporate purposes with the exception of public fund raising and the performance of investment services as regulated by Legislative Decree No. 58 of February 24, 1998. The Company may take shareholdings and interests in other companies or businesses with similar, comparable or complementary purposes to its own or those of companies in which it has holdings, either in Italy or abroad, and it may provide real and or personal guarantees for its own and others’ obligations, especially performance bonds. Part III - Capital - Shareholdings - Bonds ARTICLE 5 5.1 The Company capital is 4,005,358,876.00 (four billion five million three hundred and fifty-eight thousand eight hundred and seventy-six) euro, represented by 4,005,358,876 (four billion five million three hundred and fifty- eight thousand eight hundred and seventy-six) ordinary shares with a nominal value of 1 (one) euro each. 5.2 Shares may not be split up and each share is entitled to one vote. 5.3 The fact of being a shareholder in itself constitutes approval of these By-laws. ARTICLE 6 6.1 Pursuant to Article 3 of Decree-law No. 332 of May 31, 1994, converted with amendments into Law No. 474 of July 30, 1994, noone, in any capacity, may own Company shares that entail a holding of more than 3 per cent. of voting share capital. Such maximum shareholding limit is calculated by taking into account the aggregate shareholding held by the controlling entity, either a physical or legal person or Company; its directly or indirectly controlled entities, as well as entities controlled by the same controlling entity; affiliated entities as well as people related to the second degree by blood or marriage, as long as they are not legally separated spouses. E - 1 Control exists, with reference also to entities other than companies, in the cases envisaged by Article 2359, paragraphs 1 and 2 of the Civil Code. Affiliation exists in the case set forth in Article 2359, paragraph 3, of the Civil Code as well as between entities that directly or indirectly, by way of subsidiaries, other than those managing investment funds, are bound, even with third parties, in agreements regarding the exercise of voting rights or the transfer of shares or portions of third companies or, in any event, in agreements or pacts as per Article 122 of Legislative Decree No. 58 of February 24, 1998 regarding third party companies if said agreements or pacts concern at least 10 per cent. of the voting capital, if they are listed companies, or 20 per cent. if they are unlisted companies. The aforementioned shareholding limit (3 per cent.) is calculated by taking into account shares held by any fiduciary nominee or intermediary. Any voting rights and any other non-financial rights attributable to voting capital held or controlled in excess of the maximum limit indicated in the foregoing, cannot be exercised and the voting rights of each entity to whom such limit on shareholding applies are reduced in proportion, unless otherwise jointly provided in advance by the parties involved. In the event that shares exceeding this limit are voted, any shareholders’ resolution adopted pursuant to such a vote may be challenged pursuant to Article 2377 of the Civil Code, if the required majority had not been reached without the votes exceeding the aforementioned maximum limit. Shares not entitled to vote are included in the determination of the quorum at shareholders’ meetings. 6.2 Pursuant to Article 2, paragraph 1 of Decree-law No. 332 of May 31, 1994, converted with amendments into Law No. 474 of July 30, 1994, as modified by Article 4, Paragraph 227, of Law No. 350 of December 24, 2003 the Minister of Economy and Finance retains the following special powers to be exercised in agreement with the Minister of the Economic Development and according to the criteria contained in the Decree issued by the President of the Council of Ministers on 10 June, 2004: a) opposition with respect to the acquisition of material shareholdings by entities affected by the shareholding limit as set forth in Article 3 of Decree-law No. 332 of May 31, 1994, converted with amendments into Law No. 474 of July 30, 1994, by which – as per Decree issued by the Minister of Treasury on October 16, 1995 – are meant those representing at least 3 per cent. of share capital with the right to vote at the ordinary shareholders’ meeting. The opposition is expressed within ten days of the date of the notice to be filed by the Board of Directors at the time request is made for registration in the shareholders’ register if the Minister considers that such an acquisition may prejudice the vital interests of the Italian State. Until the ten-day term is not lapsed, the voting rights and the non-asset linked rights connected with the shares representing a material shareholding may not be exercised. If the opposition power is exercised, through a duly motivated act in connection with the prejudice that may be caused by the operation to the vital interests of the Italian State, the transferee may not exercise the voting rights and the other non-asset linked rights connected with the shares representing a material shareholding and must sell said shares within one year. In case of failure to comply, the court, upon request of the Minister of Economy and Finance, will order the sale of the shares representing a material shareholding according to the procedures set forth in Article 2359-ter of the Civil Code. The act through which the opposition power is exercised may be challenged by the transferee before the Lazio Regional Administrative Court within sixty days as of its issue; b) opposition to the subscription of Shareholders’ pacts or agreements as per Article 122 of Legislative Decree No. 58 of February 24, 1998, involving – as per the Decree issued by the Minister of Treasury on October 16, 1995 – at least 3 per cent. of the share capital with the right to vote at ordinary shareholders’ meetings. In order to allow the exercise of the above mentioned opposition power, Consob notifies the Minister of Economy and Finance of the relevant pacts or agreements notified to it pursuant to the aforementioned Article 122 of Legislative Decree No. 58 of February 24, 1998. The opposition power must be exercised within ten days of the date of the notice by Consob. Until the ten-day term has elapsed, the voting right and the other non-asset linked rights connected with the shares held by the shareholders who have subscribed the above mentioned pacts or agreements may not be exercised. If the opposition power is exercised through the issue of an act that shall be duly motivated in consideration of the prejudice that may be caused by these pacts or agreements to the vital interests of the Italian State, the shareholders pacts or agreements shall be null and void. If in the shareholders’ meetings the shareholders who signed shareholders’ pacts or agreements should behave as if those pacts or agreements disciplined by Article 122 of Legislative Decree No. 58 of February 24, 1998 were still in effect, the resolutions approved with their vote, if determining for the approval, may be challenged. The act through which the opposition power is exercised may be challenged by the shareholders who joined the above mentioned pacts or agreements before the Lazio Regional Administrative Court within sixty days; c) veto power, duly motivated in relation to the effective prejudice to the interests of the Italian State, with respect to resolutions to dissolve the Company, to transfer the business, to merge, to demerge, to transfer the Company’s registered office abroad, to change the corporate purpose or to amend the By-laws cancelling or modifying the powers indicated in this Article. The act through which the veto power is exercised may be challenged within sixty days of its issue by the dissenting shareholders before the Lazio Regional Administrative Court; E - 2 d) appointment of one Director with no voting rights. Should such an appointed Director cease to hold office, the Minister of Economy and Finance in agreement with the Minister of Economic Development will appoint a substitute. ARTICLE 7 7.1 When shares are fully paid, and if the law so allows, they may be issued to the bearer. Bearer shares may be converted into registered shares and vice-versa. Conversion operations are performed at the shareholder’s expense. ARTICLE 8 8.1 In the event, and for whatever reason, that a share belongs to more than one person, the rights relating to said share may not be exercised by other than one person or by a proxy for all co-owners. ARTICLE 9 9.1 The shareholders’ meeting may resolve to increase the Company capital and fix the terms, conditions and means thereof. 9.2 The shareholders’ meeting may resolve to increase the Company capital by issuing shares, including shares of different classes, to be assigned for no consideration pursuant to Article 2349 of the Civil Code. ARTICLE 10 10.1 Payments on shares are requested by the Board of Directors in one or more times. 10.2 Shareholders who are late in payment are charged an interest calculated at the official discount rate established by the Bank of Italy, without prejudice to the provisions of Article 2344 of the Civil Code. ARTICLE 11 11.1 The Company may issue bonds, including convertible bonds and warrants, in compliance with the law. Part IV - Shareholders’ meetings ARTICLE 12 12.1 Ordinary and extraordinary shareholders’ meetings are usually held at the Company registered office unless otherwise resolved by the Board of Directors, provided however they are held in Italy. 12.2 An ordinary shareholders’ meeting is called at least once a year, within 180 days of the end of the Company financial year, to approve the financial statements, since the Company is required to draw up consolidated financial statements. 12.3 The Directors must call a shareholders’ meeting without delay when it is requested by shareholders representing at least one twentieth of the share capital. Calling a shareholders’ meeting upon request of shareholders cannot be made for the matters upon which, according to law, the shareholders’ meeting will resolve on the basis of a proposal of the Directors or on the basis of a project or report of the Board. The shareholders who request a meeting to be called must prepare a report on the proposals relating to the items to be discussed; the Board of Directors shall make the report available to the public, together with its own evaluations, if any, at the Company’s registered office, on the Company Website and in the other ways set forth in the Consob regulation, at the time the notice calling the meeting is published. 12.4 The Board of Directors shall make a report on the items on the agenda available to the public in the ways set out in the previous paragraph within the period of time for publication of the notice calling the shareholders’ meeting. ARTICLE 13 13.1 A shareholders’ meeting shall be called by notice published on the Company Website, as well as in the ways specified by Consob in its regulation, within the legal terms and in accordance with current law. Shareholders who severally or jointly represent at least one fortieth of the Company share capital may ask for items to be added to the agenda by submitting a request within ten days of the publication of the notice calling the meeting, unless a different term is provided by the law, indicating the further proposed items in their request. Requests must be submitted in writing. Additions to the agenda cannot be made for the matters upon which, according to law, the shareholders’ meeting will resolve on the basis of a proposal of the Directors or on the basis of a project or report of the Directors different from the report on the items in the agenda. The Board of Directors gives notice of the allowed additions to the agenda in the same ways prescribed for the publication of the notice calling the meeting at least fifteen days before the date set for the shareholders’ meeting, unless a different term is prescribed by law. Within the period of time prescribed for submission of a request to add items to the agenda, the requesting shareholders shall provide to the Board of Directors a report on the matters they propose should be debated. The Board of Directors makes the report available to the public, together with its own evaluations, if any, at the same time as the publication of the notice of the additions to the agenda in the ways set out in Article 12.3 of these By-laws. 13.2 The legitimate attendance of the shareholders’ meetings and the exercise of voting rights is confirmed by a statement to the Company from the authorized intermediary, in compliance with intermediary accounting records, E - 3 on behalf of the person with the voting right. The statement shall be issued by the intermediary on the basis of balances recorded at the end of the seventh trading day prior to the date of the shareholders’ meeting on first or single call. Credit and debit records entered on accounts after this deadline shall not be considered for the purpose of legitimising the exercise of voting rights at the shareholders’ meeting. The statement made by the authorized intermediary must reach the Company by the end of the third trading day prior to the date of the shareholders’ meeting on first or single call, or other deadline fixed by Consob regulation issued in agreement with the Bank of Italy. It remains implicit that the right to attend the meeting and vote shall be legitimate if the statements are received by the Company after the deadlines indicated above, provided they are received before the opening of the shareholders’ meeting on single call. ARTICLE 14 14.1 Those persons who are entitled to vote may appoint a representative in the shareholders’ meeting according to law, by means of a written proxy or in electronic form when this is provided for in specific regulations and in the ways set forth therein. In this latter case, electronic notification of the proxy may be carried out by using a special section of the Company Website in the ways indicated in the notice calling the meeting. In order to simplify the casting of vote by proxy issued by shareholders who are employees of the Company or of its subsidiaries and members of shareholders associations incorporated under and managed pursuant to current legislation regulating proxies collection, notice boards for communications and rooms to allow proxies collection are made available to said associations according to terms and conditions agreed from time to time by the Company with the legal representatives of said associations. 14.2 The Chairman of the meeting has to assure the regularity of proxies and, in general, the right to attend the meeting. 14.3 The right to vote may also be exercised by mail according to the laws and regulations in force concerning this matter. If envisaged in the notice calling the meeting, those persons entitled to vote may attend the shareholders’ meeting through telecommunication equipment, and exercise their right to vote by electronic means, in accordance with the law, the regulatory provisions on this subject and with the meeting Regulations. 14.4 The shareholders’ meetings are disciplined by the shareholders’ meeting Regulations approved by the ordinary shareholders’ meeting. 14.5 The Company may designate a subject for each shareholders’ meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the proposals on the agenda in the ways provided by the law and the regulatory provisions, by the end of the second trading day preceding the date set for the shareholders’ meeting on first or single call. The proxy is not valid for proposals on which no voting instructions have been provided. ARTICLE 15 15.1 The meeting is chaired by the Chairman of the Board of Directors, or in the event of his absence or impediment, by the Chief Executive Officer; in their absence, the meeting shall elect its own Chairman. 15.2 The Chairman of the meeting is assisted by a Secretary, who need not be a shareholder, to be designated by the shareholders present, and may appoint one or more scrutineers. ARTICLE 16 16.1 The ordinary shareholders’ meeting decides on all the matters for which it is legally entitled and authorises the business transfer. 16.2 The ordinary and the extraordinary shareholders’ meeting are normally held after more than one call, as provided for in these By-laws; their resolutions in first, second or third call must be passed with the majorities requested by the law in each case. The Board of Directors may, if it is deemed necessary, determine that both the ordinary and the extraordinary shareholders’ meeting shall be held after a single call. In case of a single call the majorities required by law in this case shall apply. 16.3 The resolutions of the shareholders’ meeting, passed in accordance with the legal regulations and these By-laws, are binding on all shareholders, including those not present or dissenting. 16.4 The minutes of ordinary meetings must be signed by the Chairman and the Secretary. 16.5 The minutes of extraordinary meetings must be drawn up by a notary public. Part V - The Board of Directors ARTICLE 17 17.1 The Company is managed by a Board of Directors consisting of no fewer than three and no more than nine members. The shareholders’ meeting determines the number within these limits. The Minister of Economy and Finance in agreement with the Minister of the Economic Development may appoint another member, with no voting rights, pursuant to Article 6.2, letter d), of the By-laws. 17.2 The Directors are appointed for a period of up to three financial years; this term lapses on the date of the shareholders’ meeting convened to approve the financial statements of the last year of their office. They may be reappointed. E - 4 17.3 The Board of Directors, except for the member appointed pursuant to Article 6.2, letter d) of these By-laws, is appointed by the shareholders’ meeting on the basis of lists presented by shareholders and by the Board of Directors; in such lists the candidates must be listed in numerical order. The lists must be filed with the Company’s registered office by the twenty-fifth day before the date of the shareholders’ meeting on first or single call, called to resolve on the appointment of members of the Board of Directors, and made available to the public in the ways set forth in the law and in the Consob regulation at least twenty-one days before the date set for the shareholders’ meeting on first or single call. Each shareholder may, severally or jointly, submit and vote on a single list. Controlling subjects, controlled companies by them and those under joint control cannot submit or participate in the submission of other lists, nor can they vote on them, even through intermediaries or trustees, controlled here meaning those companies referred to in Article 93 of legislative decree No. 58 of February 24, 1998. Each candidate may stand on a single list, on penalty of non-electability. Only those shareholders who, severally or jointly, represent at least 1 per cent. of the share capital or the different extent fixed by Consob with its regulation shall have the right to submit lists. Ownership of the minimum share needed to submit lists shall be determined by having regard to the shares registered to the shareholder on the day on which the lists are filed with the Company. Related certification may also be submitted after the filing, provided submission is within the time limit fixed for the publication of the lists by the Company. At least one Director, if there are no more than five Directors, or at least three Directors if there are more than five, shall satisfy the independence requirements set for the Board of Statutory Auditors members of listed companies. The independent candidates shall be expressly indicated in each list. All candidates shall also satisfy the integrity requirements set forth by the applicable legislation. Together with the filing of each list, on penalty of inadmissibility, the curriculum of each candidate, statements of each candidate to accept his/her nomination and attest, in his/her own responsibility, that causes for his/her ineligibility and incompatibility are non existing and that he/she satisfies the aforementioned integrity and, if any, independence requirements, shall be filed. The appointed Directors shall communicate to the Company if they have lost the above mentioned independence and integrity requirements and if situations of ineligibility or incompatibility have arisen. The Board of Directors evaluates periodically the independence and the integrity of its members and if situations of ineligibility or incompatibility have arisen. If the integrity or independence requirements declared and set forth by the legislation in force are not satisfied or lapse for a Director or if situations of ineligibility or incompatibility have arisen, the Board of Directors shall declare the Director’s disqualification and resolve upon his/her substitution or shall invite him/her to rectify the situation of incompatibility within the term set by the Board itself, on penalty of his/her disqualification. Directors shall be elected in the following manner: a) seven tenths of the Directors to be elected will be drawn out from the candidate list that receives the majority of votes expressed by the shareholders in the numerical order in which they appear on the list, rounded off in the event of a fractional number to the next lower number; b) the remaining Directors will be drawn out from the other candidate lists; said lists shall not be linked in any way, neither indirectly, to the shareholders who have submitted or voted the list that has obtained the highest number of votes; to this purpose the votes obtained by each candidate list will be divided by one or two or three depending on the number of the members to be elected. The quotients thus obtained will be assigned progressively to candidates of each said list in the order given in the lists themselves. Quotients thus assigned to candidates of said lists will be ordered in a decreasing numerical list. Those who obtain the highest quotients will be elected. In the event that more than one candidate obtains the same quotient, the candidate elected will be the one of the list that has not hitherto had a Director elected or that has elected the least number of Directors. In the event that none of the lists has yet elected a Director or that all of them have elected the same number of Directors, the candidate from all such lists who has obtained the largest number of votes will be elected. In the event of equal list votes and equal quotients, the entire shareholders’ meeting will vote again and the candidate elected will be the one who obtains a simple majority of the votes; c) if the minimum number of independent Directors prescribed in these By-laws has not been elected after the application of the procedure described above, the quotient to be assigned to the candidates in each list shall be calculated using the system described at letter b); the independent candidates not yet drawn from the lists pursuant to letters a) and b) above, who have the highest quotients will be elected in order to meet the provision of the By-laws on the number of the independent Directors. The Directors so appointed will replace the non-independent Directors to whom the lowest quotients have been assigned. If the number of independent candidates is lower than the minimum fixed in these By-laws, the shareholders’ meeting shall resolve, with the majorities prescribed by the law, to replace the non-independent candidates who received the lowest quotients; d) to appoint Directors for any reason not appointed pursuant to the aforementioned procedure, the shareholders’ meeting shall resolve, with the majorities prescribed by the law, in such a way as to ensure that the composition of the Board of Directors complies with the current legislation and the By-laws. The vote by list procedure shall apply only to the renewal of the entire Board of Directors. 17.4 The shareholders’ meeting may, even during the Board’s term of office, change the number of members of the Board of Directors, always within the limits set forth in the first paragraph of this Article, and make the related E - 5 appointments. The mandates of Directors so elected will expire at the same time as those of the Directors already serving. 17.5 If during the term of office one or more Directors should no longer hold office, action will be taken in compliance with Article 2386 of the Civil Code with exception of the Director appointed pursuant to Article 6.2 letter d) of these By-laws. If a majority of Directors should cease to hold office, the whole Board will be considered to have resigned, and the Board must promptly call a shareholders’ meeting to appoint a new Board. 17.6 The Board may establish Board Committees which have consulting and proposing functions on specific subjects. ARTICLE 18 18.1 If the shareholders’ meeting has not appointed a Chairman, the Board will elect one among its members. The Director appointed pursuant to Article 6.2, letter d) of the By-laws cannot be appointed as Chairman. 18.2 The Board, at the Chairman’s proposal, shall appoint a Secretary, who need not belong to the Company. ARTICLE 19 19.1 The Board meets in the place indicated in the meeting notice whenever the Chairman or, in case of his absence or impediment, the Chief Executive Officer deems necessary, or when written application has been made by the majority of its members. The Board of Directors may also be convened pursuant to Article 28.4 of these By-laws. The Board of Directors’ meetings may be held by video or teleconference if each of the participants in the meetings can be identified and if each can follow and participate in the discussion of the topics dealt with in real time. The Meeting is considered duly held in the place where the Chairman and the Secretary are present. 19.2 Usually notice is given at least five days in advance. In cases of urgency the period of notice may be shorter. The Board of Directors decides on how its meetings should be convened. 19.3 The Board of Directors must also be convened when so requested by at least two Directors or by one if the Board consists of three Director, to decide on a specific topic considered to be of particular importance, pertaining to the management of the Company, and said topic must be specified in the request. ARTICLE 20 20.1 The Chairman of the Board or, in his absence, the oldest Director in attendance shall chair the meeting. ARTICLE 21 21.1 For a Board meeting to be valid, a majority of serving Directors with voting rights must be present. 21.2 Resolutions shall be approved by majority of votes of the Directors with voting rights present; should votes be equal, the person who chairs the meeting shall have a casting vote. ARTICLE 22 22.1 The resolutions of the Board of Directors are entered in the minutes, which are recorded in a book kept for that purpose pursuant to the law, and said minutes are signed by the Chairman of the meeting and by the Secretary. 22.2 Copies of the minutes are bona fide if they are signed by the Chairman or the person acting for him or her and countersigned by the Secretary. ARTICLE 23 23.1 The Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, except for the acts that the law or these By-laws reserve for the shareholders’ meeting. 23.2 The Board of Directors shall deliberate on the following matters: - - - the merger and the proportional demerger of companies in which the Company owns shares or holdings representing at least 90 per cent. of the share capital; the establishment and winding up of branches; the amendment of the By-laws to comply with legal provisions. 23.3 The Board of Directors and the Chief Executive Officer shall promptly report to the Board of Statutory Auditors at least every three months and in any event at the time of the meetings of the Board of Directors, on the activity carried out and on the most significant economic, financial and capital transactions carried out by the Company and the companies it controls; in particular they shall report to the Board of Statutory Auditors those transactions in which they have an interest, on their own behalf or on behalf of third parties. ARTICLE 24 24.1 The Board of Directors delegates its powers to one of its members with the exception of the Director appointed pursuant to Article 6.2, letter d) of the By-laws, within the limits set forth in Article 2381 of the Civil Code; the Board may in addition delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may at any time withdraw the powers delegated hereon, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, upon the proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for single acts or categories of E - 6 acts on other members of the Board of Directors with the exception of the Director appointed pursuant to Article 6.2, letter d) of these By-laws. The Chairman and the Chief Executive Officer, within the limits of the authority attributed to them, may delegate and empower Company employees or third parties to represent the Company for single acts or specific categories of acts. Further, upon proposal of the Chief Executive Officer and in agreement with the Chairman, the Board of Directors may also appoint one or more General Managers and determine the powers to be conferred on them, after they have been ascertained to fulfil the integrity requirements prescribed by the law. The Board of Directors shall periodically check the integrity of the General Managers. Failure to satisfy these requirements shall result in disqualification from the position. Upon proposal of the Chief Executive Officer, in agreement with the Chairman and with the favourable opinion of the Board of Statutory Auditors, the Board of Directors appoints the Manager responsible for the preparation of the financial reporting documents. The Manager responsible for the preparation of the financial reporting documents must be chosen from among those persons who, for at least three years, have carried out: a) administration, control or senior management activities in companies listed on regulated stock exchanges in Italy or other European Union countries or other OECD countries with a share capital of no less than two million euro, or b) audit activities in the companies indicated in letter a) above, or c) professional activities or university teaching activities in the financial or accounting sectors, or d) senior management functions in public or private bodies in the financial, accounting, or control sectors. The Board of Directors shall monitor that the Manager responsible for the preparation of the financial reporting documents has adequate powers and means to execute his/her tasks and that the administrative and accounting procedures are effectively respected ARTICLE 25 25.1 Legal representation towards any judicial or administrative authority and towards third parties, and the Company signature, is vested in either the Chairman or the Chief Executive Officer. ARTICLE 26 26.1 The Chairman and the members of the Board of Directors are entitled to remuneration to be determined by the ordinary shareholders’ meeting. Said resolution, once taken, shall remain valid for subsequent financial years until the shareholders’ meeting decides otherwise. ARTICLE 27 27.1 The Chairman: a) represents the Company pursuant to Article 25.1; b) chairs the shareholders’ meeting pursuant to Article 15.1; c) calls and chairs meetings of the Board of Directors pursuant to Articles 19.1 and 20.1; d) checks that Board resolutions are implemented; e) exercises the powers delegated to him by the Board of Directors pursuant to Article 24.1. Part VI - Board of Statutory Auditors ARTICLE 28 28.1 The Board of Statutory Auditors consists of five effective members and two alternate members, chosen among persons who satisfy the professional and integrity requirements set forth by the Ministry of Justice Decree No. 162, of March 30, 2000. Pursuant to the aforementioned decree, the subjects closely connected to the business of the Company are: commercial law, business economics and corporate finance. Similarly, the sectors closely connected to those of interest of the Company are the engineering and geological sectors. The Statutory Auditors may be appointed members of administration and control bodies in other companies within the limits set by Consob regulation. 28.2 The Board of Statutory Auditors is appointed by the shareholders’ meeting on the basis of lists presented by the shareholders; in such lists the candidates are listed by progressive number. The procedures set forth in Article 17.3 and the provisions issued by Consob in its regulation shall apply to the submission, filing and publication of candidate lists. Lists shall be divided into two sections: the first concerns those candidates for appointment as effective Auditors and the second for the candidates for appointment as alternate Auditors. At least the first candidate in each section must be a chartered accountant and have carried out audit activities for no less than three years. Three effective Auditors and one alternate Auditor will be drawn from the list that obtains the majority of votes. The other two standing Auditors and the other alternate Auditor will be appointed pursuant to Article 17.3, letter b) of the By-laws. The procedure described in said Article shall apply separately to each section of the other lists. E - 7 The shareholders’ meeting appoints the Chairman of the Board of Statutory Auditors among the effective Auditors appointed according to Article 17.3 letter b) of these By-laws. The vote by list procedure shall apply only in case of renewal of the entire Board of Statutory Auditors. Should an effective Auditor from the candidate list that received a majority of the votes expressed by the shareholders be replaced, the replacement shall be the alternate Auditor from the same list; should an effective Auditor from the other candidate lists be replaced, the replacement shall be the Alternate Auditor from those other lists. 28.3 Retiring Auditors may be re-elected. 28.4 Subject to prior communication to the Chairman of the Board of Directors, the Board of Statutory Auditors may call shareholders’ meetings and of the Board of Directors. The power to call the Board of Directors may be exercised individually by each member of the Board of Statutory Auditors; at least two effective Auditors are required to call shareholders’ meetings. The Board of Statutory Auditors’ meetings may be held by video or teleconference if each of the participants in the meetings can be identified and if each can follow and participate in the discussion of the topics dealt with in real time. The Meeting is considered duly held in the place where the Chairman and the Secretary are present. Part VII - Financial Statements and Profits ARTICLE 29 29.1 The Company financial year ends on December 31 every year. 29.2 At the end of each financial year, the Board of Directors sees to the preparation of the Company financial statements in compliance with the law. 29.3 The Board of Directors may pay interim dividends to the shareholders during the financial year. ARTICLE 30 30.1 Dividends not collected within five years of the day on which they become payable will be prescribed in favour of the Company and allocated to reserves. Part VIII - Winding Up and Liquidation of the Company ARTICLE 31 31.1 In the event the Company is wound up, the shareholders’ meeting will resolve the manner of its liquidation, appoint one or more liquidators and determine their powers and remuneration. Part IX - General Provisions ARTICLE 32 32.1 For matters not expressly regulated by these By-laws, the norms of the Civil Code and special laws on these matters shall apply. 32.2 Pursuant to Article 3, paragraph 2, of Decreelaw No. 332 of May 31, 1994, converted with amendments into Law No. 474 of July 30, 1994, Article 6.1, subsection six, of these By-laws does not apply to the shareholding owned by the Ministry of Economy and Finance, public bodies or entities they control. ARTICLE 33 33.1 The Company retains all assets and liabilities held by the public law agency Ente Nazionale Idrocarburi before its transformation. E - 8 EXHIBIT 8 Subsidiary List of Eni’s subsidiaries for year 2011 Country of Incorporation Eni’s share of net profit (%) EXPLORATION & PRODUCTION Agosta Srl Eni Angola SpA Eni East Africa SpA Eni Mediterranea Idrocarburi SpA Eni Timor Leste SpA Eni West Africa SpA Eni Zubair SpA Ieoc SpA Società Adriatica Idrocarburi SpA Società Ionica Gas SpA Società Oleodotti Meridionali - SOM SpA Società Petrolifera Italiana SpA Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA Agip Caspian Sea BV Agip Energy and Natural Resources (Nigeria) Ltd Agip Karachaganak BV Agip Oil Ecuador BV Burren Energy (Bermuda) Ltd Burren Energy Congo Ltd Burren Energy (Egypt) Ltd Burren Energy India Ltd Burren Energy Ltd Burren Energy Plc Burren Energy (Services) Ltd Burren Resources Petroleum Ltd Burren Shakti Ltd Eni AEP Ltd Eni Algeria Exploration BV Eni Algeria Ltd Sàrl Eni Algeria Production BV Eni Ambalat Ltd Eni America Ltd Eni Angola Exploration BV Eni Angola Production BV Eni Arguni I Ltd Eni Australia BV Eni Australia Ltd Eni BB Petroleum Inc Eni Bukat Ltd Eni Bulungan BV Eni Canada Holding Ltd Eni CBM Ltd Eni China BV Eni Congo SA Eni Croatia BV Eni Dación BV Eni Denmark BV Eni Elgin/Franklin Ltd Eni Energy Russia BV Eni Exploration & Production Holding BV Eni Gabon SA Eni Ganal Ltd E - 9 Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Netherlands Nigeria Netherlands Netherlands Bermuda British Virgin Islands UK UK Cyprus UK UK Bermuda Bermuda UK Netherlands Luxembourg Netherlands UK USA Netherlands Netherlands UK Netherlands UK USA UK Netherlands Canada UK Netherlands Republic of the Congo Netherlands Netherlands Netherlands UK Netherlands Netherlands Gabon UK 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 70.00 99.96 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 99.96 100.00 Eni Gas & Power LNG Australia BV Eni Ghana Exploration and Production Ltd Eni Hewett Ltd Eni India Ltd Eni Indonesia Ltd Eni International NA NV Sàrl Eni Investments Plc Eni Iran BV Eni Iraq BV Eni Ireland BV Eni JPDA 03-13 Ltd Eni JPDA 06-105 Pty Ltd Eni Krueng Mane Ltd Eni Lasmo Plc Eni LNS Ltd Eni Mali BV Eni Marketing Inc Eni Middle East BV Eni Middle East Ltd Eni MOG Ltd (in liquidation) Eni Muara Bakau BV Eni Norge AS Eni North Africa BV Eni North Ganal Ltd Eni Oil Algeria Ltd Eni Oil do Brasil SA Eni Oil & Gas Inc Eni Oil Holdings BV Eni Pakistan Ltd Eni Pakistan (M) Ltd Sàrl Eni Papalang Ltd Eni Petroleum Co Inc Eni Petroleum US Llc Eni Polska spólka z ograniczona odpowiedzialnoscia Eni Popodi Ltd Eni Rapak Ltd Eni RD Congo SPRL Eni TNS Ltd Eni Togo BV Eni Transportation Ltd Eni Trinidad and Tobago Ltd Eni Tunisia BEK BV Eni Tunisia BV Eni UFL Ltd Eni UHL Ltd Eni UKCS Ltd Eni UK Holding Plc Eni UK Ltd Eni Ukraine Holdings BV Eni Ukraine Llc Eni ULT Ltd Eni ULX Ltd Eni USA Gas Marketing Llc Eni USA Inc Eni US Operating Co Inc Eni Venezuela BV Eni West Timor Ltd Eni Yemen Ltd First Calgary Petroleums LP First Calgary Petroleums Partner Co ULC Hindustan Oil Exploration Co Ltd Ieoc Exploration BV Ieoc Production BV E - 10 100.00 Netherlands 100.00 Ghana 100.00 UK 100.00 UK 100.00 UK 100.00 Luxembourg 100.00 UK 100.00 Netherlands 100.00 Netherlands 100.00 Netherlands 100.00 UK 100.00 Australia 100.00 UK 100.00 UK 100.00 UK 100.00 Netherlands 100.00 USA 100.00 Netherlands 100.00 UK 100.00 UK 100.00 Netherlands 100.00 Norway 100.00 Netherlands 100.00 UK 100.00 UK 100.00 Brazil 100.00 USA 100.00 Netherlands 100.00 UK 100.00 Luxembourg 100.00 UK 100.00 USA 100.00 USA 100.00 Poland 100.00 UK UK 100.00 Democratic Republic of the Congo 100.00 100.00 UK 100.00 Netherlands 100.00 UK 100.00 Trinidad & Tobago 100.00 Netherlands 100.00 Netherlands 100.00 UK 100.00 UK 100.00 UK 100.00 UK 100.00 UK 100.00 Netherlands 100.00 Ukraine 100.00 UK 100.00 UK 100.00 USA 100.00 USA 100.00 USA 100.00 Netherlands 100.00 UK 100.00 UK 100.00 USA 100.00 Canada 47.18 India 100.00 Netherlands 100.00 Netherlands Lasmo Sanga Sanga Ltd Nigerian Agip Exploration Ltd Nigerian Agip Oil Co Ltd OOO ‘Eni Energhia’ GAS & POWER Compagnia Napoletana di Illuminazione e Scaldamento col Gas SpA Eni Gas & Power Belgium SpA Eni Hellas SpA EniPower Mantova SpA EniPower SpA GNL Italia SpA LNG Shipping SpA Snam Rete Gas SpA (Snam SpA from January 1, 2012) Società EniPower Ferrara Srl Società Italiana per il Gas pA Stoccaggi Gas Italia SpA - Stogit SpA Toscana Energia Clienti SpA Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana Altergaz SA Distribuidora de Gas Cuyana SA Distrigas LNG Shipping SA Distrigas NV Eni Gas & Power Belgium SA Eni Gas & Power GmbH Eni Gas Transport Services SA Eni G&P France BV Eni G&P Trading BV Finpipe GIE Inversora de Gas Cuyana SA Société du Services du Gazoduc Transtunisien SA - Sergaz SA Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA Tigáz-Dso Földgázelosztó kft Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság Trans Tunisian Pipeline Co Ltd REFINING & MARKETING Costiero Gas Livorno SpA Ecofuel SpA Eni Fuel Centrosud SpA Eni Fuel Nord SpA Eni Rete oil&nonoil SpA Eni Trading & Shipping SpA Petrolig Srl Petroven Srl Raffineria di Gela SpA Eni Austria GmbH Eni Austria Tankstellenbetrieb GmbH Eni Benelux BV Eni Ceská Republika Sro Eni Deutschland GmbH Eni Ecuador SA Eni France Sàrl Eni Hungaria Zrt Eni Iberia SLU Eni Marketing Austria GmbH E - 11 Bermuda Nigeria Nigeria Russia Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Italy Slovenia France Argentina Belgium Belgium Belgium Germany Switzerland Netherlands Netherlands Belgium Argentina Tunisia Tunisia Hungary Hungary Channel Islands Italy Italy Italy Italy Italy Italy Italy Italy Italy Austria Austria Netherlands Czech Republic Germany Ecuador France Hungary Spain Austria 100.00 100.00 100.00 100.00 55.36 100.00 100.00 86.50 100.00 55.53 100.00 55.53 51.00 55.53 55.53 100.00 51.00 98.09 45.60 100.00 100.00 100.00 100.00 100.00 100.00 100.00 63.33 76.00 66.67 100.00 50.44 50.44 100.00 65.00 100.00 100.00 100.00 100.00 100.00 70.00 68.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 Eni Mineralölhandel GmbH Eni Romania Srl Eni Schmiertechnik GmbH Eni Slovenija doo Eni Slovensko Spol Sro Eni Suisse SA Eni Trading & Shipping BV Eni Trading & Shipping Inc Eni USA R&M Co Inc Esain SA PETROCHEMICALS Polimeri Europa SpA Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság Polimeri Europa Benelux SA Polimeri Europa France SAS Polimeri Europa GmbH Polimeri Europa Ibérica SA Polimeri Europa UK Ltd ENGINEERING & CONSTRUCTION Saipem SpA Saipem Energy Services SpA Servizi Energia Italia SpA SnamprogettiChiyoda SAS di Saipem SpA Andromeda Consultoria Tecnica e Representações Ltda BOSCONGO SA BOS Investment Ltd (in liquidation) BOS - UIE Ltd (in liquidation) Construction Saipem Canada Inc ER SAI Caspian Contractor Llc ERS - Equipment Rental & Services BV Global Petroprojects Services AG Medsai SAS (former SAS Port de Tanger) Moss Maritime AS Moss Maritime Inc North Caspian Service Co Petrex SA PT Saipem Indonesia Saigut SA de CV Saimexicana SA de CV Saipem America Inc Saipem Asia Sdn Bhd Saipem Australia Pty Ltd Saipem (Beijing) Technical Services Co Ltd Saipem Contracting Algérie SpA Saipem Contracting Netherlands BV Saipem Contracting (Nigeria) Ltd Saipem do Brasil Serviçõs de Petroleo Ltda Saipem Drilling Co Private Ltd Saipem India Projects Ltd Saipem International BV Saipem Libya Llc - SA.LI.CO. Llc Saipem Ltd Saipem Luxembourg SA Saipem (Malaysia) Sdn Bhd Saipem Maritime Asset Management Luxembourg Sàrl E - 12 Austria Romania Germany Slovenia Slovakia Switzerland Netherlands USA USA Ecuador Italy Hungary Belgium France Germany Spain UK Italy Italy Italy Italy Brazil Republic of the Congo UK UK Canada Kazakhstan Netherlands Switzerland France Norway USA Kazakhstan Peru Indonesia Mexico Mexico USA Malaysia Australia China Algeria Netherlands Nigeria Brazil India India Netherlands Libya UK Luxembourg Malaysia Luxembourg 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 43.23 43.23 43.23 43.19 43.23 43.23 43.23 43.23 43.23 21.62 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 42.35 43.23 43.23 43.23 43.23 43.23 43.23 43.23 17.89 43.23 Saipem Mediteran Usluge doo Saipem Misr for Petroleum Services SAE Saipem (Nigeria) Ltd Saipem Norge AS Saipem Offshore Norway AS Saipem (Portugal) Cómercio Marítimo, Sociedade Unipessoal Lda Saipem SA Saipem Services México SA de CV Saipem Services SA Saipem Singapore Pte Ltd Saipem UK Ltd Saipem Ukraine Llc SAIRUS Llc Sajer Iraq Co for Petroleum Services Trading General Contracting & Transport Llc Saudi Arabian Saipem Ltd Sigurd Rück AG Snamprogetti Canada Inc Snamprogetti Engineering BV Snamprogetti Ltd Snamprogetti Lummus Gas Ltd Snamprogetti Netherlands BV Snamprogetti Romania Srl Snamprogetti Saudi Arabia Co Ltd Llc Sofresid Engineering SA Sofresid SA Sonsub AS Sonsub International Pty Ltd Star Gulf FZ Co Terminal Portuário do Guarujá SA Varisal - Serviços de Consultadoria e Marketing Unipessoal Lda Croatia Egypt Nigeria Norway Norway Portugal France Mexico Belgium Singapore UK Ukraine Russia Irak Saudi Arabia Switzerland Canada Netherlands UK Malta Netherlands Romania Saudi Arabia France France Norway Australia United Arab Emirates Brazil Portugal OTHER ACTIVITIES Ing. Luigi Conti Vecchi SpA Syndial SpA - Attività Diversificate CORPORATE AND FINANCIAL COMPANIES Agenzia Giornalistica Italia SpA Eni Administration & Financial Service SpA Eni Corporate University SpA EniServizi SpA Serfactoring SpA Servizi Aerei SpA Banque Eni SA Eni Finance International SA (former Eni Coordination Center SA) Eni Finance USA Inc Eni Insurance Ltd Eni International BV Eni International Resources Ltd Italy Italy Italy Italy Italy Italy Italy Italy Belgium Belgium USA Ireland Netherlands UK 43.23 43.23 38.66 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 25.94 25.94 43.23 43.23 43.23 43.23 42.80 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 43.23 100.00 100.00 100.00 99.63 100.00 100.00 48.82 100.00 100.00 100.00 100.00 100.00 100.00 100.00 E - 13 EXHIBIT 11 Code of Ethics Approved by the Board of Directors of Eni SpA on March 14, 2008 The English text is a translation of the Italian official “Code of Ethics” For any conflict or discrepancies between the two texts the Italian text shall prevail TABLE OF CONTENTS Foreword I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS 1. Ethics, transparency, fairness, professionalism 2. Relations with shareholders and with the Market 2.1. Value for shareholders, efficiency, transparency 2.2. Self-Regulatory Code 2.3. Company information 2.4. Privileged information 2.5. Media 3. Relations with institutions, associations, local communities 3.1. Authorities and Public Institutions 3.2. Political organizations and trade unions 3.3. Development of local Communities 3.4. Promotion of “non profit” activities 4. Relations with customers and suppliers 4.1. Customers and consumers 4.2. Suppliers and external collaborators 5. Eni’s management, employees, collaborators 5.1. Development and protection of Human Resources 5.2. Knowledge Management 5.3. Corporate security 5.4. Harassment or mobbing in the workplace 5.5. Abuse of alcohol or drugs and no smoking III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS 1. System of internal control 1.1. Conflicts of interest 1.2. Transparency of accounting records 2. Health, safety, environment and public safety protection 3. Research, innovation and intellectual property protection 4. Confidentiality 4.1. Protection of business secret 4.2. Protection of privacy 4.3. Membership in associations, participation in initiatives, events or external meetings IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES 1. Obligation to know the Code and to report any possible violation thereof 2. Reference structures and supervision 2.1. Guarantor of the Code of Ethics 2.2. Code Promotion Team 3. Code review 4. Contractual value of the Code E - 14 FOREWORD Eni1 is an internationally oriented industrial group which, because of its size and the importance of its activities, plays a significant role in the marketplace and in the economic development and welfare of the individuals who work or collaborate with Eni and of the communities where it is present. The complexity of the situations in which Eni operates, the challenges of sustainable development and the need to take into consideration the interests of all people having a legitimate interest in the corporate business (“Stakeholders”), strengthen the importance to clearly define the values that Eni accepts, acknowledges and shares as well as the responsibilities it assumes, contributing to a better future for everybody. For this reason the new Eni’s Code of Ethics (“Code” or “Code of Ethics”) has been devised. Compliance with the Code by Eni’s directors, statutory auditors, management and employees as well as by all those who operate in Italy and abroad for achieving Eni’s objectives (“Eni’s People”), each within their own functions and responsibilities, is of paramount importance – also pursuant to legal and contractual provisions governing the relationship with Eni – for Eni’s efficiency, reliability and reputation, which are all crucial factors for its success and for improving the social situation in which Eni operates. Eni undertakes to promote knowledge of the Code among Eni’s People and the other Stakeholders, and to accept their constructive contribution to the Code’s principles and contents. Eni undertakes to take into consideration any suggestions and remarks of Stakeholders, with the objective of confirming or integrating the Code. Eni carefully checks for compliance with the Code by providing suitable information, prevention and control tools and ensuring transparency in all transactions and behaviours by taking corrective measures if and as required. The Watch Structure of each Eni company performs the functions of guarantor of the Code of Ethics (“Guarantor”). The Code is brought to the attention of every person or body having business relations with Eni. (1) “Eni” means Eni SpA and its direct and indirect subsidiaries, in Italy and abroad. E - 15 I. GENERAL PRINCIPLES: SUSTAINABILITY AND CORPORATE RESPONSIBILITY Compliance with the law, regulations, statutory provisions, self-regulatory codes, ethical integrity and fairness, is a constant commitment and duty of all Eni’s People, and characterizes the conduct of Eni’s entire organization. Eni’s business and corporate activities has to be carried out in a transparent, honest and fair way, in good faith, and in full compliance with competition protection rules. Eni undertakes to maintain and strengthen a governance system in line with international best practice standards, able to deal with the complex situations in which Eni operates, and with the challenges to face for sustainable development. Systematic methods for involving Stakeholders are adopted, fostering dialogue on sustainability and corporate responsibility. In conducting both its activities as an international company and those with its partners, Eni stands up for the protection and promotion of human rights – inalienable and fundamental prerogatives of human beings and basis for the establishment of societies founded on principles of equality, solidarity, repudiation of war, and for the protection of civil and political rights, of social, economic and cultural rights and the so-called third generation rights (selfdetermination right, right to peace, right to development and protection of the environment). Any form of discrimination, corruption, forced or child labor is rejected. Particular attention is paid to the acknowledgement and safeguarding of the dignity, freedom and equality of human beings, to protection of labor and of the freedom of trade union association, of health, safety, the environment and biodiversity, as well as the set of values and principles concerning transparency, energy efficiency and sustainable development, in accordance with International Institutions and Conventions. In this respect Eni operates within the reference framework of the United Nations Universal Declaration of Human Rights, the Fundamental Conventions of the ILO – International Labor Organization – and the OECD Guidelines on Multinational Enterprises. All Eni’s People, without any distinction or exception whatsoever, respect the principles and contents of the Code in their actions and behaviours while performing their functions and according to their responsibilities, because compliance with the Code is fundamental for the quality of their working and professional performance. Relationships among Eni’s People, at all levels, must be characterized by honesty, fairness, cooperation, loyalty and mutual respect. The belief that one is acting in favor or to the advantage of Eni can never, in any way, justify – not even in part – any behaviours that conflict with the principles and contents of the Code. II. BEHAVIOUR RULES AND RELATIONS WITH STAKEHOLDERS 1. ETHICS, TRANSPARENCY, FAIRNESS, PROFESSIONALISM In conducting its business, Eni is inspired by and complies with the principles of loyalty, fairness, transparency, efficiency and an open market, regardless of the importance level of the transaction in question. Any action, transaction and negotiation performed and, generally, the conduct of Eni’s People in the performance of their duties is inspired by the highest principles of fairness, completeness and transparency of information and legitimacy, both in form and substance, as well as clarity and truthfulness of all accounting documents, in compliance with the applicable laws in force and internal regulations. All Eni’s activities have to be performed with the utmost care and professional skill, with the duty to provide skills and expertise adequate to the tasks assigned, and to act in a way capable to protect Eni’s image and reputation. Corporate objectives, as well as the proposal and implementation of projects, investments and actions, have to be aimed at improving the company’s assets, management, technological and information level in the long term, and at creating value and welfare for all Stakeholders. Bribes, illegitimate favours, collusion, requests for personal benefits for oneself or others, either directly or through third parties, are prohibited without any exception. It is prohibited to pay or offer, directly or indirectly, money and material benefits and other advantages of any kind to third parties, whether representatives of governments, public officers and public servants or private employees, in order to influence or remunerate the actions of their office. Commercial courtesy, such as small gifts or forms of hospitality, is only allowed when its value is small and it does not compromise the integrity and reputation of either party, and cannot be construed by an impartial observer as aimed at obtaining undue advantages. In any case, these expenses must always be authorized by the designated managers as per existing internal rules, and be accompanied by appropriate documentation. It is forbidden to accept money from individuals or companies that have or intend to have business relations with Eni. Anyone who receives proposals of gifts or special or hospitality treatment that cannot be considered as commercial courtesy of small value, or requests therefore by third parties, shall reject them and immediately inform their superior, or the body they belong to, as well as the Guarantor. Eni shall properly inform all third parties about the commitments and obligations provided for in the Code, require third parties to respect the principles of the Code relevant to their activities and take proper internal actions and, if the matter is within its own competence, external actions in the event that any third party should fail to comply with the Code. E - 16 2. RELATIONS WITH SHAREHOLDERS AND WITH THE MARKET 2.1.Value for shareholders, efficiency, transparency The internal structure of Eni and the relations with the parties directly and indirectly taking part in its activities are organized according to rules able to ensure management reliability and a fair balance between the management’s powers and the interests of shareholders and of the other Stakeholders in general as well as transparency and market traceability of management decisions and general corporate events which may considerably influence the market value of the financial instruments issued. Within the framework of the initiatives aimed at maximizing the value for shareholders and at guaranteeing transparency of the management’s work, Eni defines, implements and progressively adjusts a coordinated and homogeneous set of behaviour rules concerning both its internal organizational structure and relations with shareholders and third parties, in compliance with the highest corporate governance standards at national and international level, based on the awareness that the company’s capacity to impose efficient and effective functioning rules upon itself is a fundamental tool for strengthening its reputation in terms of reliability and transparency as well as Stakeholders’ trust. Eni deems it necessary that shareholders are enabled to participate in decisions which come within the limits of their competence and make informed choices. Therefore, Eni undertakes to ensure maximum transparency and timeliness of information communicated to shareholders and to the market – by means of the corporate internet site, too – in compliance with the laws and regulations applicable to listed companies. Moreover, Eni undertakes to keep in due consideration the legitimate remarks expressed by shareholders whenever they are entitled to do so. 2.2. Self-Regulatory Code The main corporate governance rules of Eni are contained in the Self-Regulatory Code of Eni SpA, adopted in compliance with the Code promoted by Borsa Italiana SpA, which is referred to herein as far as applicable. 2.3. Company information Eni ensures the correct management of company information, by means of suitable procedures for in-house management and communication to the outside. 2.4. Privileged information All Eni’s People are required, while performing the tasks entrusted to them, to properly manage privileged information such as to know and comply with corporate procedures referring to market abuse. Insider trading and any behaviour that may promote insider trading are expressly forbidden. In any case, the purchase or sale of shares of Eni or of companies outside Eni shall always be based on absolute and transparent fairness. 2.5. Media Eni undertakes to provide outside parties with true, prompt, transparent and accurate information. Relations with the media are exclusively dealt with by the departments and managers specifically appointed to do so; information to be supplied to media representatives, as well as the undertaking to provide such information, have to be agreed upon beforehand by Eni’s People with the relevant Eni Corporate structure. 3. RELATIONS WITH INSTITUTIONS, ASSOCIATIONS, LOCAL COMMUNITIES Eni encourages dialogue with Institutions and with organized associations of civil society in all the countries where it operates. 3.1. Authorities and Public Institutions Eni, through its People, actively and fully cooperates with Authorities. Eni’s People, as well as external collaborators whose actions may somehow be referred to Eni, must have behaviours towards the Public Administration characterized by fairness, transparency and traceability. These relations have to be exclusively dealt with by the departments and individuals specifically appointed to do so, in compliance with approved plans and corporate procedures. The departments of the subsidiaries concerned shall coordinate with the relevant Eni Corporate structure for assessing the quality of the interventions to be carried out and for the sharing, implementing and monitoring of their actions. It is forbidden to make, induce or encourage false statements to Authorities. 3.2. Political organizations and trade unions Eni does not make any direct or indirect contributions in whatever form to political parties, movements, committees, political organizations and trade unions, nor to their representatives and candidates, except those specifically contemplated by applicable laws and regulations. E - 17 3.3. Development of local Communities Eni is committed to actively contribute to promoting the quality of life, the socio-economic development of the communities where Eni operates and to the development of their human resources and capabilities, while conducting its business activities according to standards that are compatible with fair commercial practices. Eni’s activities are carried out in the awareness of the social responsibility that Eni has towards all of its Stakeholders and in particular the local communities in which it operates, in the belief that the capacity for dialogue and interaction with civil society constitutes an important asset for the company. Eni respects the cultural, economic and social rights of the local communities in which it operates and undertakes to contribute, as far as possible, to their exercise, with particular reference to the right to adequate nutrition, drinking water, the highest achievable level of physical and mental health, decent dwellings, education, abstaining from actions that may hinder or prevent the exercise of such rights. Eni promotes transparency of the information addressed to local communities, with particular reference to the topics that they are most interested in. Forms of continuous and informed consultancy are either promoted, through the relevant Eni structures, in order to take into due consideration the legitimate expectations of local communities in conceiving and conducting corporate activities and in order to promote a proper redistribution of the profits deriving from such activities. Eni, therefore, undertakes to promote the knowledge of its corporate values and principles, at every level of its organization, also through adequate control procedures, and to protect the rights of local communities, with particular reference to their culture, institutions, ties and life styles. Within the framework of their respective responsibilities, Eni’s People are required to participate in the definition of single initiatives in compliance with Eni’s policies and intervention programs, to implement them according to criteria of absolute transparency and support them as an integral part of Eni’s objectives. 3.4. Promotion of “non profit” activities The philanthropic activity of Eni is in line with its vision and attention to sustainable development. Therefore, Eni undertakes to foster and support, as well as to promote among its People, its “non profit” activities which demonstrate the company’s commitment to help meet the needs of those communities where it operates. 4. RELATIONS WITH CUSTOMERS AND SUPPLIERS 4.1. Customers and consumers Eni pursues its business success on markets by offering quality products and services under competitive conditions while respecting the rules protecting fair competition. Eni undertakes to respect the right of consumers not to receive products harmful to their health and physical integrity and to get complete information on the products offered to them. Eni acknowledges that the esteem of those requesting products or services is of primary importance for success in business. Business policies are aimed at ensuring the quality of goods and services, safety and compliance with the precautionary principle. Therefore, Eni’s People shall: • • • comply with in-house procedures concerning the management of relations with customers and consumers; supply, with efficiency and courtesy, within the limits set by the contractual conditions, high-quality products meeting the reasonable expectations and needs of customers and consumers; supply accurate and exhaustive information on products and services and be truthful in advertisements or other kind of communication, so that customers and consumers can make informed decisions. 4.2. Suppliers and external collaborators Eni undertakes to look for suppliers and external collaborators with suitable professionalism and committed to sharing the principles and contents of the Code and promotes the establishment of long-lasting relations for the progressive improvement of performances while protecting and promoting the principles and contents of the Code. In relationships regarding tenders, procurement and, generally, the supply of goods and/or services and of external collaborations (including consultants, agents, etc.), Eni’s People shall: • • • • follow internal procedures concerning selection and relations with suppliers and external collaborators and abstain from excluding any supplier meeting requirements from bidding for Eni’s orders; adopt appropriate and objective selection methods, based on established, transparent criteria; secure the cooperation of suppliers and external collaborators in guaranteeing the continuous satisfaction of Eni’s customers and consumers, to an extent adequate to that legitimately expected by them, in terms of quality, costs and delivery times; use as much as possible, in compliance with the laws in force and the criteria for legality of transactions with related parties, products and services supplied by Eni companies at arm’s length and market conditions; state in contracts the Code acknowledgement and the obligation to comply with the principles contained therein; comply with, and demand compliance with, the conditions contained in contracts; • • maintain a frank and open dialogue with suppliers and external collaborators in line with good commercial practice; promptly inform superiors, and the Guarantor, about any possible violations of the Code; E - 18 • inform the relevant Eni Corporate structure about any serious problems that may arise with a particular supplier or external collaborator, in order to evaluate possible consequences for Eni. The remuneration to be paid shall be exclusively proportionate to the services to be rendered and described in the contract and payments shall not be allowed to any party different from the contract party nor in a third Country different from the one of the parties or where the contract has to be performed. 5. ENI’S MANAGEMENT, EMPLOYEES, COLLABORATORS 5.1. Development and protection of Human Resources People are basic components in the company’s life. The dedication and professionalism of management and employees represent fundamental values and conditions for achieving Eni’s objectives. Eni is committed to developing the abilities and skills of management and employees so that their energy and creativity can have full expression for the fulfilment of their potential in their working performance, such as to protect working conditions as regards both mental and physical health and dignity. Undue pressure or discomfort is not allowed, while appropriate working conditions promoting development of personality and professionalism are fostered. Eni undertakes to offer, in full compliance with applicable legal and contractual provisions, equal opportunities to all its employees, making sure that each of them receives a fair statutory and wage treatment exclusively based on merit and expertise, without discrimination of any kind. Competent departments shall: • • • adopt in any situation criteria of merit and ability (and anyhow strictly professional) in all decisions concerning human resources; select, hire, train, compensate and manage human resources without discrimination of any kind; create a working environment where personal characteristics or beliefs do not give rise to discrimination and which allows the serenity of all Eni’s People. Eni wishes that Eni’s People, at every level, cooperate in maintaining a climate of common respect for a person’s dignity, honour and reputation. Eni shall do its best to prevent attitudes that can be considered as offensive, discriminatory or abusive. In this regard, any behaviours outside the working place which are particularly offensive to public sensitivity are also deemed relevant. In any case, any behaviours constituting physical or moral violence are forbidden without any exception. 5.2. Knowledge Management Eni promotes culture and the initiatives aimed at disseminating knowledge within its structures, and at pointing out the values, principles, behaviours and contributions in terms of innovation of professional families in connection with the development of business activities and to the company’s sustainable growth. Eni undertakes to offer tools for interaction among the members of professional families, working groups and communities of practice, as well as for coordination and access to know-how, and shall promote initiatives for the growth, dissemination and systematization of knowledge relating to the core competences of its structures and aimed at defining a reference framework suitable for guaranteeing operating consistency. All Eni’s People shall actively contribute to Knowledge Management as regards the activities that they are in charge of, in order to optimize the system for knowledge sharing and distribution among individuals. 5.3. Corporate security Eni engages in the study, development and implementation of strategies, policies and operational plans aimed at preventing and overcoming any intentional or non-intentional behaviour which may cause direct or indirect damage to Eni’s People and/or to the tangible and intangible resources of the company. Preventive and defensive measures, aimed at minimizing the need for an active response – always in proportion to the attack – to threats to people and assets, are favored. All Eni’s People shall actively contribute to maintaining an optimal corporate security standard, abstaining from unlawful or dangerous behaviours, and reporting any possible activities carried out by third parties to the detriment of Eni’s assets or human resources to superiors or to the body they belong to, as well as to the relevant Eni Corporate structure. In any case requiring particular attention to personal safety, it is compulsory to strictly follow the indications in this regard supplied by Eni, abstaining from behaviours which may endanger one’s own safety or the safety of others, promptly reporting any danger for one’s own safety, or the safety of third parties, to one’s superior. 5.4. Harassment or mobbing in the workplace Eni supports any initiatives aimed at implementing working methods for the achievement of a better organization. Eni demands that there shall be no harassment or mobbing behaviours in personal working relationships either inside or outside the company. Such behaviours are all forbidden, without exceptions, and are: • • • the creation of an intimidating, hostile, isolating or in any case discriminatory environment for individual employees or groups of employees; unjustified interference in the work performed by others; the placing of obstacles in the way of the work prospects and expectations of others merely for reasons of personal competitiveness or because of other employees. E - 19 Any form of violence or harassment, either sexual harassment or harassment based on personal and cultural diversity, is forbidden. Such harassment is for instance: • • • • subordinating decisions on someone’s working life to the acceptance of sexual attentions, or personal and cultural diversity; obtaining sexual attentions using the influence of one’s role; proposing private interpersonal relations despite the recipient’s explicit or reasonably clear distaste; alluding to disabilities and physical or psychic impairment, or to forms of cultural, religious or sexual diversity. 5.5. Abuse of alcohol or drugs and no smoking All Eni’s People shall personally contribute to promoting and maintaining a climate of common respect in the workplace; particular attention is paid to respect of the feelings of others. Eni will therefore consider individuals who work under the effect of alcohol or drugs, or substances with similar effect, during the performance of their work activities and in the workplace, as being aware of the risk they cause. Chronic addiction to such substances, when it affects work performance, shall be considered similar to the above mentioned events in terms of contractual consequences; Eni is committed to favour social action in this field as provided for by employment contracts. It is forbidden to: • • hold, consume, offer or give for whatever reason, drugs or substances with similar effect, at work and in the workplace; smoke in the workplace. Eni supports voluntary initiatives addressed to People to help them quit smoking and, in identifying possible smoking areas, shall take into particular consideration the condition of those suffering physical discomfort from exposure to smoke in the workplace shared with smokers and requesting to be protected from “passive smoking” in their place of work. III. TOOLS FOR IMPLEMENTING THE CODE OF ETHICS 1. SYSTEM OF INTERNAL CONTROL Eni undertakes to promote and maintain an adequate system of internal control, i.e. all the necessary or useful tools for addressing, managing and checking activities in the company, aimed at ensuring compliance with corporate laws and procedures, at protecting corporate assets, efficiently managing activities and providing precise and complete accounting and financial information. The responsibility for implementing an effective system of internal control is shared at every level of Eni’s organizational structure; therefore, all Eni’s People, according to their functions and responsibilities, shall define and actively participate in the correct functioning of the system of internal control. Eni promotes the dissemination, at every level of its organization, of policies and procedures characterized by awareness of the existence of controls and by an informed and voluntary control oriented mentality; consequently, Eni’s management in the first place and all Eni’s People in any case shall contribute to and participate in Eni’s system of internal control and, with a positive attitude, involve its collaborators in this respect. Each employee shall be held responsible for the corporate tangible and intangible assets relevant to his/her job. No employee can make, or let others make, improper use of assets and equipment belonging to Eni. Any practices and attitudes linked to the perpetration or to the participation in the perpetration of frauds are forbidden without any exception. Control and supervisory bodies, Eni Internal Audit department and appointed auditing companies shall have full access to all data, documents and information necessary to perform their own relevant activities. 1.1. Conflicts of interest Eni acknowledges and respects the right of its People to take part in investments, business and other kinds of activities other than the activity performed in the interest of Eni, provided that such activities are permitted by law and are compatible with the obligations assumed towards Eni. The Self-Regulatory Code of Eni SpA governs any possible conflict of interest of directors and statutory auditors of Eni SpA. Eni’s management and employees shall avoid and report any conflicts of interest between personal and family economic activities and their tasks within the company. In particular, everyone shall point out any specific situations and activities of economic or financial interest (owner or member) to them or, as far as they know, of economic or financial interest to relatives of theirs or relatives by marriage within the 2nd degree of kinship, or to persons actually living with them, also involving suppliers, customers, competitors, third parties, or the relevant controlling companies or subsidiaries, and shall point whether they perform corporate administration or control or management functions therein. Moreover, conflicts of interest are determined by the following situations: • use of one’s position in the company, or of information, or of business opportunities acquired during one’s work, to one’s undue benefit or to the undue benefit of third parties; E - 20 • the performing of any type of work for suppliers, sub-suppliers and competitors by employees and/or their relatives. In any case, Eni’s management and employees shall avoid any situation and activity where a conflict with the Company’s interests may arise, or which can interfere with their ability to make impartial decisions in the best interests of Eni and in full accordance with the principles and contents of the Code, or in general with their ability to fully comply with their functions and responsibilities. Any situation that may constitute or give rise to a conflict of interest shall be immediately reported to one’s superior within management, or to the body one belongs to, and to the Guarantor. Furthermore, the party concerned shall abstain from taking part in the operational/decision-making process, and the relevant superior within management, or the relevant body, shall: • • • identify the operational solutions suitable for ensuring, in the specific case, transparency and fairness of behaviours in the performance of activities; transmit to the parties concerned – and for information to one’s superior, as well as to the Guarantor – the necessary written instructions; file the received and transmitted documentation. 1.2. Transparency of accounting records Accounting transparency is grounded on the use of true, accurate and complete information which form the basis for the entries in the books of accounts. Each member of company bodies, of management or employee shall cooperate, within their own field of competence, in order to have operational events properly and timely registered in the books of accounts. It is forbidden to behave in a way that may adversely affect transparency and traceability of the information within financial statements. For each transaction, the proper supporting evidence has to be maintained in order to allow: easy and punctual accounting entries; • identification of different levels of responsibility, as well as of task distribution and segregation; • • accurate representation of the transaction so as to avoid the probability of any material or interpretative error. Each record shall reflect exactly what is shown by the supporting evidence. All Eni’s People shall cause that the documentation can be easily traced and filed according to logical criteria. Eni’s People who become aware of any omissions, forgery, negligence in accounting or in the documents on which accounting is based, shall bring the facts to the attention of their superior, or to the body they belong to, and to the Guarantor. 2. HEALTH, SAFETY, ENVIRONMENT AND PUBLIC SAFETY PROTECTION Eni’s activities shall be carried out in compliance with applicable worker health and safety, environmental and public safety protection agreements, international standards and laws, regulations, administrative practices and national policies of the Countries where it operates. Eni actively contributes as appropriate to the promotion of scientific and technological development aimed at protecting the environment and natural resources. The operative management of such activities shall be carried out according to advanced criteria for the protection of the environment and energy efficiency, with the aim of creating better working conditions and protecting the health and safety of employees as well as the environment. Eni’s People shall, within their areas of responsibility, actively participate in the process of risk prevention as well as environmental, public safety and health protection for themselves, their colleagues and third parties. 3. RESEARCH, INNOVATION AND INTELLECTUAL PROPERTY PROTECTION Eni promotes research and innovation activities by management and employees, within their functions and responsibilities. Any intellectual assets generated by such activities are an important and fundamental heritage of Eni. Research and innovation focus in particular on the promotion of products, tools, processes and behaviours supporting energy efficiency, reduction of environmental impact, attention to health and safety of employees, of customers and of the local communities where Eni operates, and in general sustainability of business activities. Eni’s People shall actively contribute, within their functions and responsibilities, to managing intellectual property in order to allow its development, protection and enhancement. 4. CONFIDENTIALITY 4.1. Protection of business secret Eni’s activities constantly require the acquisition, storing, processing, communication and dissemination of information, documents and other data regarding negotiations, administrative proceedings, financial transactions, and know-how (contracts, deeds, reports, notes, studies, drawings, pictures, software, etc.) that may not be disclosed to the E - 21 outside pursuant to contractual agreements, or whose inopportune or untimely disclosure may be detrimental to corporate interest. Without prejudice to the transparency of the activities carried out and to the information obligations imposed by the provisions in force, Eni’s People shall ensure the confidentiality required by the circumstances for each piece of news they have got to know of because of their working function. Any information, knowledge and data acquired or processed during one’s work or because of one’s tasks at Eni, belong to Eni and may not be used, communicated or disclosed without specific authorization of one’s superior within management in compliance with specific procedures. 4.2. Protection of privacy Eni is committed to protecting information concerning its People and third parties, whether generated or obtained inside Eni or in the conduct of Eni’s business, and to avoiding improper use of any such information. Eni intends to guarantee that processing of personal data within its structures respects fundamental rights and freedoms, as well as the dignity of the parties concerned, as contemplated by the legal provisions in force. Personal data must be processed in a lawful and fair way and, in any case, the data collected and stored is only that which is necessary for certain, explicit and lawful purposes. Data shall be stored for a period of time no longer than necessary for the purposes of collection. Eni undertakes moreover to adopt suitable preventive safety measures for all databases storing and keeping personal data, in order to avoid any risks of destruction and losses or of unauthorized access or unallowed processing. Eni’s People shall: • • • • obtain and process only data that are necessary and adequate to the aims of their work and responsibilities; obtain and process such data only within specified procedures, and store said data in a way that prevents unauthorized parties from having access to it; represent and order data in a way ensuring that any party with access authorization may easily get an outline thereof which is as accurate, exhausting and truthful as possible; disclose such data pursuant to specific procedures or subject to the express authorization by their superior and, in any case, only after having checked that such data may be disclosed, also making reference to absolute or relative constraints concerning third parties bound to Eni by a relation of whatever nature and, if applicable, after having obtained their consent. 4.3. Membership in associations, participation in initiatives, events or external meetings Membership in associations, participation in initiatives, events or external meetings is supported by Eni if compatible with the working or professional activity provided. Membership and participation considered as such are: drawing up of articles, papers and publications in general; participation in public events in general. • membership in associations, participation in conferences, workshops, seminars, courses; • • In this regard, Eni’s management and employees in charge of illustrating, or providing to the outside data or news concerning Eni’s objectives, aims, results and points of view, shall not only comply with corporate procedures relating to market abuse, but also obtain the necessary authorization from their superior within management for the lines of action to follow and the texts as well as reports drawn up, such as to agree on contents with the relevant Eni Corporate structure. IV. CODE OF ETHICS SCOPE OF APPLICATION AND REFERENCE STRUCTURES The principles and contents of the Code apply to Eni’s People and activities. Any listed subsidiaries and power & gas sector subsidiaries subject to unbundling shall receive the Code and adopt it, adjusting it – if necessary – to the characteristics of their company, consistently with their management independence. The representatives indicated by Eni in the company bodies of partially owned companies, in consortia and in joint ventures shall promote the principles and contents of the Code within their own respective areas of competence. Directors and management must be the first to give concrete form to the principles and contents of the Code, by assuming responsibility for them both towards the inside and the outside and by enhancing trust, cohesion and a sense of team-work, as well as providing a behaviour model for their collaborators in order to have them comply with the Code and make questions and suggestions on specific provisions. To achieve full compliance with the Code, each of Eni’s People may even apply directly to the Guarantor. 1. OBLIGATION TO KNOW THE CODE AND TO REPORT ANY POSSIBLE VIOLATION THEREOF Each of Eni’s People is expected to know the principles and contents of the Code as well as the reference procedures governing own functions and responsibilities. Each of Eni’s People shall: • refrain from all conduct contrary to such principles, contents and procedures; E - 22 • • • • carefully select, as long as within their field of competence, their collaborators, and have them fully comply with the Code; require any third parties having relations with Eni to confirm that they know the Code; immediately report to their superiors or the body they belong to, and to the Guarantor, any remarks of theirs or information supplied by Stakeholders concerning a possible violation or any request to violate the Code; reports of possible violations shall be sent in compliance with conditions provided for by the specific procedures established by the Board of Statutory Auditors and by the Watch Structure of Eni SpA; cooperate with the Guarantor and with the relevant departments according to the applicable specific procedures in ascertaining any violations; adopt prompt corrective measures whenever necessary, and in any case prevent any type of retaliation. • Eni’s People are not allowed to conduct personal investigations, nor to exchange information, except to their superiors, or to the body that they belong to, and to the Guarantor. If, after notifying a supposed violation any of Eni’s People feels that he or she has been subject to retaliation, then he or she may directly apply to the Guarantor. 2. REFERENCE STRUCTURES AND SUPERVISION Eni is committed to ensuring, even through the Guarantor’s appointment: • the widest dissemination of the principles and contents of the Code among Eni’s People and the other Stakeholders, providing any possible tools for understanding and clarifying the interpretation and the implementation of the Code, as well as for updating the Code as required to meet evolving civil sensibility and relevant laws; the execution of checks on any notice of violation of the Code principles and contents or of reference procedures; an objective evaluation of the facts and, if necessary, the adoption of appropriate sanctions; that no one may suffer any retaliation whatsoever for having provided information regarding possible violations of the Code or of reference procedures. • 2.1. Guarantor of the Code of Ethics The Code of Ethics is, among other things, a compulsory general principle of the Organizational, Management and Control Model adopted by Eni SpA according to the Italian provision on the “administrative liability of legal entities deriving from offences” contained in Legislative Decree No. 231 of June 8, 2001. Eni SpA assigns the functions of Guarantor to the Watch Structure established pursuant to the above mentioned Model. Each direct or indirect subsidiary, in Italy and abroad, entrusts the function of Guarantor to its own Watch Structure by formal deed of the relevant corporate body. The Guarantor is entrusted with the task of: • promoting the implementation of the Code and the issue of reference procedures; reporting and proposing to the CEO of the company the useful initiatives for a greater dissemination and knowledge of the Code, also in order to prevent any recurrences of violations; promoting specific communication and training programs for Eni’s management and employees; investigating reports of any violation of the Code by initiating proper inquiry procedures; taking action at the request of Eni’s People in the event of receiving reports that violations of the Code have not been properly dealt with or in the event of being informed of any retaliation against Eni’s people for having reported violations; notifying relevant structures of the results of investigations relevant to the adoption of possible penalties; informing the relevant line/area structures about the results of investigations relevant to the adoption of the necessary measures. • • • Moreover, the Guarantor of Eni SpA submits to the Internal Control Committee and to the Board of Statutory Auditors as well as to the Chairman and to the Chief Executive Officer, which report about it to the Board of Directors, a six-monthly report on the implementation and possible need for updating the Code. For the performance of its tasks, the Guarantor of Eni SpA avails itself of “Technical Secretariat of the Watch Structure 231 of Eni SpA” that reports thereto and is supported by the relevant Structures of Eni SpA. The Technical Secretariat is responsible for starting and maintaining an adequate reporting and communication flow to and from the Guarantors of subsidiaries. Each information flow is to be sent to the following email address: organismo_di_vigilanza@eni.it 2.2. Code Promotion Team The Code is made available to Eni’s People in compliance with applicable standards, and is also available on the internet and intranet sites of Eni SpA and of subsidiaries. In order to promote the knowledge and facilitate the implementation of the Code, a Code Promotion Team reporting to the Guarantor of Eni SpA has been established. The Team makes available within Eni all possible tools for understanding and clarifying the interpretation and the implementation of the Code. The members of the Team are chosen by the Chief Executive Officer of Eni SpA upon proposal of the Guarantor of Eni SpA. E - 23 3. CODE REVIEW The Code review is approved by the Board of Directors of Eni SpA, upon proposal of the Chief Executive Officer with the agreement of the Chairman, after hearing the opinion of the Board of Statutory Auditors. The proposal is made taking into consideration the Stakeholders’ evaluation with reference to the principles and contents of the Code, promoting active contribution and notification of possible deficiencies by Stakeholders themselves. 4. CONTRACTUAL VALUE OF THE CODE Respect of the Code’s rules is an essential part of the contractual obligations of all Eni’s People pursuant to and in accordance with applicable law. Any violation of the Code’s principles and contents may be considered as a violation of primary obligations under labour relations or of the rules of discipline and can entail the consequences provided for by law, including termination of the work contract and compensation for damages arising out of any violation. E - 24 Certifications as separate documents filed as exhibits I, Paolo Scaroni, certify that: 1. I have reviewed this annual report on Form 20-F of Eni SpA; Certification EXHIBIT 12.1 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: (a) (b) (c) (d) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: April 5, 2012 /s/PAOLO SCARONI Paolo Scaroni Title: Chief Executive Officer E - 25 I, Alessandro Bernini, certify that: 1. I have reviewed this annual report on Form 20-F of Eni SpA; Certification EXHIBIT 12.2 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: April 5, 2012 /s/ALESSANDRO BERNINI Alessandro Bernini Title: Chief Financial Officer E - 26 Certification Pursuant to 18 U.S.C. Section 1350 EXHIBIT 13.1 For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the “Company”), hereby certifies, to such officer’s knowledge, that: (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: April 5, 2012 The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act. /s/PAOLO SCARONI Paolo Scaroni Title: Chief Executive Officer E - 27 Certification Pursuant to 18 U.S.C. Section 1350 EXHIBIT 13.2 For purposes of 18 U.S.C. Section 1350, the undersigned officer of Eni SpA, a company incorporated under the laws of Italy (the “Company”), hereby certifies, to such officer’s knowledge, that: (i) the Annual Report on Form 20-F of the Company for the year ended December 31, 2011 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) as applicable, of the Securities Exchange Act of 1934; and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: April 5, 2012 The foregoing certification is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act. /s/ALESSANDRO BERNINI Alessandro Bernini Title: Chief Financial Officer E - 28 EXHIBIT 15.a(i) DEGOLYER AND MACNAUGHTON 5001 SPRING VALLEY ROAD SUITE 800 EAST DALLAS, TEXAS 75244 February 29, 2012 Eni S.p.A. E&P Division Ms. Manuela Feudaroli Vice President, Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Ms. Feudaroli: Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the net proved crude oil, condensate, and natural gas reserves, as of December 31, 2011, of certain properties in Europe and Asia owned by Eni S.p.A. (Eni). This evaluation was completed on February 29, 2012. Eni has represented that these properties account for 27.2 percent, on a net equivalent barrel basis, of Eni’s net proved reserves as of December 31, 2011, and that Eni’s net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Eni that it represents to be Eni’s estimates of the net reserves, as of December 31, 2011, for the same properties as those which we have independently evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Eni. Reserves included herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2011. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Eni after deducting interests owned by others. E - 29 DEGOLYER AND MACNAUGHTON 2 Estimates of oil, condensate, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Data used in this audit were obtained from reviews with Eni personnel, from Eni files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Eni with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of E - 30 DEGOLYER AND MACNAUGHTON 3 energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of production licenses as appropriate. Definition of Reserves Petroleum reserves included in this report are classified as proved. Reserves classifications used for our estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Eni has represented that its estimates of proved reserves are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using known production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: Proved oil and gas 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 E - 31 DEGOLYER AND MACNAUGHTON 4 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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. in included injection) are (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited the proved to, fluid classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable the technology establishes engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. reasonable certainty of the E - 32 DEGOLYER AND MACNAUGHTON 5 (v) 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. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) 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 (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – 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. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable for which an improved recovery application of fluid injection or other to any acreage E - 33 DEGOLYER AND MACNAUGHTON 6 technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. Primary Economic Assumptions The following economic assumptions were used for estimating existing and future prices and costs: Oil and Condensate Prices Eni has represented that the oil and condensate prices were based on a reference price, 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, unless prices are defined by contractual arrangements. A dated Brent oil price of 111 United States dollars (U.S.$) per barrel (U.S.$/bbl) was the resulting reference price. Where appropriate, Eni supplied differentials by field to the relevant reference price, and the prices were held constant thereafter. The volume-weighted average prices in this report were: Oil (U.S.$/bbl) Condensate (U.S.$/bbl) 107.06 79.29 99.13 63.78 49.59 53.97 Europe Asia Average for Total Natural Gas Prices Eni has represented that the natural gas prices were based on a reference price, 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, unless prices are defined by contractual arrangements. E - 34 DEGOLYER AND MACNAUGHTON 7 A significant quantity of the gas sold by Eni is subject to contract prices, and the range of such prices is varied. A reference price is the United Kingdom National Balancing Point Index, which was U.S.$9.19 per thousand cubic feet. Where appropriate, Eni supplied differentials by field to the relevant reference price and the prices were held constant thereafter. The volume-weighted average gas prices in this report were as follows, expressed in United States dollars per thousand cubic feet (U.S.$/Mcf): Gas (U.S.$/Mcf) 10.88 1.29 3.29 Europe Asia Average for Total Operating Expenses and Capital Costs Operating expenses and capital costs, based on information provided by Eni, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2011, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines. E - 35 DEGOLYER AND MACNAUGHTON 8 Eni has represented that its estimated net proved reserves attributable to the reviewed properties in Europe and Asia are based on the definitions of proved reserves of the SEC. Eni represents that its estimates of the net proved reserves attributable to these properties, which represent 27.2 percent of Eni’s reserves on a net equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe): Estimated by Eni Net Proved Reserves as of December 31, 2011 Oil (MMbbl) Condensate (MMbbl) Marketable Gas (Bcf) Oil Equivalent (MMboe) Properties reviewed by DeGolyer and MacNaughton Total Proved 705 183 5,778 1,929 Note: Gas is converted to oil equivalent using a factor of 5,550 cubic feet of gas per 1 barrel of oil equivalent. In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. In comparing the detailed net proved reserves estimates prepared by us and by Eni, we have found differences, both positive and negative, resulting in an aggregate difference of less than 5 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Eni on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us. E - 36 DEGOLYER AND MACNAUGHTON 9 DeGolyer and MacNaughton independent petroleum engineering is an consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Eni. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Eni. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/ DEGOLYER AND MACNAUGHTON DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 [SEAL] /s/ LLOYD W. CADE, P.E. Lloyd W. Cade, P.E. Senior Vice President DeGolyer and MacNaughton E - 37 DEGOLYER AND MACNAUGHTON CERTIFICATE of QUALIFICATION I, Lloyd W. Cade Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. 2. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Eni dated February 29, the 2012, and preparation of this report. that I, as Senior Vice President, was responsible for That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have approximately 29 years of experience in oil and gas reservoir studies and reserves evaluations. SIGNED: February 29, 2012 [SEAL] /s/ LLOYD W. CADE, P.E. Lloyd W. Cade, P.E. Senior Vice President DeGolyer and MacNaughton E - 38 EXHIBIT 15.a(ii) Eni S.p.A. Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests SEC Parameters As of December 31, 2011 /s/HERMAN G. ACUÑA, P.E. ———————————————————————————————— Herman G. Acuña, P.E. TBPE License No. 92254 Managing Senior Vice President – International RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580 [SEAL] RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 39 January 30, 2012 Eni S.p.A E&P Division Ms. Manuela Feudaroli Vice President Reserves Via Emilia 1 20097 San Donato Milanese Milano, Italy Dear Ms. Feudaroli: At the request of Eni S.p.A. (Eni), Ryder Scott Company (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as prepared by Eni’s engineering and geological staff as of December 31, 2011 based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 30, 2012 and presented herein, was prepared for public disclosure by Eni in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Eni has indicated that the proved net reserves attributable to the properties that we reviewed account for 4.5 percent of their total net proved remaining hydrocarbon reserves. The subject properties are located in the following geographic locations: • Africa • Asia • Australia and Oceania As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.” Based on our review, including the data, technical processes and interpretations presented by Eni, it is our opinion that the overall procedures and methodologies utilized by Eni in preparing their estimates of the proved reserves as of December 31, 2011 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Eni are, in the aggregate, reasonable within 5 percent of Ryder Scott’s estimates which is less than the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. The conclusions discussed in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790 621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258 E - 40 Eni S.p.A. – Third Party January 30, 2012 Page 2 the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities audited by Ryder Scott. Reserves Included in This Report In our opinion, the proved reserves discussed herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report. The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The audited proved gas volumes included gas consumed in operations as reserves. Non-hydrocarbon or inert gas volumes have been excluded from the reserves reported herein. Reserves are those estimated remaining quantities of petroleum that are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Eni’s request, this report addresses only the proved reserves attributable to the properties evaluated herein. 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.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production, unless RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 41 Eni S.p.A. – Third Party January 30, 2012 Page 3 evidence indicates that contract renewal is reasonably certain. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Eni for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Eni the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Eni’s representations regarding such contractual information should be construed as a legal opinion on this matter. Ryder Scott did not evaluate the country and geopolitical risks in the countries where Eni operates or has interests. Eni’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities. The estimates of proved reserves audited herein were based upon a detailed study of the properties in which Eni owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. Audit Data, Methodology, Procedure and Assumptions The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 42 Eni S.p.A. – Third Party January 30, 2012 Page 4 assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above. Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. The proved reserves for the properties included herein were estimated by performance methods, analogy methods, the volumetric method, or a combination of performance and volumetric methods. These performance methods include, but may not be limited to, decline curve analysis and analogy which utilized extrapolations of historical production and pressure data available through December 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were supplied to Ryder Scott by Eni and were considered sufficient for the purpose thereof. The volumetric method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The volumetric analysis utilized pertinent well and seismic data supplied to Ryder Scott by Eni that were available through December 2011. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Eni has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Eni with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 43 Eni S.p.A. – Third Party January 30, 2012 Page 5 verification of the data furnished by Eni. We consider the factual data used in this report appropriate and sufficient for the purpose of our investigations. In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to conduct the audit of reserves of the properties described herein. The proved reserves discussed herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves reviewed in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. Future Production Rates For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Eni. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described. Eni furnished us with the above mentioned average prices in effect on December 31, 2011. Eni has assured us that these initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 44 Eni S.p.A. – Third Party January 30, 2012 Page 6 are sold. The average dated Brent oil price of $111/Bbl was used by Eni. Eni also provided us with the gas prices based on their gas sales agreements. The average realized prices provided by Eni and used in our evaluation are as follows: Geographic Area Africa Asia Australia and Oceania Product Gas Condensate Gas Oil Condensate Oil Gas Condensate Average Realized Prices $81.99/Mm3 $72.37/Bbl $135.85/Mm3 $93.21/Bbl $94.73/Bbl $105.49/Bbl $265.32/Mm3 $93.69/Bbl The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Eni. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Eni to determine these differentials. Costs Operating costs used in our evaluation were based on the operating expense reports of Eni and include only those costs directly applicable to the evaluated assets. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Eni. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the assets. Development costs were furnished to us by Eni and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Eni were accepted without independent verification. The proved developed and undeveloped reserves in this report have been incorporated herein in accordance with Eni’s plans to develop these reserves as of December 31, 2011. The implementation of Eni’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Eni’s management. As the result of our inquires during the course of preparing this report, Eni has informed us that the development activities included herein have been subjected to and received the internal approvals required by Eni’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 45 Eni S.p.A. – Third Party January 30, 2012 Page 7 requirements or other administrative approvals external to Eni. Additionally, Eni has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans. Current costs used by Eni were held constant throughout the life of the properties. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee- owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education. Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. We are independent petroleum engineers with respect to Eni. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed. The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. Terms of Usage The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Eni. We have provided Eni with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Eni and the original signed report letter, the original signed report letter shall control and supersede the digital version. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 46 Eni S.p.A. – Third Party January 30, 2012 Page 8 The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L. P. TBPE Firm Registration No. F-1580 /s/HERMAN G. ACUNA, P.E. Herman G. Acuna, P.E. Texas P.E. License No. 92254 Managing Senior Vice President – International [SEAL] HGA(DPR)/pl RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 47 Professional Qualifications Herman G. Acuña The conclusions presented in this report for Eni properties located in Africa, Asia, Australia and Ocenia are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Herman G. Acuña was the primary technical person responsible for overseeing the independent estimation of the reserves, future production and income to render the audit conclusions of the report. Mr. Acuña, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1997, is a Managing Senior International Vice President and serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Acuña served in a number of engineering positions with Exxon. For more information regarding Mr. Acuña’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com. Mr. Acuña earned a Bachelor (Cum Laude) and a Masters (Magna Cum Laude) of Science degree in Petroleum Engineering from The University of Tulsa in 1987 and 1989 respectively. He is a registered Professional Engineer in the State of Texas, a member of the Association of International Petroleum Negotiators (AIPN) and the Society of Petroleum Engineers (SPE). In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Acuña fulfills. Mr. Acuña has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Acuña has recently taught various company reserves evaluation schools in Argentina, Bolivia, China, Denmark, Spain, U.S.A and Venezuela. Mr. Acuña has participated in various capacities in reserves conferences such as being a panelist a the 2008 Trinidad and Tobago’s Petroleum Conference, delivering the reserves evaluation seminar during IAPG convention in Mendoza, Argentina in 2006 and chairing the first Reserves Evaluation Conference in the Middle East in Dubai, U.A.E in 2006. Based on his educational background, professional training and over 20 years of practical experience in petroleum engineering and the estimation and evaluation of petroleum reserves, Mr. Acuña has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 48 PETROLEUM RESERVES DEFINITIONS As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) PREAMBLE On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC Regulations”. The SEC Regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions, as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the original document (direct passages excerpted from the aforementioned SEC document are denoted in italics herein). Reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC Regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the Commission. The SEC Regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the Commission unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 49 PETROLEUM RESERVES DEFINITIONS Page 2 These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. Reserves do not include quantities of petroleum being held in inventory. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows: 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. Note to paragraph (a) (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows: Proved oil and gas 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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 50 PETROLEUM RESERVES DEFINITIONS Page 3 (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. PROVED RESERVES (SEC DEFINITIONS) CONTINUED (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) 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. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 51 RESERVES STATUS DEFINITIONS AND GUIDELINES As Adapted From: RULE 4-10(a) of REGULATION S-X PART 210 UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) Sponsored and Approved by: SOCIETY OF PETROLEUM ENGINEERS (SPE), WORLD PETROLEUM COUNCIL (WPC) AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4- 10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). DEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) 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 (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions) While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 52 RESERVES STATUS DEFINITIONS AND GUIDELINES Page 2 Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves. Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate but which have not yet started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. UNDEVELOPED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: 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. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS E - 53 (This page intentionally left blank) Sovracop20F_Eni_2011 4/12/12 10:42 AM Pagina 1 Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2011: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1 Internet Home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary BNY Mellon Shareowner Services PO Box 358516 Pittsburgh, PA 15252-8516 shrrelations@bnymellon.com Contacts: - Institutional Investors/Broker Desk: UK: Mark Lewis - Tel. +44 (0) 20 7964 6089; mark.lewis@bnymellon.com USA: Ravi Davis - Tel. +1 212 815 4245; ravi.davis@bnymellon.com Hong Kong: Joe Oakenfold - Tel. +852 2840 9717; joe.oakenfold@bnymellon.com - Retail Investors: Domestic Toll Free – Tel. 1-866-433-0354 International Callers – Tel. +1.201.680.6825 Cover: Inarea - Rome - Italy Layout and supervision: Studio Joly Srl - Rome - Italy Printing: Primaprint Srl - Viterbo - Italy eni.com A n n u a l R e p o r t o n F o r m 2 0 - F 2 0 1 1 A n n u a l Re p o r t o n Fo r m 2 0 - F 2 0 1 1 Sovracop20F_Eni_2011 4/12/12 10:42 AM Pagina 1 Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2011: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1 Internet Home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary BNY Mellon Shareowner Services PO Box 358516 Pittsburgh, PA 15252-8516 shrrelations@bnymellon.com Contacts: - Institutional Investors/Broker Desk: UK: Mark Lewis - Tel. +44 (0) 20 7964 6089; mark.lewis@bnymellon.com USA: Ravi Davis - Tel. +1 212 815 4245; ravi.davis@bnymellon.com Hong Kong: Joe Oakenfold - Tel. +852 2840 9717; joe.oakenfold@bnymellon.com - Retail Investors: Domestic Toll Free – Tel. 1-866-433-0354 International Callers – Tel. +1.201.680.6825 Cover: Inarea - Rome - Italy Layout and supervision: Studio Joly Srl - Rome - Italy Printing: Primaprint Srl - Viterbo - Italy eni.com A n n u a l R e p o r t o n F o r m 2 0 - F 2 0 1 1 A n n u a l Re p o r t o n Fo r m 2 0 - F 2 0 1 1

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