UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549
————————————————————
Form 20-F

(Mark One)

 

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

OR

  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 200
7

OR

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

OR

  SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report

Commission file number: 1-14090
Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei
00144 Roma
Italy

(Address of principal executive offices)
Marco Mangiagalli
Eni SpA
1, piazza Ezio Vanoni
San Donato Milanese
20097 Milano
Italy
Tel +39 02 52041730
Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
————————————————————
Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class

  

Name of each exchange on which registered

Shares
American Depositary Shares

  

New York Stock Exchange*
New York Stock Exchange

(Which represent the right to receive two Shares)

   * Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes 

   

 No 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes 

   

 No 

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes 

   

 No 

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer

Accelerated filer

Non-accelerated filer

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP

International Financial Reporting Standards as issued by the International Accounting Standards Board

Other

If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17

   

 Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes 

   

 No 


TABLE OF CONTENTS
    Page
     
Certain Defined Terms   iii
Presentation of Financial and Other Information   iii
Statements Regarding Competitive Position   iv
Glossary   v
Abbreviations and Conversion Table   viii
         
PART I        
Item 1.   IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS   1
Item 2.   OFFER STATISTICS AND EXPECTED TIMETABLE   1
Item 3.   KEY INFORMATION   1
    Selected Financial Information   1
    Selected Operating Information   3
    Exchange Rates   5
    Risk Factors   5
Item 4.   INFORMATION ON THE COMPANY   16
    History and Development of the Company   16
    Business Overview   20
    Exploration & Production   20
    Gas & Power   43
    Refining & Marketing   52
    Petrochemicals   59
    Engineering & Construction   61
    Corporate and other activities   64
    Research and Development   64
    Insurance   65
    Environmental Matters   65
    Regulation of Eni’s Businesses   68
    Property, Plant and Equipment   77
    Organizational Structure   77
Item 4A.   UNRESOLVED STAFF COMMENTS   77
Item 5.   OPERATING AND FINANCIAL REVIEW AND PROSPECTS   77
    Executive Summary   77
    Critical Accounting Estimates   80
    2005-2007 Group Results of Operations   83
    Liquidity and Capital Resources   92
    Recent Developments   98
    Management's Expectations of Operations   100
Item 6.   DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES   103
    Directors and Senior Management   103
    Board Practices   107
    Compensation   117
    Employees   124
    Share Ownership   125
Item 7.   MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS   126
    Major Shareholders   126
    Related Party Transactions   126
Item 8.   FINANCIAL INFORMATION   126
    Consolidated Statements and Other Financial Information   126
    Significant Changes   135
Item 9.   THE OFFER AND THE LISTING   136
    Offer and Listing Details   136
    Markets   137
Item 10.   ADDITIONAL INFORMATION   138
    Memorandum and Articles of Association   138
    Material Contracts   145
    Documents on Display   145
    Exchange Controls   145
    Taxation   146

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Table of Contents

 

Item 11.   QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK   149
Item 12.   DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES   149
         
PART II        
Item 13.   DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES   150
Item 14.   MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS   150
Item 15.   CONTROLS AND PROCEDURES   150
Item 16.        
16A.   Board of Statutory Auditors Financial Expert   151
16B.   Code of Ethics   151
16C.   Principal Accountant Fees and Services   151
16D.   Exemptions from the Listing Standards for Audit Committees   152
16E.   Purchases of Equity Securities by the Issuer and Affiliated Purchasers   152
         
PART III        
Item 17.   FINANCIAL STATEMENTS   154
Item 18.   FINANCIAL STATEMENTS   154
Item 19.   EXHIBITS   154

 

 

 

 

 

 

ii


Table of Contents

Certain disclosures contained herein including, without limitation, information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", “Item 5 – Operating and Financial Review and Prospects” and "Item 11 – Qualitative and Quantitative 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 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) and IFRS issued by the IASB as adopted by the European Union following the procedure contained in Article 6 of the EC Regulation No. 1606/2002 of the European Parliament and Council of July 19, 2002.

Unless otherwise indicated, any reference herein to "Consolidated Financial Statements" is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.

Unless otherwise specified or the context otherwise requires, references herein to "dollars", "$", "U.S. dollars" and "U.S. $" are to the currency of the United States, and references to "euro" and "€" are to the currency of the European Monetary Union.

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Table of Contents

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

iv


Table of Contents

GLOSSARY

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

 

Financial terms

   
     
Leverage   A non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’equity, including minority interest. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
     
Net borrowings   Eni evaluates its financial condition by reference to "net borrowings", which is a non-GAAP measure. Eni calculates net borrowings as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure which in the case of the Company refers to IFRS, see "Item 5 – Financial Condition".
     
TSR (Total Shareholder Return)   Management uses this measure to asses the total return of the Eni share. It is calculated on a yearly basis, keeping account of changes in prices (beginning and end of year) and dividends distributed and reinvested at the ex-dividend date.
     

Business terms

   
     
Associated gas   Natural gas, occurring in the form of a gas cap, overlying an oil zone, contained in the reservoir’s crude oil gas.
     
Average reserve life index   Ratio between the amount of reserves at the end of the year and total production for the year.
     
Barrel/BBL   Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
     
BOE   Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see "Conversion Table").
     
Concession contracts   Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.
     
Condensates   These are light hydrocarbons produced along with gas that condense to a liquid state at surface temperature and pressure.
     
Conversion capacity   Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.
     
Conversion index   Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
     
Deep waters   Waters deeper than 200 meters.
     
Development   Drilling and other post-exploration activities aimed at the production of oil and gas.

v


Table of Contents

 

Enhanced recovery   Techniques used to increase or stretch over time the production of wells.
     
EPC   Engineering, Procurement and Construction.
     
EPIC   Engineering, Procurement, Installation and Construction.
     
Exploration   Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
     
FPSO   Floating Production Storage and Offloading System.
     
FSO   Floating Storage and Offloading System.
     
Infilling wells   Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
     
LNG   Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
     
LPG   Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
     
Margin   The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
     
Mineral Storage   According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
     
Modulation Storage   According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
     
Natural gas liquids (NGL)   Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
     
Network Code   A code containing norms and regulations for access to, management and operation of natural gas pipelines.
     
Over/Under lifting   Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.
     
Primary balanced refining capacity   Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
     
Production Sharing Agreement ("PSA")   Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "cost oil" is used to recover costs borne by the contractor and "profit oil" is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.

 

vi


Table of Contents
Proved reserves   Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of the impact of changes in existing prices on existing contractual arrangements, but not on escalations based upon future conditions. Proved reserves include: (i) proved developed reserves: amounts of hydrocarbons that are expected to be retrieved through existing wells, facilities and operating methods; and (ii) non-developed proved reserves: amounts of hydrocarbons that are expected to be retrieved following new drilling, facilities and operating methods. Based on these amounts the company has already defined a clear development expenditure program which is an expression of the company’s determination to develop existing reserves.
     
Reserve life index   Ratio between the amount of proved reserves at the end of the year and total production for the year.
     
Reserve replacement ratio   Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
     
Ship-or-pay   Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
     
Strategic Storage   According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
     
Take-or-pay   Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
     
Upstream/Downstream   The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.

 

vii


Table of Contents

ABBREVIATIONS

mmCF = million cubic feet   KBBL = thousand barrels
             
BCF = billion cubic feet   mmBBL = million barrels
             
mmCM = million cubic meters   BBBL = billion barrels
             
BCM = billion cubic meters   ktonnes = thousand tonnes
             
BOE = barrel of oil equivalent   mmtonnes = million tonnes
             
KBOE = thousand barrel of oil equivalent   GWh = gigawatthour
             
mmBOE = million barrel of oil equivalent   TWh = terawatthour
             
BBOE = billion barrel of oil equivalent   /d = per day
             
BBL = barrels   /y = per year

 

CONVERSION TABLE

1 acre

=

0.405 hectares    
         
1 barrel

=

42 U.S. gallons    
         
1 BOE

=

1 barrel of crude oil

=

5,742 cubic feet of natural gas
         
1 barrel of crude oil per day

=

approximately 50 tonnes of crude oil per year    
         
1 cubic meter of natural gas

=

35.3147 cubic feet of natural gas    
         
1 cubic meter of natural gas

=

approximately 0.00615 barrels of oil equivalent    
         
1 kilometer

=

approximately 0.62 miles    
         
1 short ton

=

0.907 tonnes

=

2,000 pounds
         
1 long ton

=

1.016 tonnes

=

2,240 pounds
         
1 tonne

=

1 metric ton

=

1,000 kilograms
     

=

approximately 2,205 pounds
         
1 tonne of crude oil

=

1 metric ton of crude oil

=

approximately 7.3 barrels of crude oil (assuming an API gravity of 34 degrees)

viii


Table of Contents

PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

 

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

 

 

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB) and IFRS issued by the IASB as adopted by the European Union. The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2004, 2005, 2006 and 2007. The selected historical financial data for the years ended December 31, 2004, 2005, 2006 and 2007 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 herein.

 

Year ended December 31,

 
 

2003 (1)

 

2004

 

2005

 

2006

 

2007

 
 
 
 
 
  (million euro except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA                        
Net sales from operations   57,545     73,728     86,105     87,256  
Operating profit by segment                        
     Exploration & Production   8,185     12,592     15,580     13,788  
     Gas & Power   3,428     3,321     3,802     4,127  
     Refining & Marketing   1,080     1,857     319     729  
     Petrochemicals   320     202     172     74  
     Engineering & Construction   203     307     505     837  
     Other activities   (395 )   (934 )   (622 )   (444 )
     Corporate and financial companies   (363 )   (377 )   (296 )   (217 )
     Impact of unrealized intragroup profit elimination   (59 )   (141 )   (133 )   (26 )
Operating profit   12,399     16,827     19,327     18,868  
Net profit attributable to Eni   7,059     8,788     9,217     10,011  
Data per ordinary share (euro) (2)                        
Operating profit:                        
- basic   3.29     4.48     5.23     5.14  
- diluted   3.28     4.47     5.22     5.14  
Net profit attributable to Eni basic and diluted   1.87     2.34     2.49     2.73  
Data per ADR ($) (2) (3)                        
Operating profit:                        
- basic   8.18     11.14     13.13     14.10  
- diluted   8.17     11.12     13.12     14.10  
Net profit attributable to Eni basic and diluted   4.66     5.82     6.26     7.48  
 
 
 
 
 

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Table of Contents

 

 

As of December 31,

 
 

2003 (1)

 

2004

 

2005

 

2006

 

2007

 
 
 
 
 
  (million euro except number of shares and dividend information)
CONSOLIDATED BALANCE SHEET DATA                    
Total assets       72,853   83,850   88,312   101,460
Short-term and long-term debt       12,684   12,998   11,699   19,830
Capital stock issued       4,004   4,005   4,005   4,005
Minority interest       3,166   2,349   2,170   2,439
Shareholders’ equity - Eni share       32,374   36,868   39,029   40,428
Capital expenditures       7,499   7,414   7,833   10,593
Weighted average number of ordinary shares outstanding (fully diluted - shares million)   3,778   3,775   3,763   3,701   3,669
Dividend per share (euro)   0.75   0.90   1.10   1.25   1.30
Dividend per ADR ($) (2)   1.83   2.17   2.73   3.24   3.74
 
 
 
 
 

(1)   Until December 31, 2004, Eni prepared its Consolidated Financial Statements and other interim financial information (including quarterly and semi-annual data) in accordance with Italian GAAP. IFRS required adopting companies to restate only one year of financial statements prepared under previous GAAP. Accordingly, selected IFRS financial information has not been published for the year ended December 31, 2003.
(2)   Euro per Share or dollars per American Depositary Receipt (ADR), as the case may be. From 2006, one ADR represents two Eni shares. Previously, one ADR was equivalent to five Eni shares. Data per ADR for 2003-2005 have been recalculated accordingly.
(3)   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 for each year presented (see the table on page 5). Dividends per ADR for the years 2003 through 2006 have been translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, recorded on payment of the interim dividend and the balance to the full-year dividend, respectively. Eni started to pay an interim dividend in 2005. The dividend for 2007 was converted at the Noon Buying Rate of the interim dividend (euro 0.60 per share) payment date which occurred on October 25, 2007. The balance of euro 0.70 per share payable on May 22, 2008 was translated at the Noon Buying Rate of December 31, 2007. On May 14, 2008, the Noon Buying Rate was $1.55 per euro 1.00.

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Table of Contents

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, 2003, 2004, 2005, 2006 and 2007. 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 or cost method of accounting.

 

Year ended December 31,

 
 

2003

 

2004

 

2005

 

2006

 

2007

 
 
 
 
 
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)  

4,138

 

3,972

 

3,748

 

3,457

 

3,127

of which developed  

2,447

 

2,471

 

2,331

 

2,126

 

1,953

Proved reserves of liquids of equity-accounted entities at period end (mmBBL)      

36

 

25

 

24

 

142

of which developed          

19

 

18

 

26

Proved reserves of natural gas of consolidated subsidiaries at period end (BCF)  

18,008

 

18,278

 

17,501

 

16,897

 

16,549

of which developed   10,224  

10,501

 

11,159

 

10,949

 

10,967

Proved reserves of natural gas of equity-accounted entities at period end (BCF)      

157

 

90

 

68

 

3,022

of which developed          

70

 

48

 

428

Proved reserves of hydrocarbons of consolidated subsidiaries in mmBOE at period end (1)  

7,272

 

7,154

 

6,796

 

6,400

 

6,010

of which developed  

4,230

 

4,300

 

4,275

 

4,032

 

3,862

Proved reserves of hydrocarbons of equity-accounted entities in mmBOE at period end (a)      

64

 

41

 

36

 

668

of which developed          

31

 

27

 

101

Reserve replacement ratio (2)  

142

 

91

 

43

 

38

 

38

Average daily production of liquids (KBBL/d)  

981

 

1,034

 

1,111

 

1,079

 

1,020

Average daily production of natural gas available for sale (mmCF/d) (3)  

3,174

 

3,171

 

3,344

 

3,679

 

3,819

Average daily production of hydrocarbons available for sale (KBOE/d) (3)  

1,536

 

1,586

 

1,693

 

1,720

 

1,684

Hydrocarbon production sold (mmBOE)  

556.2

 

576.5

 

614.9

 

625.1

 

611.4

Oil and gas production costs per BOE (4)          

5.59

 

5.79

 

6.90

Profit per barrel of oil equivalent (5)          

12.20

 

14.97

 

14.03

 
 
 
 
 

(a)    Mainly refers to Eni’s share of proved reserves relating to three Russian companies purchased by Eni as part of a bid procedure for assets of bankrupt Yukos (Eni’s share was 60%). Gazprom was granted an option to acquire a 51% interest in these three entities. Should Gazprom exercise its call option, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%.
(1)    Includes approximately 747, 737, 760, 754 and 749 BCF of natural gas held in storage in Italy at December 31, 2003, 2004, 2005, 2006 and 2007, respectively. See "Item 4 – Information on the Company – Exploration & Production – Storage".
(2)    Consists of: (i) the increase in proved reserves of consolidated subsidiaries 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 SFAS 69. See the unaudited supplemental oil and gas information in Notes 39 to the Consolidated Financial Statements. Expressed as a percentage.
(3)    Natural gas production volumes exclude gas consumed in operations (151, 220, 251, 286 and 296 mmCF/d in 2003, 2004, 2005, 2006 and 2007, respectively).
(4)    Consists of production costs (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by actual production net of production volumes of natural gas consumed in operations. See the unaudited supplemental oil and gas information in Notes 39 to the Consolidated Financial Statements. Expressed in dollars. Data for the years prior to 2005 are not available as they were prepared in accordance with U.S. GAAP.
(5)    Results of operations from oil and gas producing activities, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations. See the unaudited supplemental oil and gas information in Notes 39 to the Consolidated Financial Statements for a calculation of results of operations from oil and gas producing activities. Expressed in dollars. Data for the years prior to 2005 are not available as they were in accordance with U.S. GAAP.

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Selected Operating Information continued

 

Year ended December 31,

 
 

2003

 

2004

 

2005

 

2006

 

2007

 
 
 
 
 
Sales of natural gas to third parties (6)  

69.49

 

72.79

 

77.08

 

79.63

 

78.75

Natural gas consumed by Eni (6)  

1.90

 

3.70

 

5.54

 

6.13

 

6.08

Sales of natural gas of affiliates (Eni’s share) (6)  

6.94

 

5.84

 

7.08

 

7.65

 

8.74

Total sales and own consumption of natural gas of the Gas & Power segment (6)  

78.33

 

82.33

 

89.70

 

93.41

 

93.57

E&P natural gas sales in Europe and in the Gulf of Mexico (7)  

5.03

 

4.70

 

4.51

 

4.69

 

5.39

Worldwide natural gas sales  

83.36

 

87.03

 

94.21

 

98.10

 

98.96

Transport of natural gas for third parties in Italy (6)  

24.63

 

28.26

 

30.22

 

30.90

 

30.89

Length of natural gas transport network in Italy at period end (8)  

30.1

 

30.2

 

30.7

 

30.9

 

31.1

Electricity sold (9)  

8.65

 

16.95

 

27.56

 

31.03

 

33.19

Refinery throughputs (10)  

33.52

 

35.75

 

36.68

 

36.27

 

35.21

Balanced capacity of wholly-owned refineries (11)  

504

 

504

 

524

 

534

 

544

Retail sales (in Italy and rest of Europe) (10)  

14.01

 

14.40

 

13.72

 

12.48

 

12.65

Number of service stations at period end (in Italy and rest of Europe)  

10,647

 

9,140

 

6,282

 

6,294

 

6,441

Average throughput per service station (in Italy and rest of Europe) (12)  

2,109

 

2,488

 

2,479

 

2,470

 

2,486

Petrochemical production (10)  

6.91

 

7.12

 

7.28

 

7.07

 

8.80

Oilfield Services Construction and Engineering order backlog at period end (13)  

9,405

 

8,521

 

10,122

 

13,191

 

15,390

Employees at period end (units)  

75,421

 

70,348

 

72,258

 

73,572

 

75,862

 
 
 
 
 

(6)    Expressed in BCM.
(7)    From 2006, also includes E&P sales of volumes of natural gas produced in the Gulf of Mexico.
(8)    Expressed in thousand kilometers.
(9)    Expressed in TWh.
(10)    Expressed in mmtonnes.
(11)    Expressed in KBBL/d.
(12)    Expressed in thousand liters per day. Refers to the Agip branded network only, as in years up to 2005 Eni also sold refined products on the "IP" branded network of service stations in Italy.
(13)    The sum of the order backlog of Saipem SpA and Snamprogetti SpA, expressed in million euro.

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Exchange Rates

The following tables sets forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board).

 

High

 

Low

 

Average (1)

 

At period end

 
 
 
 
 

(U.S. dollars per euro)

Year ended December 31,                
2003   1.26   1.04   1.13   1.26
2004   1.36   1.18   1.24   1.35
2005   1.35   1.17   1.24   1.18
2006   1.33   1.19   1.26   1.32
2007   1.49   1.29   1.37   1.46
 
 
 
 

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

 

 

High

 

Low

 

At period end

 
 
 
 

(U.S. dollars per euro)

November 2007   1.49   1.44   1.47
December 2007   1.48   1.43   1.46
January 2008   1.49   1.46   1.48
February 2008   1.52   1.45   1.52
March 2008   1.58   1.52   1.58
April 2008   1.60   1.56   1.56
May 2008 (through May 14, 2008)   1.55   1.54   1.55
 
 
 

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 May 14, 2008 was $1.55 per euro 1.00.

 

Risk Factors

Competition

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

Eni encounters competition from other oil and natural gas companies in all areas of its operations.

  In the Exploration & Production business, Eni faces competition from both international oil companies and state run oil companies for obtaining exploration and development rights, particularly outside of Italy, and developing and applying new technology to maximize hydrocarbon recovery. If Eni fails to obtain new exploration and development acreage or to apply and develop new technology, its growth prospects and future results of operations and cash flows may be adversely affected. The current trend of the industry towards a reduction of the number of operators through takeovers or mergers may lead to stronger competition from operators with greater financial resources and a wider portfolio of development projects.
  Eni is increasingly in competition with state run oil companies who are partners of Eni in a number of oil and gas projects and titles in the host countries where Eni conducts its upstream operations. These state run 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, by this way reducing Eni’s profit share. For example, Sonatrach, the Algeria national oil company, is seeking to modify the contractual terms of certain PSAs in which Eni is party to achieve a redistribution of the tax burden of such PSAs. In fact, Sonatrach alleges that it is currently bearing part of the tax burden attributable to Eni following the enactment of certain modifications to the country’s tax regime. If this negotiation results in a negative outcome for Eni, the future profitability

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    of certain of Eni’s PSAs in Algeria will be reduced. For more information on this matter see "Item 4 – Exploration & Production – Algeria".
  In Eni’s Exploration & Production activities in Libya, which accounted for 14% of its liquids production and 15% of its gas production in 2007, the Company faces increasing competition from other international oil and gas companies. This competition has increased sharply in recent years following the ending of economic sanctions imposed on Libya by the United Nations and the U.S.
  In its domestic natural gas business, Eni faces an increasingly strong competition from both national and international natural gas suppliers, also following the impact of the liberalization of the Italian natural gas market introduced by Legislative Decree No. 164/2000 which provides for, among other things, the opening of the Italian market to competition, limitations to the size of gas companies relatively to the market and third party access to infrastructures. Increasingly high levels of competition in the Italian natural gas market could possibly entail reduced natural gas selling margins (see below). In addition, Legislative Decree No. 164/2000 grants the Italian Authority for Electricity and Gas certain regulatory powers in matters of natural gas pricing and access to infrastructures. Outside of Italy, particularly in Europe, Eni 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. Furthermore a number of large clients, particularly electricity producers, in both the domestic market and other European markets are planning to enter the supply market of natural gas. 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 national and other European markets for natural gas and reduce Eni’s operating profit.
  In its domestic electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity in the Italian market.
  In retail marketing of refined products both in and outside Italy, 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. Once established, Eni’s service stations compete primarily on the basis of pricing, services and availability of non-petroleum products. In Italy, political and institutional forces are urging greater levels of competition in the retail marketing of fuels. Eni expects developments on this issue to further increase pressure on selling margins in the retail marketing of fuels.
  Competition in the oilfield 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).

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

The exploration and production of oil and natural gas requires high levels of capital expenditures and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil and natural gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. The oil and 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.

Exploratory drilling efforts may not be successful

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 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. Specifically, in the Caspian Region these complex environmental conditions resulted in higher drilling expenses as discussed under "Item 4 – Exploration & Production – Caspian Area". 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. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. In particular Eni plans to explore for oil and gas offshore, frequently in deep water or at deep drilling depths, where operations are more difficult and costly than on land or at shallower

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depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. In the case of the Company, risky exploration projects are conducted in the deep offshore of the Gulf of Mexico, Australia, Brazil, the Barents Sea, India, and offshore Ireland. In 2008, management plans to spend significant amounts of exploration expenditures in these areas that may result in significant dry hole expenses.

In addition, lack of essential equipment such as a shortage of deep water rigs could delay operations or increase exploration costs, thus increasing both operational and financial risks. Furthermore, 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 involved in several development projects for the production of hydrocarbon reserves, principally offshore. Eni’s future results of operations rely upon its ability to 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 with customers; 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 affording opportunities to participate 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 supplier of goods and services;
  the ability to design development projects so 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;
  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, including the sharp rise in procurement costs and costs for leasing third party equipment or purchase services such as drilling rigs and shipping that we have experienced in recent years as a result of industry-wide cost inflation, resulting in cost overruns;
  the actual performance of the reservoir and natural field decline; and
  the ability and time necessary to build suitable transport infrastructures to export production to final markets.

Furthermore, deep waters and other hostile environments, where the majority of Eni’s planned and existing development projects are located, can exacerbate these problems. Delays and differences between scheduled and actual timing of critical events, as well as cost overruns may adversely affect completion, the total amount of expenditures to be incurred and start up of production from such projects and, consequently, actual returns. Finally, developing and market hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involving an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, 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 which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased budgeted expenditures and a substantial delay in the scheduling of production start up on the Kashagan field, where development is ongoing. Moreover, in July 2007 these matters triggered a dispute with the relevant Kazakh authorities. In January 2008, the Kazakh authorities and the partners of the consortium North Caspian Sea Production Sharing Agreement (NCSPSA), which conducts operations at the Kashagan field, reached a settlement of this dispute. The parties have agreed, among others, to the following terms: (i) the proportional dilution of the participating interests of all the international members of the Kashagan consortium, allowing the national Kazakh company KazMunayGas’ stake to increase matching that of the four major shareholders at 16.81%, effective January 1, 2008. The Kazakh partner will pay to the other co-venturers an aggregate amount of U.S. $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPSA, the amount of which will vary in proportion to future levels of oil prices. Eni will contribute to the value transfer package according to its new participating interest in the project. See "Item 4 – Business Overview – Exploration & Production". If the Company is unable to develop and operate major projects as planned, it may have a material adverse effect on our results of operations and liquidity.

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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. Eni’s proved reserves of subsidiaries declined by 6.1% in 2007 and by 5.8% in 2006. In addition, Eni’s reserve replacement ratio was 38% in both 2007 and 2006, and 43% in 2005, meaning that the Company replaced less reserves than those produced. These reductions were greatly impacted by lower 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 a field’s 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. See "Item 4 – Business Overview – Exploration & Production". 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. An inability to replace reserves could adversely impact future production levels and growth prospects, thus negatively affecting Eni’s future results of operations and financial condition.

Lifting and development costs are trending up and this could reduce profit per BOE in the Exploration & Production segment

Profits per BOE in the Exploration & Production segment are being affected by a steady rising trend in lifting and development costs as a result of a number of industry-wide operating factors, including: (i) the increasingly high percentage of complex development projects in our portfolio (such as those in deep and ultra deep waters and in harsh environments, such as with the Kashagan field). These projects in complex environments bear higher lifting and development costs as compared to development projects located onshore and in traditional environments; (ii) continuing increases in the purchase prices of raw materials and services due to sector-specific inflation; and (iii) an increasingly severe shortage of specialized resources (such as engineers and other valuable technicians) and critical equipment (such as drilling rigs) especially in remote areas, leading to project delays and cost overruns. Eni’s management expects this rising trend in lifting and development costs to continue in the foreseeable future, resulting in a continuing pressure on our profit margins per BOE.

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. Eni generally does not hedge its exposure to variability 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 OPEC member countries which control a significant portion of the worldwide 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;
(iv)   prices and availability of alternative sources of energy;
(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. Such factors can also affect the prices of natural gas because natural gas prices for the major part of our supplies are typically indexed to the prices of crude oil and certain refined petroleum products. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flows from operations.

Furthermore, 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; (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 impairments charges.

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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 because the estimates of reserves are based on prices and costs existing as of the date when those estimates are made. In particular the reserves 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 ultimately will 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.

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

In recent years, Eni has experienced adverse changes in tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. For example, in 2006 changes were enacted in the rate of taxes applicable to profit before taxation for upstream operations in the United Kingdom and in Algeria. As a result, in its 2006 profit and loss account Eni recorded an aggregate expense of euro 526 million for higher taxes payable and adjustments to deferred tax liabilities.

Management believes that adverse changes are always possible in the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. These adverse changes would translate into negative impacts on Eni’s future results of operations and cash flows. Furthermore, the marginal tax rate in the oil and gas industry tends in the long-term to change in correlation with the price of crude oil which could make it difficult for Eni to translate higher oil prices into increased net profit.

 

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. At December 31, 2007, approximately 70% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supply comes from countries outside the EU and North America. In 2007, 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. A case in point was the expropriation of Eni’s assets relating to the Dación oilfield in Venezuela which occurred in 2006, following the unilateral cancellation of a service contract regulating oil activities in this field by the Venezuelan state oil company. For a discussion on developments for this matter see "Item 4 – Exploration & Production – Venezuela"; (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. For example, in 2007 we experienced continued social unrest in Nigeria leading to a number of disruptions at certain Eni oil producing facilities in the Country. As a consequence, our oil and gas production in the Country declined by an estimated amount of 25 KBOE/d from the previous year. In the first quarter of 2008, the Company has experienced a slow ramp up of production. See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves"; and "Item 5 – Recent Developments". While the occurrence of these 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.

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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 of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties.

Under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under, ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 8 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country.

Adding to Eni’s risks arising from this matter, a bill to amend and extend the extra-territorial reach of the economic sanctions imposed by the United States with respect to Iran has been passed by the U.S. House of Representatives and may lead to the passage of new laws in this area. Iran continues to be designated by the U.S. State Department as a State sponsoring terrorism. For a description of Eni’s operations in Iran see "Item 4 – Information on the Company – Exploration & Production – North Africa and Rest of World". It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation.

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 state sponsors of terrorism. These policies could adversely impact investment by certain investors in our securities.

 

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand, 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 and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from Asiatic companies and national oil companies’ petrochemical divisions which can leverage on certain long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. In particular, Eni’s petrochemical operations are located mainly in Italy and Western Europe where regulatory framework and public environmental sensitivity are generally more stringent than in other 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.

 

Liberalization of the Italian Natural Gas Market

Legislative Decree No. 164/2000 opened up the Italian natural gas market to competition as from January 1, 2003. As a result, all customers in Italy are free to choose their supplier of natural gas. The decree, among other things, introduced rules which have a significant impact on Eni’s activity, as the Company is present in all the phases of the natural gas chain; in particular:

  until December 31, 2010, antitrust thresholds are in place for gas operators in Italy as follows: (i) effective January 1, 2002, operators are prohibited to transmit into the national transport network imported or domestically produced gas volumes higher than a preset share of Italian final consumption. This share was 75% of total final consumption in the first year of regulation, decreasing by 2 percentage points per year to achieve a 61% threshold in terms of final consumption by 2009 (this share amounted to 65% in 2007); and (ii) effective January 1, 2003, operators are forbidden from marketing gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified annually by comparing actual average shares reached by any operator in a given three-year period for both volumes input and volumes marketed to customers to average shares permitted by the law for the same period. Actual shares are computed net of losses (in the case of sales) and volumes of natural gas consumed in own operations. Based on a bill passed by the Italian upper house, Eni expects that these antitrust thresholds will be renewed when they expire in 2010; and

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  access to natural gas infrastructures is guaranteed to any natural gas operator on the basis of certain procedures that must be transparent and non discriminatory. Natural gas infrastructures comprise high pressure, high sized pipelines for transporting natural gas over long distances, certain depleted fields to store natural gas, regasification facilities and low pressure, small sized pipelines for distributing natural gas to residential and commercial clients located in urban centers. Tariffs to use these infrastructures are set by the Authority for Electricity and Gas, an independent governmental body.

Eni expects that a combination of regulatory effects and increasing competition will limit growth prospects and profitability of our natural gas business in Italy as discussed below.

Eni has been experiencing significant pressure on its natural gas margins1 since the inception of the liberalization process in Italy. In addition, unfavorable trends in Italian demand and supply of gas could add further pressure

Since the inception of the liberalization process in the Italian natural gas market, Eni has been experiencing rising competition in its natural gas business leading to lower selling margins due to the entry of new competitors into the market. Certain competitors of Eni are supplied by the Company itself, generally on the basis of long-term contracts. In fact, in order to comply with the above mentioned regulatory thresholds relating to volumes supplied through the national transport network and sales volumes in Italy, Eni sold part of its gas availability under its take-or-pay supply contracts to third parties importing said volumes to Italy and marketing them to Italian customers. For more information on Eni’s take-or-pay contracts, see "Item 4 – Gas & Power – Natural gas purchases".

Management expects Eni’s gas selling margins in Italy to remain under pressure in the foreseeable future considering Eni’s gas availability under its take-or-pay supply contracts, build-up of Eni’s supplies to the above mentioned competitors and possibly new competitors entering the Italian market also in light of ongoing or planned capital projects intended to expand the transport capacity of import pipelines to Italy and to build new import infrastructures, particularly LNG terminals. In fact, Eni is currently implementing its plans to upgrade its natural gas import pipelines mainly from Algeria and Russia to Italy to achieve an increase of 16 BCM/y in import capacity reaching full operation in 2009, of which 10 BCM are expected to come online in 2008 (3.3 BCM are already operating; 6.6 BCM are expected to come online by year end). Further 3 BCM/y of new import capacity will be added by upgrading the GreenStream gasline from Libya with expected start up in 2012. A large portion of the new capacity deriving from Eni’s upgrading projects has been or is planned to be sold to third parties. In addition, Eni expects a third party’s new LNG terminal with an 8 BCM/y capacity to commence operations by end of 2008.

Despite the fact that an increasing portion of natural gas volumes purchased by Eni under its take-or-pay contracts is planned to be marketed outside Italy, management believes that in the long-term unfavorable trends in the Italian demand and supply for natural gas, also due to the possible implementation of all publicly announced plans for the construction of new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts and may result in a downward pressure on gas selling margins. Based on the foregoing, Eni’s future results of operations and cash flows might be adversely affected.

Eni’s growth prospects in Italy are limited by regulation

Due to the antitrust threshold on direct sales in Italy, management expects Eni’s natural gas sales in Italy to increase at a rate that will not exceed the growth rate of natural gas demand in Italy.

Eni is committed to increasing natural gas sales in Europe. If Eni fails to achieve this target, future growth prospects may be adversely affected. Furthermore, Eni may be unable to fulfill its minimum take obligations under its take-or-pay purchase contracts and this could adversely impact 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 it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands). 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.

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

Over the medium term, Eni has scheduled its import volumes of natural gas to Italy based on the assumption to use the purchase flexibility contractually provided by its take-or-pay purchase contracts during periods in which


(1)   For a definition of margin see "Glossary".

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demand is expected to peak. These import programs are also based on the assumption that Eni will obtain the necessary transport capacity on the Italian transport network. However, Eni’s planning assumptions are inconsistent with current rules regulating the access to the Italian transport infrastructures as provided for by the Network Code currently in force which has been drafted in accordance with Decision No. 137 of July 17, 2002 of the Authority for Electricity and Gas. Such rules establish certain priority criteria for transport capacity entitlements at points where the Italian transport infrastructure connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, Eni’s gas volumes purchased under take-or-pay contracts are entitled to a priority in the allocation of available transport capacity for amounts not exceeding average daily contractual volumes. Accordingly, Eni’s purchase volumes exceeding average daily contractual volumes are not entitled to any priority in gaining access to the Italian transport infrastructures. The contractual flexibility represented by Eni’s right to uplift daily volumes larger than average daily contractual volumes under its take-or-pay purchase contracts is used when demand peaks, usually during the wintertime. In the event congestion occurs at entry points to the Italian transport network, under current regulation available transport capacity would be entitled firstly to operators having a priority right, i.e. holders of take-or-pay contracts within the limits of average daily contractual volumes. Then any residual available transport capacity would be allocated in proportion to all pending capacity requests. Eni considers Decision No. 137/2002 to be inconsistent with the overall rationale of the European natural gas regulatory framework, especially with reference to Directive 98/30/CE (superseded and replaced by Directive 03/55/CE) and Legislative Decree No. 164/2000, and has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". Eni cannot rule out a negative outcome for this matter. However, management believes that Eni’s results of operations and cash flows could be adversely affected should market conditions in light of current regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill its minimum take contract obligations (e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure, Eni would be forced to uplift a smaller volume of gas than the minimum contractual take). See "Item 5 – Management Expectations of Operations".

The Italian Government, Parliament and the regulatory authorities in Italy and in Europe may take further steps to increase competition in the Italian natural gas market and such regulatory developments may adversely affect Eni’s results of operations and cash flows

Italian institutional and political forces are urging a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area. A brief description follows of certain recently enacted laws and certain proceedings before the Authority for Electricity and Gas and the Italian Antitrust Authority in order to allow investors to gain some insight into the complexity of this matter. For a full discussion of laws and procedures described herein see "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power".

In 2003, Law No. 290 was enacted which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 50.04% interest in Snam Rete Gas, which owns and manages approximately 97% of the Italian natural gas transport infrastructure). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re-scheduled in a 24-month term starting from the date in which this decree from the Italian Prime Minister becomes effective. Currently, Eni is unable to predict any deadline of this disposal.

On the basis of a joint inquiry conducted from 2003 through June 2004 on the Italian natural gas market, the Authority for Electricity and Gas and the Italian Antitrust Authority (the "Antitrust Authority") concluded that the overall level of competition of the Italian natural gas market is unsatisfactory due to the dominant position held by Eni in many phases of the natural gas chain. According to both the Authority for Electricity and Gas and the Antitrust Authority, the vertical integration of Eni in the supply, transport and storage of gas has restricted the development of competition in Italy notwithstanding the antitrust ceilings introduced by Legislative Decree No. 164/2000. It was further stated that the price of natural gas in Italy (in particular for the industrial sector) is higher than in other European countries.

In November 2006, the Authority for Electricity and Gas concluded an inquiry concerning the competitive behavior of operators selling natural gas to residential and commercial customers. This inquiry acknowledged that the retailing market for natural gas in Italy lacked a sufficient degree of competition due to current commercial practices and the existence of both entry and exit barriers. The Authority plans to implement measures to improve competition in this market.

In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regard to lack of investments by operators directed to expand capacity to store natural gas in Italy. Eni through its wholly-owned subsidiary Stogit Italia owns almost the entire storage capacity currently existing in Italy.

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

Decisions of the Authority for Electricity and Gas on the matter of natural gas tariffs may diminish Eni’s ability to determine the price at which it sells natural gas to customers

On the basis of certain legislative provisions, the Authority for Electricity and Gas ("the Authority") holds a general monitoring power on pricing in the natural gas market in Italy and the power to establish reference selling tariffs for supply of natural gas to residential users taking into account, among other things, the public interest goal of containing inflationary pressure due to rising energy costs. The decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the purchase cost of natural gas on to the final consumers. Specifically, upon finalization of a complex lengthy administrative procedure started in 2004 and closed in March 2007, the Authority: (i) set the raw material cost component in supplies to residential users consuming less than 200,000 CM/y for the period from January 1, 2005 to June 30, 2006 – at the same time imposing to Italian natural gas importers (including Eni) to renegotiate supply contracts with resellers to residential users in order to take account of the impact of these new amounts; and (ii) confirmed the indexation mechanism for updating the raw material cost component in supplies to above mentioned users in force from July 1, 2006, establishing in particular that in case the international price of Brent crude oil decrease below the 20 dollars per barrel threshold or exceed the 35 dollars per barrel threshold the corresponding variations of the raw material cost are only partially transferred on to residential users of natural gas. Management cannot exclude the possibility that in the future the Authority could implement similar measures that may negatively affect Eni results of operations and liquidity. For more information on this issue (particularly the Authority’s Decisions No. 248/2004, 134/2006 and 79/2007) 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 2007, Eni accrued significant provisions amounting to euro 130 million against pending antitrust proceedings before the European Commission. In previous years, Eni also recorded significant loss provisions against antitrust proceedings before the Italian Antitrust Authority, the Authority for Electricity and Gas and the European Commission. It is possible that the Group may incur significant loss provisions in future years relative to ongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this risk in its natural gas and refining and marketing activities due to its large presence in these markets in Italy and in Europe. See Note 28 to the Consolidated Financial Statements for a full description of Eni’s main ongoing 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. 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, as well as refining, petrochemicals and other Group operations, limit or prohibit drilling activities in certain protected areas, 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 pollution resulting from oil, natural gas, refining, petrochemical and other Group’s 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 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. 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 environmental, health and safety laws and regulations, also taking into account possible future developments in environmental regulations in Italy and in other countries where Eni operates, particularly the implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions.

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Eni’s results of operations and financial condition are exposed to risks deriving from environmental, health and safety accidents and liabilities

Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s belief that Eni adopts high standards to ensure safety of its operations, it is always possible that incidents like blow-outs, spillovers, contaminations and similar events could occur that would result in damage to the environment, workers and communities. In particular, Eni is performing a number of remedial actions to restore certain industrial sites which were contaminated as a result of the Group’s activities in previous years. Management expects other remedial actions to be implemented in future years. 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 amount represents the management’s best estimates of future environmental expenses to be incurred taking into account the probability that new and stricter environmental laws might be implemented and third parties’ claims. Notwithstanding this, 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 chance of as yet unknown contamination; (ii) the results of on-going 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 site; and (iii) the possibility that new litigation might arise.

 

Legal Proceedings

Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of the 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.

 

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 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 by different 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 these changes. Wholesale margins in the Gas & Power business are substantially independent from fluctuations in crude oil prices as purchase and selling prices of natural gas are contractually indexed to prices of crude oil and certain refined products according to similar pricing schemes. However, quarterly performance and year-to-year comparability of results of Eni’s natural gas business may be somewhat affected by the indexation mechanism of the raw material component in gas supplies to residential customers and certain resellers to residentials in Italy in accordance with applicable regulations from the Italian Authority for Electricity and Gas as outlined above in the risk factor describing the "Liberalization of the Italian Natural Gas Market". Specifically, this indexation mechanism provides a certain time lag between movements in the price of crude oil and the related adjustment to the selling price of natural gas. For a detailed discussion of this indexation mechanism in Italy see "Item 4 – Regulation – Gas & Power – Natural gas prices".

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

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

The 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 as outlined above. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities vs. light crude qualities. In 2007, Eni’s refining margins declined significantly compared to 2006 due to a weak trading environment exacerbated by the circumstances that price differentials between heavy crudes and light ones narrowed sharply resulting in a substantial reduction in the profitability of complex throughputs.

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 changes in oil prices which influence changes in purchase costs of petroleum-based feedstock. 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 2007, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins for commodity petrochemical products due to higher purchase costs for oil-based feedstock that were not fully transferred to selling prices of products. Management’s outlook for 2008 is also challenging, and management does not expect any significant improvement in the trading environment from 2007 and possibly a further contraction in margins on petrochemical products.

 

Risks from Acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or corporations in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, in the current high oil price environment, 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 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.

 

Exchange Rates

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 results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in dollar-denominated expenses. The Exploration & Production segment is particularly affected by movements in the U.S. dollar vs. the euro exchange rates. In 2007, Eni’s operating profit in this business segment declined by an estimated amount of euro 1.4 billion due to a 9.2% depreciation of the U.S. dollar versus the euro. Based on current trends in the U.S. dollar vs. the euro exchange rates, management expects the operating profit of the Exploration & Production segment to be negatively affected in 2008.

 

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 2007, operating profit in the Gas & Power business was negatively affected by unusually mild winter weather resulting in lower gas sales from a year ago.

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.

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Interest Rates

Interest on Eni’s finance 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 finance debt.


Critical Accounting Estimates

The preparation of financial statements requires management to make certain accounting estimates that are characterized by a high degree of uncertainty, complexity and judgment. These estimates affect the reported amount of the Company’s assets and liabilities, as well as the reported amount of the Company’s income and expenses for a given period. 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; the availability of new informative elements, variations in economic conditions such as prices, significant factors (e.g. removal technologies and costs) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".

 

 

Item 4. INFORMATION ON THE COMPANY

History and Development of the Company

Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 75,862 employees as of December 31, 2007.

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: www.eni.it.

The name of the agent of Eni in the United States is Viscusi Enzo, 666 Fifth Ave., New York, NY 10103.

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment involves oil and natural gas exploration and field development and production, as well as LNG operations in 36 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2007, Eni’s production of oil and natural gas amounted to 1,684 KBOE/d on an available-for-sale basis. As of December 31, 2007, Eni’s proved reserves of subsidiaries stood at 6,010 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 668 mmBOE. In 2007, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 27,278 million and operating profit of euro 13,788 million.

Eni’s Gas & Power segment involves supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. In 2007, Eni’s worldwide sales of natural gas amounted to 98.96 BCM, including 5.39 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S.. Sales in Italy amounted to 56.13 BCM, while sales in European markets were 35.02 BCM that included 10.67 BCM of gas sold to certain importers to Italy. Through its 50.04 per cent-owned subsidiary Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,081-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 5,000 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Eni, through its 100 percent-owned

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subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,318 municipalities through a low pressure network consisting of approximately 48,750 kilometers of pipelines as of December 31, 2007. Eni produces electricity and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of approximately 4.9 GW as of December 31, 2007. In 2007, sales of electricity totaled 33.19 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in Europe, Egypt and in certain projects under construction in the U.S.. In 2007, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 27,633 million and operating profit of euro 4,127 million.

Eni’s Refining & Marketing segment involves refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2007, processed volumes of crude oil and other feedstock amounted to 37.15 mmtonnes and sales of refined products were 50.15 mmtonnes, of which 28.05 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.65 mmtonnes including Italy and the rest of Europe. In 2007, Eni’s retail market share in Italy through its Agip-branded network of service stations was 29.2%. In 2007, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 36,401 million and operating profit of euro 729 million.

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 2007, Eni sold 5.5 mmtonnes of petrochemical products. In 2007, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,934 million and an operating profit of euro 74 million.

Eni’s oilfield services, construction and engineering activities are conducted through its 43 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, subsea pipe laying and floating production systems and onshore construction. Offshore and onshore drilling services and engineering and project management services are also provided to the oil and gas, refining and petrochemical industries. In 2007, Eni’s Engineering & Construction segment reported net sales from operations (including intragroup sales) of euro 8,678 million and operating profit of euro 837 million.

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

 

Strategy

Eni’s strategy is to grow the Company’s main businesses over both the medium and the long-term, with improving profitability. This strategy is designed to create long-term shareholder’s value particularly through significant dividend distributions. Over the next four-years, Eni plans to execute a capital expenditure program amounting to euro 49.8 billion to support organic growth. Eni plans to fund this capital expenditure program by means of cash flows provided by operating activities. Over the next four-years, the Company expects to distribute to its shareholders annual amounts of dividends in line with the current level in real terms (See "Item 8 – Dividends"). Eni plans to allocate cash flows provided by operating activities in excess of capital expenditures and dividend payments to continue its program of share repurchases, while at the same time maintaining a strong balance sheet. See "Item 5 – Management Expectations of Operations".

Eni’s strategy in its Exploration & Production operations is to grow production leveraging on development of assets in its portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to achieve a production growth rate of 4.5% on average over the 2008-2011 period, under Eni’s Brent price scenario of 64 U.S. dollar per barrel in 2008, decreasing to 55 U.S. dollar per barrel in 2011 (See "Item 5 – Management Expectations of Operations"). High oil prices represent a risk to the achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008 Brent price was 121.14 U.S. dollar per barrel. For a description of Eni’s production volume sensitivity to oil prices see "Item 5 – Management Expectations of Operations". Management will continue to evaluate opportunities to increase production through acquisitions. Eni intends to pay special attention to reserve replacement in order to secure the medium to long-term sustainability of its business.

In its Gas & Power activities, Eni intends to grow natural gas sales in the international market, preserve the profitability of the Italian marketing business, effectively manage regulated businesses, and develop a global LNG business. Eni targets worldwide gas sales of 110 BCM in 2011, including E&P sales in the North Sea and the U.S.. In particular, Eni plans to achieve an annual average growth rate of 9% in international sales in the four-year period 2008 to 2011. Eni plans to grow its international sales mainly: (i) in Europe, where Eni expects to expand sales in those markets where its presence is already established – i.e. the Iberian Peninsula, Germany, Turkey, France and the UK – leveraging on the Company’s competitive advantages given by gas availability, access to infrastructures and long-term relationships with the most important producing countries (mainly Russia, Algeria and Libya); and (ii) in the U.S. where Eni plans to grow sales by leveraging on a number of LNG projects that are currently being

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executed. In Italy, Eni plans to implement a marketing plan aiming at preserving the profitability of its Italian operations against an expected increase in competition. Management forecasts sale volumes to remain stable compared to current levels. Eni intends to focus the most profitable customer segments, upgrade the commercial offer by tailoring pricing and services to customers’ specific needs and leverage the full potential of the combined supply of gas and electricity ("dual offer"). A strong focus will be devoted to reducing marketing expenses.

In its Refining & Marketing activities, Eni intends to improve profitability through the following steps. In its refining activities, Eni plans to implement a number of capital projects designed to upgrade its refineries with the aim of: (i) increasing conversion capacity so as to obtain a higher yield of middle distillates; (ii) enhancing flexibility in order to process low-quality crude that is typically discounted in the market-place; and (iii) reducing operating costs. In marketing, Eni intends to strengthen its leadership position in the Italian retail market by improving the quality of the offer through high standards of service, the marketing of premium fuels, tailored promotional initiatives to retain customers and advanced convenience formats. Eni will also continue to develop sales in a number of selected markets in the rest of Europe.

In its Engineering & Construction activities, Eni aims developing and expanding its geographical reach and technical characteristics of its world class fleet, by capturing opportunities arising from a growing market in drilling and oilfield services sectors. In order to achieve this, management plans to leverage on Eni’s strong position in faster growing markets and its consolidating relationships with major companies and National Oil Companies.

In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.7 billion to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crudes (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.

 

Significant business and Portfolio Developments

The significant business and portfolio developments that occurred in 2007 and to date in 2008 were the following:

  In April 2007, as part of the liquidation procedure of bankrupt Russian company Yukos, Eni purchased a 60% interest in OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia which are engaged in the development of hydrocarbon reserves, mainly consisting of natural gas reserves. Eni’s share of proved reserves purchased in connection with this transaction amounted to 617 mmBOE. Eni also acquired 20% of OAO Gazprom Neft. Net cash consideration for this transaction amounted to U.S. $5 billion (equivalent to euro 3.73 billion). Gazprom was granted an option to acquire a 51% interest in those three gas companies and the entire 20% interest in OAO Gazprom Neft. Should Gazprom exercise its call option to purchase a 51% interest in those gas companies, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%.
  In May 2007, Eni finalized the purchase of proved and unproved oil and gas properties onshore Congo from the French company Maurel & Prom for cash consideration of U.S. $1,434 million (equivalent to approximately euro 1 billion). Acquired properties brought in an incremental production of 17,000 BOE/d; additions to Eni’s proved reserves amounted to 33 mmBOE.
  In July 2007, Eni closed the acquisition of oil and gas properties from U.S. Company Dominion Resources in the Gulf of Mexico for total cash consideration of U.S. $4,757 million (equivalent to euro 3.5 billion). Acquired properties, 60% of which operated, contributed an incremental production of 75,000 BOE/d; additions to Eni’s proved reserves amounted to 123 mmBOE.
  In October 2007, Eni signed a major agreement with NOC, the Libyan National Oil Corporation. The agreement provides for the extension of the duration of Eni’s mineral rights in Libya, for oil properties until 2042 and for gas properties until 2047, and the launch of large projects aiming at monetizing substantial gas reserves and overhauling offshore exploration activities. Relevant agreements will be effective from January 1, 2008.
  In November 2007, Eni announced the terms of a recommended cash offer to acquire the entire issued share capital of the UK-based oil company Burren Energy Plc. This acquisition closed in January 2008. Total cash consideration amounted to approximately euro 2.3 billion, of which euro 0.6 billion were spent in 2007. Burren holds producing assets in Congo and Turkmenistan flowing at a rate of over 25,000 BOE/d and partners with Eni in the Congolese assets that Eni bought from Maurel & Prom.

In addition, in 2007 Eni closed the following transactions:

  In April 2007, Eni acquired an additional interest in the Nikaitchuq field in Alaska, thus achieving a 100% interest. Production start-up is expected by end of 2009.

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  In June 2007, a gas sale agreement was signed between the consortium conducting operations at the Karachaganak field (Eni is co-operator with a 32.5% stake) and KazRosGaz, a joint venture established by the Kazakh and Russian companies KazMunaiGaz and Gazprom. This agreement lays the foundations for the development of field gas reserves.
  In June 2007, Eni signed a framework agreement with Gazprom to build the South Stream pipeline system which is expected to import into Europe volumes of natural gas produced in Russia across the Black Sea.
  In June 2007, Eni acquired a 27.8% interest in Altergaz, the main independent operator in the French gas market. Eni plans to support Altergaz development in the French retail and small enterprises segments through 10 year supply contract for 1.3 BCM/y.
  In September 2007, Eni purchased a 16.11% stake in the Czech Refining Company, increasing Eni’s ownership interest to 32.4% and equal to a refining capacity of 2.6 mmtonnes/y.
  In October 2007, Eni purchased 102 retail fuel stations from ExxonMobil Central Europe located in Czechia, Slovakia and Hungary and related additional marketing activities.
  In November 2007, Eni purchased a 13.6% interest in the Angola LNG Ltd Consortium (A-LNG) committed to build an LNG plant. The plant will be designed with a processing capacity of 1 BCF/d of natural gas and produce 5.2 mmtonnes/y of LNG and related products.

Recent developments are described below.

  In January 2008 the international partners of the North Caspian Sea Production Sharing Agreement (NCSPSA) Consortium and the Kazakh authorities signed a Memorandum of understanding to settle a dispute commenced in August 2007 regarding conditions and rights for developing and exploiting the Kashagan field. For further details on this transaction see "Item 4 – Exploration & Production – Kazakhstan".
  In February 2008, Eni and the Venezuelan authorities reached a final settlement over the dispute regarding the expropriation of the Dación field that occurred in April 2006. Under the terms of the settlement, Eni will receive cash compensation in line with the carrying value of the expropriated asset.
  In February 2008, Eni and the Venezuelan State oil company PDVSA signed a strategic agreement for the development of the Junin Block 5 located in the Orinoco oil belt. According to management’s estimates, this block covering a gross acreage of 670 square kilometers holds an important resource potential.

In 2007, capital expenditures amounted to euro 10.6 billion, of which 84.7% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 4,788 million) deployed predominantly in Kazakhstan, Egypt, Angola, Italy and Congo, and exploration projects (euro 1,659 million) particularly in the Gulf of Mexico, Egypt, Norway, Nigeria and Brazil; (ii) development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 886 million) as well as upgrading of natural gas import pipelines to Italy (euro 253 million); (iii) the ongoing construction of combined cycle power plants (euro 175 million); (iv) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build and upgrade service stations (totaling euro 979 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,410 million).

In 2007, Eni’s acquisitions amounted to euro 9.7 billion and mainly related to: (i) a 60% interest in three Russian gas companies as part of the liquidation procedure of bankrupt Russian company Yukos. Through the same transaction Eni also purchased a 20% stake in the oil and gas company OAO Gazprom Neft. Gazprom was granted a call option to purchase a 51% interest in those three gas companies and the 20% stake in OAO Gazprom Neft; (ii) the purchase of upstream assets in the Gulf of Mexico; (iii) the purchase of upstream assets onshore Congo; (iv) the purchase of a 24.9% interest in Burren Energy; (v) the acquisition of a further 16.11% stake in the Ceska Rafinerska in the Czech Republic increasing Eni’s ownership interest to 32.4%; (vi) the purchase of 102 retail fuel stations and related marketing assets located in the Czech Republic, Slovakia and Hungary; and (vii) the purchase of a 13.6% stake in the Angola LNG consortium.

In 2006, capital expenditures amounted to euro 7.8 billion, of which 89.6% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and was primarily related to: (i) the development of oil and gas reserves (euro 3,629 million) in particular in Kazakhstan, Angola, Egypt and Italy, exploration projects (euro 1,348 million) particularly in Angola, Egypt, Norway, Nigeria, the Gulf of Mexico and Italy, including the acquisition of 152,000 square kilometers of new acreage (99% operated by Eni); (ii) upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 785 million); (iii) the ongoing construction of combined cycle power plants (euro 229 million); (iv) projects aimed at improving flexibility and yields of refineries (euro 376 million), including the start up of construction of a new hydrocracking unit at the Sannazzaro refinery, and upgrading the refined product distribution network in Italy and in the rest of Europe (euro 223 million); and (v) the construction of a new FPSO unit and upgrading of the fleet and logistic centers in the Engineering & Construction segment (euro 591 million).

In 2005, capital expenditures amounted to euro 7.4 billion, of which 91% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and was primarily related to: (i) the development of oil and gas reserves (euro 3,952 million), in particular in Kazakhstan, Libya, Angola, Italy and Egypt, exploration

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projects (euro 656 million) and the purchase of proved and unproved property (euro 301 million); (ii) upgrading Eni’s natural gas transport and distribution networks in Italy (euro 825 million); (iii) the continuation of construction of combined cycle power plants (euro 239 million); (iv) actions for improving flexibility and yields of refineries, including the completion of construction of the tar gasification plant at the Sannazzaro refinery, and the upgrade of the refined product distribution network in Italy and in the rest of Europe (overall euro 656 million); and (v) upgrading vessels and other equipment and facilities in Kazakhstan and West Africa in the oilfield services and construction business (euro 346 million).

 

 

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment involves oil and natural gas exploration and field development and production, as well as LNG operations, in 36 countries, including Italy, the UK, Norway, Libya, Egypt, Angola, Nigeria, Congo, the U.S., Kazakhstan, Russia and Australia. In 2007, Eni produced 1,684 KBOE/d on an available-for-sale basis. As of December 31, 2007, Eni’s proved reserves of subsidiaries stood at 6,010 mmBOE; Eni’ share of reserves of equity-accounted entities amounted to 668 mmBOE.

Eni’s strategy in its Exploration & Production operations is to increase production leveraging on the development of assets in portfolio and the integration of the assets acquired in 2007, including Burren Energy Plc that was acquired in January 2008. Eni plans to achieve a production growth rate of 4.5% on average over the 2008-2011 period, under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). High oil prices represent a risk factor to the achievement of the Company’s planned production target due to Eni’s exposure to PSAs whereby higher oil prices result in lower production entitlements. On May 14, 2008, Brent price was 121.14 U.S. $/BL. A description of Eni’s production volume sensitivity to oil prices is disclosed under "Item 5 – Management Expectations of Operations". Future growth will be driven by the development of new projects located mainly in the key producing basins of North and West Africa and the Caspian region, and the contribution of long-life fields, including Kazakhstan, Libya, Congo, Nigeria and Italy. Management will continue to evaluate opportunities to increase production through the purchase of corporations or individual assets. Eni intends to pay special attention to reserve replacement in order to guarantee the medium-to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking new opportunities and divesting marginal assets. Eni also intends to develop its LNG business in order to monetize its large base of gas reserves mainly in North and West Africa.

In exploration activities, Eni intends to concentrate resources in well established areas of presence where availability of production facilities, existing competencies and long-term relationships with host countries will enable Eni to readily put in production discovered reserves, reducing the time-to-market and capturing synergies. Approximately 70% of planned capital expenditures will be directed to such core areas (located mainly in the United States, Egypt, Libya, Nigeria, Angola, Italy, Norway and Congo). Eni also plans to selectively pursue high risk/high reward opportunities arising from expansion in areas with high mineral potential. Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic ones.

Eni plans to improve profitability of its operations by implementing operating solutions with lower operating costs and exploiting synergies.

In order to execute these strategies, Eni intends to invest approximately euro 25.1 billion on reserve development and field optimization and euro 4.7 billion on exploration projects over the next four-year period. Further euro 3.7 billion will be spent to upgrade natural gas storage sites in Italy and to execute LNG and transport projects through equity-accounted entities.

 

Oil and Natural Gas Reserves

Eni has always exercised rigorous control over the booking of proved reserves. The Reserve Department of the Exploration & Production segment, reporting directly to the General Manager, is entrusted with the task of continuously updating the Company’s guidelines concerning reserve evaluations and monitoring the periodic quantification process. Company guidelines follow Regulation S-X Rule 4-10 of the U.S. Securities and Exchange Commission (SEC) as well as, on specific issues not regulated by rules, the consolidated practice recognized by qualified reference institutions. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has certified their compliance with applicable SEC rules. D&M has also stated that the company guidelines regulate situations for which the SEC rules are less precise, providing a reasonable interpretation in line with the generally accepted practices in international markets. When participating in exploration and production activities operated by other entities, Eni also estimates its proved reserves on the basis of the above guidelines.

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The process for evaluating reserves involves: (i) business unit managers (geographic units) and Local Reserve Evaluators (LRE), who perform the evaluation and classification of reserves including estimates of production profiles, capital expenditure, operating costs and costs related to asset retirement obligations; (ii) geographic area managers at head offices checking evaluations carried out by business unit managers; and (iii) the Reserve Department, which provides independent reviews of the fairness and correctness of classifications carried out by business units and aggregates worldwide reserve data and calculates equity volumes. Moreover, the Reserve Department has the responsibility to ensure the periodic certification process of reserves, to perform economic evaluation of reserves and to update continuously the Company guidelines on reserves evaluation and classification.

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation2 of its proved reserves on a rotational basis. Eni believes these independent evaluators to be experienced and qualified in the marketplace. In the preparation of their reports, these independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in determining its proved reserves and included log, directional surveys, core and PVT (Production Volume Temperature) analysis, maps, oil/gas/water monthly production/injection data of wells, reservoir, and field; field studies, reservoir studies; engineers comments relative to field performances, reservoir performances, development programs, work programs etc.; budget data for each field, long range development plans, future capital and operating costs, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information to calculate NPV for the fields required to undertake an independent evaluation. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves as opposed to a determination. We also note that the work performed in evaluating our reserves may not be the same work that the independent evaluators perform when evaluating other companies’ reserves. Notwithstanding the above, the fact that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the management’s confidence that the Company’s booked reserves meet the regulatory definition of proved reserves and are reasonably certain to be produced in the future. Additionally, for those fields where a discrepancy arose, the Company has adopted the reserve estimate indicated by the independent evaluators whenever the latter was lower than the Company’s estimate. In any case, those differences were not significant.

In 2007, a total of 1.8 BBOE of proved reserves of subsidiaries have been evaluated, representing approximately 30% of Eni’s total proved reserves of subsidiaries at December 31, 2007. In the 2005-2007 three-year period, 64% of Eni’s total proved reserves of subsidiaries were subject to independent evaluations. As at December 31, 2007 the most important of Eni’s properties which were not subject to an independent evaluation were: Kashagan (Kazakhstan), Bayu Undan (Australia), Cerro Falcone and Monte Alpi-Monte Enoc (Italy). In 2007, Eni’s proved reserves purchased in Russia have also been evaluated as amounting to 617 mmBOE. These reserves related to the acquisition of a 60% interest in three equity-accounted Russian gas companies.

Eni’s proved reserves of subsidiaries at December 31, 2007 totaled 6,010 mmBOE (oil and condensates 3,127 mmBBL; natural gas 16,549 BCF) representing a decrease of 390 mmBOE, or 6.1%, from December 31, 2006. Additions to proved reserves booked by Eni’s subsidiaries in 2007 were 81 mmBOE deriving from: (i) extensions and discoveries (201 mmBOE), with major increases booked in Angola, Congo, Egypt, Kazakhstan, Tunisia and United States; and (ii) improved recovery (23 mmBOE) mainly in Algeria and Angola. These increases were offset in part by a negative balance of 143 mmBOE resulting from downward and upward revisions of previous estimates. Downward revisions of previous estimates mainly related to adverse price impacts in determining volume entitlements in Eni’s PSAs (down 348 mmBOE) resulting from higher year end oil prices (Brent price was $96.02 per barrel at December 31, 2007 compared to $58.925 per barrel at December 31, 2006). These negative revisions were recorded mainly in Kazakhstan, Libya and Angola, and were partly offset by upward revisions in Egypt, Italy, Nigeria and Norway. Acquisitions amounted to 156 mmBOE reflecting a contribution of purchased properties in the Gulf of Mexico and Congo. Due to risks inherent in the exploration and production business, a degree of uncertainty still exists as to whether these additions will actually be produced. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves". Proved reserves of Eni’s subsidiaries were determined based on Eni’s working interest of 18.52% in quantifying reserve entitlements of the Kashagan project as of December 31, 2007. As part of the agreements defined with the Kazakh Republic, the change of Eni’s interest to 16.81% in 2008 will determine a decrease of approximately 50 mmBBL in Eni’s estimated net proved reserves of the Kashagan field with respect to December 31, 2007 (information on the Kashagan agreements is provided below under the section "Caspian Area" on page 35).

As of December 31, 2007 Eni’s share of proved reserves of equity-accounted entities amounted to 668 mmBOE. In 2007, proved reserves booked in connection with the acquisition of a 60% interest in three Russian gas companies amounted to 617 mmBOE. Gazprom was granted an option to acquire a 51% interest in those three gas companies. Should Gazprom exercise the call option, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%. Management believes that Gazprom will likely exercise its call option.


(2)   From 1991 to 2002 DeGolyer and MacNaughton, from 2003 also Ryder Scott.

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The reserve replacement ratio for Eni’s subsidiaries was 38% in 2007 (38% in 2006 and 43% in 2005). The average reserve life index for Eni’s subsidiaries was 9.6 years at December 31, 2007. The reserve 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 SFAS No. 69 – See supplemental oil and gas information in Note 39 to the Consolidated Financial Statements. The reserve replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by reserve additions booked according with SEC criteria under Rule 4-10 of Regulation S-X. Management considers the reserve replacement ratio to be an important measure of the ability of the Company to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate development and production 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 infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks. Specifically, in recent years Eni’s performance in replacing produced reserves has been affected by the impact of higher year-end oil prices on reserves entitlements in the Company’s Production Sharing Agreements (PSAs) 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.

The table below show Eni’s calculations of its reserve replacement ratios for the years ended December 31, 2005, 2006 and 2007.

 

Subsidiaries

 

Equity-accounted entities

 
 
 

2005

 

2006

 

2007

 

2005

 

2006

 

2007

 
 
 
 
 
 
  (mmBOE)
Additions to proved reserves   271     244     237     (18 )   1     639  
of which purchases and sales of reserves-in-place   106     (172 )   156                 617  
Production for the year   (629 )   (640 )   (627 )   (5 )   (6 )   (7 )
 
 
 
 
 
 

 

 

Subsidiaries

 
 

2005

 

2006

 

2007

 
 
 
  (%)
Proved reserves replacement ratio of subsidiaries 43   38   38
 
 
 

Proved developed reserves of subsidiaries at December 31, 2007 amounted to 3,862 mmBOE (1,953 mmBBL of liquids and 10,967 BCF of natural gas), representing 64% of total estimated proved reserves (63% and 63% at December 31, 2006 and 2005, respectively).

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 676 mmBOE as of December 31, 2007 (583 and 604 mmBOE as of December 31, 2006 and 2005, respectively). Said volumes are not included in reserves volumes shown in the table herein.

The tables below set forth a geographical breakdown of Eni’s proved reserves and proved developed reserves of hydrocarbons, on a barrel of oil equivalent basis, for the periods indicated.

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Proved reserves

Eni’s proved reserves of hydrocarbons by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (mmBOE)
Italy   868   805   747
North Africa   2,026   2,018   1,879
West Africa   1,279   1,122   1,095
North Sea   758   682   617
Caspian Area   1,087   1,219   1,061
Rest of the World   778   554   611
Total consolidated subsidiaries   6,796   6,400   6,010
Equity-accounted entities   41   36   668
   
 
 

Eni’s proved reserves of liquids by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (mmBBL)
Italy   228   215   215
North Africa   961   982   878
West Africa   936   786   725
North Sea   433   386   345
Caspian Area   778   893   753
Rest of the World   412   195   211
Total consolidated subsidiaries   3,748   3,457   3,127
Equity-accounted entities   25   24   142
   
 
 

Eni’s proved reserves of natural gas by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (BCF)
Italy   3,676   3,391   3,057
North Africa   6,117   5,946   5,751
West Africa   1,965   1,927   2,122
North Sea   1,864   1,697   1,558
Caspian Area   1,774   1,874   1,770
Rest of the World   2,105   2,062   2,291
Total consolidated subsidiaries   17,501   16,897   16,549
Equity-accounted entities   90   68   3,022
   
 
 

Eni’s proved developed reserves of hydrocarbons by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (mmBOE)
Italy   620   562   534
North Africa   1,230   1,242   1,183
West Africa   793   798   766
North Sea   611   571   524
Caspian Area   548   525   494
Rest of the World   473   334   361
Total consolidated subsidiaries   4,275   4,032   3,862
Equity-accounted entities   31   27   101
   
 
 

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Eni’s proved developed reserves of liquids by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (mmBBL)
Italy   149   136   133
North Africa   697   713   649
West Africa   568   546   511
North Sea   353   329   299
Caspian Area   266   262   219
Rest of the World   298   140   142
Total consolidated subsidiaries   2,331   2,126   1,953
Equity-accounted entities   19   18   26
   
 
 

Eni’s proved developed reserves of natural gas by geographic area

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (BCF)
Italy   2,704   2,449   2,304
North Africa   3,060   3,042   3,065
West Africa   1,289   1,447   1,469
North Sea   1,484   1,395   1,293
Caspian Area   1,618   1,511   1,580
Rest of the World   1,004   1,105   1,256
Total consolidated subsidiaries   11,159   10,949   10,967
Equity-accounted entities   70   48   428
   
 
 


Mineral Right Portfolio and Exploration
Activity for the year

As of December 31, 2007, Eni’s mineral right portfolio consisted of 1,220 exclusive or shared rights for exploration and development in 36 countries on five continents, for a total net acreage of 394,490 square kilometers (385,219 at December 31, 2006). Of these, 37,642 square kilometers concerned production and development (48,273 at December 31, 2006). Outside Italy net acreage (373,826 square kilometers) increased by 11,103 square kilometers mainly due to the acquisition of assets in Angola, Congo, Russia and the Gulf of Mexico, as well as exploration property in Australia, India, Nigeria, Pakistan, the United Kingdom and Alaska. In Italy, net acreage (20,664 square kilometers) declined by 1,832 square kilometers due to releases.

A total of 81 new exploratory wells were drilled in 2007 (43.5 of which represented Eni’s share), as compared to 68 exploratory wells completed in 2006 (35.9 of which represented Eni’s share). In addition, 28 exploratory wells were in progress at year end. The overall commercial success rate was 40% (38% net to Eni) as compared to 43% (49% net to Eni) in 2006. In 2005, 52 exploratory wells were completed (21.8 of which represented Eni’s share), with an overall success rate of 39.3% in 2005 (the success rate of Eni’s share of exploratory wells was 47.4%).

 

Production

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 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 2007, oil and natural gas production available for sale averaged 1,684 KBOE/d (liquids 1,020 KBBL/d; natural gas 3,819 mmCF/d), a decrease of 36 KBOE/d, or 2.1%, compared to 2006 mainly due to disruptions in Nigeria due to continuing social unrest (down 25 KBOE/d), unplanned downtime and technical issues in the North Sea and mature field declines, particularly in Italy and the United Kingdom, as well as price impacts in certain PSAs. Production performance for the year was also impacted by Venezuela’s expropriation of the Dación oilfield

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assets which took place on April 1, 2006 (down 15 KBBL/d over 2006). These negative factors were offset in part by the contribution of acquired assets in the Gulf of Mexico and Congo (up 45 KBOE/d on annual average) and production increases in Libya, Egypt and Kazakhstan. Oil and natural gas production share outside Italy was 88% (as compared to 87% in 2006).

Production of liquids (1,020 KBBL/d) decreased by 59 KBBL/d, or 5.5%, compared to 2006. Production decreases were reported mainly in Nigeria, Venezuela and the United Kingdom due to the above-mentioned causes. The most significant increases were registered in: (i) the United States due to the contribution of purchased assets and the resumption of full activity at plants damaged by hurricanes in the second half 2005; (ii) Egypt, as a result of production ramp-up at the el Temsah fields; and (iii) Kazakhstan due to a better performance of the Karachaganak field.

Production of natural gas available for sale (3,819 mmCF/d) in 2007 increased over 2006 by 140 mmCF/d, or 3.8%, mainly in Libya, as a result of the build-up of the Western Libyan Gas Project; the Gulf of Mexico, due to the contribution of acquired assets; Norway, particularly at the Aasgard (Eni’s interest 14.81%) and Kristin (Eni’s interest 8.25%) fields. Gas production decreased due to mature field declines in Italy and the United Kingdom.

Oil and gas production sold in 2007 amounted to 611.4 mmBOE. Approximately 61% of liquids production sold (370.3 mmBBL) was destined to Eni’s Refining & Marketing segment; 37% of natural gas production sold (1,385 BCF) was destined to Eni’s Gas & Power segment.

The tables below set forth Eni’s production of liquids and natural gas on an available-for-sale basis for the periods indicated.

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (KBBL/d)
Liquids production (1)            
Italy   86   79   75
North Africa   308   329   337
West Africa   310   322   280
North Sea   179   178   157
Caspian Area   64   64   70
Rest of the World   164   107   101
Total   1,111   1,079   1,020
   
 
 

(1)   Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 7, 8 and 8 KBBL/d in 2007, 2006 and 2005 respectively.

 

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (mmCF/d)
Natural gas production available for sale (1) (2)            
Italy   972   883   763
North Africa   900   1,187   1,357
West Africa   151   232   220
North Sea   563   557   557
Caspian Area   207   214   222
Rest of the World   551   606   700
Total   3,344   3,679   3,819
   
 
 

(1)   Data includes Eni’s share of production of affiliates and joint venture accounted for under the equity method of accounting amounting to 28, 31 and 38 mmCF/d in 2007, 2006 and 2005 respectively.
(2)   Excluding production volumes of natural gas consumed in operations. Said volumes were 251, 286 and 296 mmCF/d in 2005, 2006 and 2007, 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 75 KBOE/d, 57 KBOE/d and 20.5 KBOE/d in 2007, 2006 and 2005, respectively.

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The table below sets forth certain information and operating data regarding Eni’s principal oil and natural gas interests as of December 31, 2007.

Principal oil and natural gas interests at December 31, 2007

   

Commencement of operations

 

Number of interests

 

Gross exploration
and development acreage
(1)

 

Net exploration
and development acreage
(1)

 

Net development acreage (1)

 

Type of fields

 

Number of producing fields

 

Number of other fields

   
 
 
 
 
 
 
 
Italy  

1926

 

162

 

25,991

 

20,664

 

12,582

 

Onshore/Offshore

 

82

 

103

                                 
North Africa                                
Algeria  

1981

 

36

 

11,432

 

3,041

 

902

 

Onshore

 

24

 

14

Egypt  

1954

 

56

 

24,443

 

14,469

 

3,011

 

Onshore/Offshore

 

34

 

30

Libya  

1959

 

16

 

37,749

 

33,289

 

796

 

Onshore/Offshore

 

12

 

14

Tunisia  

1961

 

11

 

6,464

 

2,274

 

1,558

 

Onshore/Offshore

 

19

 

3

       

119

 

80,088

 

53,073

 

6,267

     

89

 

61

                                 
West Africa                                
Angola  

1980

 

55

 

20,527

 

3,570

 

1,398

 

Offshore

 

42

 

27

Congo  

1968

 

24

 

11,099

 

4,905

 

968

 

Offshore

 

19

 

7

Nigeria  

1962

 

50

 

44,049

 

7,756

 

5,715

 

Onshore/Offshore

 

83

 

51

       

129

 

75,675

 

16,231

 

8,081

     

144

 

85

                                 
North Sea                                
Norway  

1965

 

49

 

15,335

 

5,390

 

123

 

Offshore

 

13

 

7

United Kingdom  

1964

 

88

 

5,445

 

1,239

 

610

 

Offshore

 

36

 

11

       

137

 

20,780

 

6,629

 

733

     

49

 

18

                                 
Caspian Area  

1995

 

6

 

4,933

 

959

 

488

 

Onshore/Offshore

 

1

 

5

                                 
Rest of world                                
Australia  

2001

 

19

 

62,510

 

31,544

 

891

 

Offshore

 

2

 

1

Brazil  

1999

 

4

 

2,920

 

2,774

     

Offshore

       
China  

1983

 

3

 

632

 

103

 

103

 

Offshore

 

10

 

3

Croatia  

1996

 

2

 

1,975

 

988

 

988

 

Offshore

 

5

 

5

East Timor  

2006

 

5

 

12,224

 

9,779

     

Offshore

       
Ecuador  

1988

 

1

 

2,000

 

2,000

 

2,000

 

Onshore

 

1

   
India  

2005

 

3

 

24,425

 

9,091

     

Onshore/Offshore

       
Indonesia  

2001

 

10

 

27,999

 

16,047

 

656

 

Onshore/Offshore

 

7

 

8

Iran  

1957

 

4

 

1,456

 

820

 

820

 

Onshore/Offshore

 

3

   
Pakistan  

2000

 

22

 

38,426

 

21,155

 

601

 

Onshore/Offshore

 

6

 

3

Russia  

2007

 

4

 

5,126

 

3,076

 

1,168

 

Onshore

 

3

 

6

Saudi Arabia  

2004

 

1

 

51,687

 

25,844

     

Onshore

       
Trinidad & Tobago  

1970

 

1

 

382

 

66

 

66

 

Offshore

 

2

 

3

United States  

1968

 

558

 

10,619

 

6,024

 

937

 

Onshore/Offshore

 

63

 

13

Venezuela  

1998

 

3

 

1,556

 

614

 

145

 

Offshore

     

1

       

640

 

243,937

 

129,925

 

8,375

     

102

 

43

Other countries      

9

 

6,311

 

1,364

 

1,116

 

Offshore

       
Other countries with only exploration activity      

18

 

299,568

 

165,646

     

Onshore/Offshore

       
Outside Italy      

1,058

 

731,292

 

373,827

 

25,060

     

385

 

212

Total      

1,220

 

757,283

 

394,491

 

37,642

     

467

 

315

   
 
 
 
 
 
 
 

(1)   Square kilometers.

Eni’s principal regions of operations are described below. In the discussion that follows references to hydrocarbon production are to be intended to hydrocarbon production available for sale.

Italy

Eni has been operating in Italy since 1926. In 2007, Eni’s oil and gas production amounted to 208 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.

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The Adriatic Sea represents Eni’s main production area in Italy, accounting for 30% of Eni’s domestic production in 2007. Production is composed mainly of natural gas. Main operated fields are Barbara (155 mmCF/d net to Eni), Angela-Angelina (64 mmCF/d), Porto Garibaldi (57 mmCF/d) and Cervia (46 mmCF/d).

Eni is operator of the Val d’Agri concession (Eni’s interest 60.77%) in Basilicata Region, Southern Italy, resulting from the unitization of the Volturino and Grumento Nova concessions made in late 2005. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is fed by 22 production wells of the 47 foreseen by the sanctioned development plan and is supported by the Viggiano oil center with a treatment capacity of 104 KBBL/d. Oil produced is carried to Eni’s refinery in Taranto via a 136-kilometer long pipeline. In 2007, the Val d’Agri concession produced 106 KBOE/d (65 net to Eni) corresponding to 31% of Eni’s production in Italy.

Eni is operator of 15 production concessions onshore and offshore Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2007 accounted for 9% of Eni’s production in Italy.

In 2007, production started at: (i) Fiumetto-4 well and Pizzo Tamburino concessions in the onshore of Sicily, with production at 600 BOE/d and 1,000 BOE/d, respectively; (ii) Tea/Arnica/Lavanda field in the Adriatic Sea, with production peaking at 35 mmCF/d and which was linked to Ravenna Mare power station; and (iii) Candela field in the Puglia Region, with production at 3,531 CF/d. The first development phase was completed through linking of existing facilities.

In 2007, development activities concerned in particular: (i) optimization of producing fields by means of sidetracking and infilling (Gela, Gagliano, Cervia, Barbara, Bonaccia and Emma); and (ii) continuation of drilling and upgrading of producing facilities in the Val d’Agri.

The main ongoing development project is Miglianico, located in the onshore of the Abruzzi Region. Three development wells have been drilled. The project provides for the construction of facilities to treat production volumes of oil, to be delivered to logistic structures of the Refining & Marketing segment. The production volumes of gas will be input into Italian natural gas transportation network. Production is expected to start in the second half of 2009, peaking at 7 KBOE/d.

 

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In the medium term, management expects production in Italy to remain stable at current level due to the production ramp-up of the Val d’Agri fields and ongoing new field project and continuing development activities designed to counteract mature field decline.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2007, North Africa accounted for 34% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2007, Eni’s oil production in Algeria averaged 85 KBOE/d. Operating activities are located in the Bir Rebaa area in the South-Eastern desert and include the following exploration and production blocks: (a) Blocks 403 a/d (Eni’s interest 100%); (b) Blocks 401a/402a (Eni’s interest 55%); (c) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); and (d) Blocks 212 (Eni’s interest 22.38%) and 208 (Eni’s interest 12.25%).

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

Production in Block 403a/d is supplied mainly by the HBN and Rom and satellite fields and accounted for approximately 23% of Eni’s production in Algeria in 2007. The main project underway is the Rom Integrated project, designed to develop the reserves of the Rom Main (Eni’s interest 100%), ZEA (Eni’s interest 75%) and Rom Nord fields. The project provides for the construction of a new oil treatment plant with a capacity of 32 KBBL/d. First oil is expected in 2011.

Production in Blocks 401a/402a is supplied mainly by the Rod and satellite fields and accounted for approximately 22% of Eni’s production in Algeria in 2007. Infilling activities are being performed in order to maintain the current production plateau.

The main fields in Block 403 are BRN, BRW and BRSW and accounted for approximately 14% of Eni’s production in Algeria in 2007. Extensive exploration activity is being performed. In October 2007, Eni and the Algerian state company Sonatrach signed an agreement for the renewal of the development and production concession on this block.

Block 208 is located South of Bir Rebaa. The El Merk Synergy plan for the development of this block in conjunction with the development of adjoining blocks operated by other companies is the main project underway in Algeria. The project scheme provides for the construction of a Central Production Facility. Start-up is expected after 2011. In 2007, basic engineering work was completed.

In 2006, Sonatrach requested international oil companies, including Eni, to renegotiate the economic terms of certain PSAs in light of certain changes enacted in the tax regime applicable to oil activities. Although tax terms applicable to existing PSAs partied by international oil companies have not been modified, Sonatrach asserts that it is currently bearing higher taxation on behalf of foreign oil companies. On this basis, Sonatrach intends to renegotiate the economic terms of those PSAs, particularly Blocks 401a/402a (Eni’s interest 55%), 404 (Eni’s interest 12.25%) and 208 (Eni’s interest 12.25%), in order to restore the initial economics of such contracts. At present, management is not able to foresee the final outcome of such renegotiations.

In the medium term, management expects production in Algeria to decline slightly due to mature fields decline.

Egypt. Eni has been present in Egypt since 1954. In 2007, Eni’s share of production in this country amounting to 231 KBOE/d and accounted for 14% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Belayim concession (Eni’s interest 100%) offshore in the Gulf of Suez. Gas production mainly comes from the operated or participated concession of North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (50% interest), Ras el Barr (50% interest, non-operated) and el Temsah (50% interest) offshore the Nile Delta. In 2007, production from these concessions also including a portion of liquids accounted for 90% of Eni’s production in Egypt.

Exploration and production activities in Egypt are regulated by concession contracts and PSAs.

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Development activities are underway in the offshore area of the Nile Delta: (i) in the North Port Said concession (Eni’s interest 100%), production started at the Semman gas field. Production is expected to peak at 46 mmCF/d net to Eni. Development activities at the el Gamil plant progressed by increasing compression capacity to support the el Temsah and Ras el Barr production concessions; (ii) in the Ras el Barr concession (Eni’s interest 50%), development activities of the Taurt field are underway. This project provides the drilling of production wells which are expected to be linked by sealines and umbilicals to existing onshore treatment facilities. Production is expected to start in second half of 2008; and (iii) in the el Temsah concession (Eni operator with a 50% interest), production started at the Denise A platform. The production build-up is expected to be completed in the first half of 2008.

Through its affiliate Unión Fenosa Gas, Eni has an indirect participation in the Damietta natural gas liquefaction plant with a producing capacity of 5 mmtonnes/y of LNG corresponding to approximately 268 BCF/y of feed-gas. Eni is currently supplying 53 BCF/y to the first unit for a twenty-year period. Future supplies will be secured by developing the Taurt and Denise fields which are expected to supply 23 KBOE/d of feed-gas to the first unit. The partners of this project are planning to double the plant capacity by means of the construction of a second train seen operating in 2011. Eni will supply 88 BCF/y to the second train for a twenty-year period. The reserves which are destined to feed this second train have already been identified, including any additional amounts that must be developed to meet the country’s domestic requirement under existing laws. The approval from relevant Egyptian Authorities is expected in the first half of 2008.

In April 2008, Eni signed a memorandum of understanding relating to the thermoelectric sector in Egypt, where the Company will provide its technology for the combined production of electricity and steam from gas-fired plants.

Main discoveries for the year were achieved in: (a) the offshore area of the Nile Delta with the Satis-1 discovery well (Eni’s interest 50%), showing the presence of significant amounts of gas at a depth of over 6,500 meters, as well as the Andaleeb-1 and Aten-1 discovery wells (Eni’s interest 100%); (b) the onshore area of the Western Desert with two near field discoveries in the Melehia (Eni’s interest 56%) and West Razzak (Eni’s interest 80%) development permits and in the East Obayed exploration permit (Eni’s interest 100%) with in Faramid-1 exploration well; and (c) the Gulf of Suez with near field discoveries in the offshore Belayim Marine permit (Eni’s interest 100%). These ongoing exploration activities aim at supporting the expansion plan of the Damietta LNG plant.

In the medium term, management expects to increase Eni’s production in Egypt to approximately 240 KBOE/d reflecting ongoing development of gas reserves, despite expected mature oil field declines.

Libya. Eni started operations in Libya in 1959. In 2007, Eni’s oil and gas production averaged 242 KBOE/d, the portion of liquids being 58%. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan desert area.

 

   

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In October 2007, Eni signed a major petroleum agreement with NOC, the Libyan National Oil Corporation. The agreement provides the extension of Eni’s mineral rights in Libya until 2042 and 2047 for oil and gas properties respectively, and the launch of large projects in gas monetization and exploration. This agreement will enable Eni to efficiently develop its long-life producing fields over a long time frame by applying its advanced techniques for maximizing the recoverability of hydrocarbons. The projects defined by the agreement regard: (i) overhauling the exploration activities in high-potential areas where Eni is already present; (ii) monetizing additional and substantial gas reserves through the upgrading of the GreenStream export pipeline, achieving an additional transport capacity of 106 BCF/y and the construction of a new LNG plant near Mellitah designed to produce 177 BCF/y, equivalent of LNG to be marketed worldwide. Under this agreement, the properties owned by Eni have been grouped into six contract areas (onshore and offshore) regulated according to Production Sharing Agreements. Onshore, the following areas have been identified: (i) Area A, including the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 and the NC 125 field (Eni’s interest 50%); (iii) Area E, with Block NC 174 (Eni’s interest 33.3%); and (iv) Area F, with Block 118 (Eni’s interest 50%). Offshore 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) that feed the Western Libyan Gas Project (Eni’s interest 50%).

In the exploration phase, Eni is operator of four onshore blocks in the Muzurk basin (161/1, 161/2&4, 176/3) an in the Kufra area (186/1, 2, 3 & 4).

In May 2007, the Government of Libya issued a tax law that amended the profit taxation regime for foreign oil companies operating under PSA schemes. In line with past practice, Libya’s National Oil Company (NOC) was designated as tax agent on behalf of foreign oil companies operating under PSA. The new tax regime is expected to become effective from 2008, after receiving instructions from NOC on the determination of the asset tax base recognized at January 1, 2008 (which instructions might result in an adjustment of related deferred tax liabilities). Eni does not expect the adoption of the new law to have a significant impact on the agreed oil profit share under PSAs currently existing between the Libyan state company and Eni.

As a part of the Western Libyan Gas project (Eni’s interest 50%), ongoing projects to upgrade production facilities aim at increasing current natural gas production by 35 BCF/y and supporting current oil production plateau of the Wafa field. Export of natural gas leverages on the GreenStream pipeline, which delivered 313 BCF in 2007. In addition, 29 BCF were sold on the Libyan market for power generation. In 2007, the production of the Wafa and Bahr Essalam fields was 154 KBOE/d net to Eni (up 36% from 2006).

Other ongoing development projects regarded the ANC118 field (Eni’s interest 50%) by linking it to existing facilities at the Wafa and Mellitah plants and the monetization of gas volumes currently flared at the Bouri field (Eni’s interest 50%) by processing at the Sabratha platform and exporting them via the GreenStream pipeline.

 

Main discoveries for the year were achieved in: (a) offshore Block NC41 (Eni’s interest 100%), where the U1-NC41 discovery well showed the presence of oil and natural gas at a depth of over 2,600 meters; and (b) onshore concession 82 (Eni’s interest 50%), where the YY1-82 discovery well showed the presence of oil at a depth of about 5,000 meters.

In the medium term, management expects to increase Eni’s production in Libya owing to the expected ramp-up of new mineral structures near the Western Libyan Gas Project fields, despite mature field declines.

Tunisia. Eni has been present in Tunisia since 1961. In 2007, Eni’s production amounted to 15 KBOE/d. Eni’s activities are located mainly in the Mediterranean offshore facing Hammamet and in the Southern desert areas.

Exploration and production in this country are regulated by concessions and Production Sharing Agreements.

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Production mainly comes from 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. In 2007, the development of Maamoura offshore field was sanctioned. Production is expected to start in 2009 and flow at 7 KBOE/d.

Main discoveries in 2007 were achieved in: (i) the Adam concession, where the Karma-1 and Ikhil-1 exploration wells found oil and the Nadir-1 exploration well showed the presence of gas. The three wells were linked to existing production facilities; (ii) the Bordi el Khadra permit, where the Nakhil 1 exploration well showed an oil formation and was linked to existing production facilities; and (iii) the Larich concession, where the Larich SW-1 exploration well showed the presence of oil and gas.

In the medium term Eni expects production in Tunisia to increase due to the development of recent discoveries.

West Africa

Eni’s operations in West Africa are conducted in Angola, Congo and Nigeria. In 2007, West Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas.

Angola. Eni has been present in Angola since 1980. In 2007, Eni’s production averaged 132 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

The main blocks participated by Eni are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) west of the Angolan coast; (ii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iii) 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 minor concessions, in particular in some areas of Block 3 (with interests varying from 12 to 15%) and in the 14K/A IMI Unit Area (Eni’s interest 10%). In the exploration phase, Eni is operator of Block 15/06 (with a 35% interest) and holds interests in Block 3/05-A with a 12% interest.

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

In November 2007, Eni acquired a 13.6% stake in the Angola LNG Ltd Consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers North of Luanda. This facility will be designed to produce 5.2 mmtonnes/y of LNG by processing 1 BCF/d of natural gas. The project has been sanctioned by the Angolan Government and Parliament and will develop significant amounts of gas reserves along a 30-year period. The project has high environmental value since it allows the collection of the associated gas from offshore production blocks, in compliance with the zero flaring policy. The LNG is expected to be delivered to the U.S. market at the re-gasification plant in Pascagoula, in the Gulf of Mexico, in which Eni, following this agreement, has acquired a re-gasification capacity equivalent to approximately 177 BCF/y.

 

In December 2007, Eni finalized another agreement to be part of a second gas consortium which will evaluate existing gas discoveries and explore further potential in the Angolan offshore to support the feasibility of a second LNG train. Eni is technical operator, with a 20% interest.

Development activities at the Landana and Tombua oil fields in offshore Block 14 progressed, achieving early production at the Landana field which was linked to existing facilities at Benguela/Belize. Production is expected to peak in 2009 at 130 KBBL/d (23 net to Eni).

Development of the Banzala oil field in Block 0 in Cabinda moved forward with the installation of the two scheduled production platforms, which had been previously started up in June 2007 and in January 2008, respectively. Production is expected to peak in 2009 at 27 KBBL/d (3 KBBL/d net to Eni).

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As part of Phase C of the development of reserves in the Kizomba deep offshore area, development activities of the Mondo and Saxi/Batuque fields in Block 15 are ongoing. A common development strategy is expected to be deployed in both projects, envisaging the installation of FPSO vessels. In January 2008, the Mondo field was started up. The Saxi/Batuque fields are expected to start-up in 2008. Peak production at 100 KBBL/d (18 net to Eni) is expected in 2008 and 2009, respectively. In September 2007, production started at the Marimba field by linking to existing facilities at Kizomba A. Production is expected to peak in 2008 at 39 KBBL/d (7 KBBL/d net to Eni).

Main oil discoveries were made in Block 14, with the Lucapa-1, Menongue-1 and Malange-1 wells and in Block 15/06 with the Sangos 1 discovery well.

In the medium term, management expects to increase Eni’s production to approximately 130 KBBL/d reflecting contributions from ongoing development projects, despite mature field declines.

Congo. Eni has been present in Congo since 1968 and its activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. In 2007, production averaged 67 KBOE/d net to Eni.

In April 2007, an agreement was signed awarding to Eni the Marine XII exploration permit (Eni operator with a 90% interest) offshore Congo. The goal of the initiative is to exploit the relevant gas potential and feeding a power plant.

In May 2007, Eni closed the acquisition of exploration and production assets from the French company Maurel & Prom onshore Congo, for a cash consideration of approximately for euro 1 billion. Acquired properties brought in an additional production of approximately 17 KBOE/d and proved reserves amounting to approximately 33 mmBOE.

Eni’s principal oil producing interests operated in Congo are the Zatchi (Eni’s interest 65%) and Loango (Eni’s interest 50%) fields and Blocks Marine VI (Eni’s interest 65%) and VII (Eni’s interest 35.75%) as well as the acquired assets including the producing fields of M’Boundi (Eni’s interest 43.1%) and Kouakouala A (Eni’s interest 66.67%). In 2008, Eni’s working interest in the M’Boundi field will reach 80.1% due to the acquisition of Burren Energy finalized early in 2008.

Eni holds a 35% interest in the Pointe Noire Grand Fonde and Pex permits. Eni also holds interests in the exploration phase in three deep offshore blocks: Mer Très Profonde Nord (Eni operator with a 40% interest), Mer Très Profonde Sud (Eni’s interest 30%), Marine X (Eni operator with a 72% interest), and Le Kouilou onshore permit (Eni operator with a 48% interest).

 

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

Development activities of the acquired M’Boundi field moved forward with the revision of the production scheme and layout, as well designing activities regarding application of advanced recovery techniques and associated gas monetization. In particular, Eni signed an agreement with Congolese authorities for doubling the Djeno power plant and building a new power plant to be fired with associated gas produced at the M’Boundi field. These projects are expected to start-up in the second half of 2008 and by end of 2009, respectively.

Development activities at the Awa Paloukou (Eni’s interest 90%) and Ikalou-Ikalou Sud (Eni’s interest 100%) fields are underway. Production is expected to start in 2008, peaking at 13 KBOE/d net to Eni in 2009.

Main oil discoveries were made in Mer Très Profonde Sud permit (Eni’s interest 30%) with the Persée Nord Est-1 well, drilled at a depth between 2,700 and 3,500 meters, and the Cassiopea Est-1 well, drilled at a depth of 2,900 meters and which yielded 5,300 BBL/d in test production.

In the medium term, management expects to increase Eni’s production in Congo due to the contribution from recently acquired assets, targeting a level of 140 KBBL/d in 2011. Key growth drivers will be the integration and development of assets acquired from Maurel & Prom and Burren Energy in addition to projects underway.

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Nigeria. Eni has been present in Nigeria since 1962. In 2007, Eni’s oil and gas production averaged 119 KBOE/d located mainly in the onshore and offshore of the Niger Delta.

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 50.19%), OMLs 120-121 (Eni’s interest 40%) and OML 118 (Eni’s interest 12.5%). Through SPDC JV oil joint venture, Eni also holds a 5% interest in 31 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.

In the exploration phase Eni is operator of Oil Prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 50.19%) and onshore OML 135 (former OPL 219 - Eni’s interest 12.5%) and OPL 282 (Eni’s interest 90%).

In March 2007, Eni signed a Production Sharing Contract for the OPL 135 permit (Eni operator with a 48% interest) located in the Niger Delta. The arrangement with a 25-year term envisages an exploration stage with a five-year term and a subsequent development phase of oil and natural gas reserves located in the proximity of existing facilities and the Kwale/Okpai power station where Eni is operator.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and service contracts where Eni acts as contractor for state owned companies.

The Forcados/Yokri oil and gas fields (Eni’s interest 5%) are currently under development offshore and onshore the Niger Delta. Development is expected to be completed in 2008 as part of an integrated project aiming at providing natural gas supplies to the Bonny liquefaction plant. Offshore production facilities have been installed. The onshore project provides for the upgrading of the Yokri and North/South Bank flowstations and the realization of a gas compressor plant.

Eni holds a 10.4% interest in the Bonny liquefaction plant located in the eastern Niger Delta, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The sixth train has been started in 2007. The seventh unit is being engineered with start-up expected in 2012. 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 a gas supply

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agreement with a 20-year term from the SPDC joint venture and the NAOC JV of OMLs 60, 61, 62 and 63.When fully operational in 2008, supplies will total approximately 3,461 mmCF/d (268 net to Eni). In 2007, Eni’s supplies were 173 mmCF/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 is operator with a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal. This plant is expected to start operating in 2012 with a treatment capacity of 10 mmtonnes/y of LNG corresponding to 618 BCF/y (approximately 64 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas fields in the OMLs 61 and 62 onshore blocks. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 2 mmtonnes/y of LNG capacity. The front end engineering is underway and the final investment decision is expected in the second half of 2008.

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

North Sea

Eni’s operations in the North Sea area are conducted in Norway and United Kingdom. In 2007, the North Sea accounted for 15% of Eni’s total worldwide production of oil and natural gas.

Norway. Eni has been operating in Norway since 1964. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 134 KBBL/d in 2007.

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

Eni holds interests in six production areas in the Norwegian Sea. The main producing fields are Aasgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.12%), Mikkel (Eni’s interest 14.9%) and Norne (Eni’s interest 6.9%), which together accounted for 68% of Eni’s production in Norway. The main structures under development are located near Kristin, particularly Tyrihans (Eni’s interest 6.23%). Economic development of this field is expected to be achieved through synergies with the Kristin production facilities. Production is expected to start in 2009, when production of Kristin is expected to decline which will make spare capacity available to process production from Tyrihans.

Eni holds interest in four production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL018 which in 2007 produced 352 KBOE/d (44 net to Eni) and accounted for 32% of Eni’s production in Norway. Ongoing projects for Ekofisk aim at maintaining and optimizing production by means of infilling wells, the development of the Growth Area and upgrading of existing facilities.

Currently Eni is only performing exploration activities in Barents Sea. Operations in this area are focused on the appraisal of the mineral potential of the large Goliath discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest) aimed at its commercial development. The project is progressing in accordance with the program. The final investment decision is expected in 2008. Critical equipment (rigs) to develop the field has already been booked.

In 2007, Eni sold a 30% stake of the Prospecting License 259 (Eni’s interest 70%) and the whole interest of the Prospecting License 256.

Main discoveries for 2007 were achieved in the: (i) Prospecting License 393 (Eni’s interest 30%), near the Goliath discovery, where the 7125/4-1 Nucula exploration well showed the presence of hydrocarbons at a depth between 800 and 1,450 meters; (ii) Prospecting License 122 (Eni’s interest 20%), the appraisal of the Marulk discovery increased the recognized mineral potential; (iii) Prospecting License 312 (Eni’s interest 17%), where the Gamma discovery well showed the presence of gas at a depth of 2,500 meters; and (iv) the Prospecting License 293 (Eni operator with a 45% interest) the Afrodite discovery well showed the presence of gas and condensates at a depth of 373 meters.

In the medium term, management expects to slightly increase Eni’s production in Norway, reflecting the planned development projects, partly offset by mature field declines.

The United Kingdom. Eni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, in the Irish Sea and in some areas East and West of the Shetland Islands. In 2007, Eni’s net production of oil and gas averaged 120 KBOE/d.

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Exploration and production activities in the United Kingdom are regulated by concession contracts.

Eni holds interests in 12 production areas in the British section of the North Sea. The main fields are Elgin/Franklin (Eni’s interest 21.87%), the J-Block (Eni’s interest 33%), the Flotta Catchment Area (Eni’s interest 20%), Andrew (Eni’s interest 16.2%) and Farragon (Eni’s interest 30%), which in 2007 accounted for 58% of Eni’s production in the United Kingdom. In 2007, production started at the Blane (Eni’s interest 18%) and West Franklin (Eni’s interest 21.87%). The Blane field was linked to existing production facilities with a peak production of 21 KBOE/d (approximately 4 net to Eni) already reached. The West Franklin field was linked to the production facilities of the nearby Elgin Franklin field and is expected to peak at 20 KBOE/d (4 net to Eni) in the second half of 2008 with the scheduled start-up of a second development well. Appraisal of the large Jasmine discovery in the J-Block is underway.

Eni holds interests in six production blocks in the Liverpool Bay area (Eni’s interest 53.9%) in the Eastern section of the Irish Sea. Main fields are Douglas, Hamilton and Lennox and their extensions which in 2007 accounted for 24% of Eni’s production in UK.

Eni holds interest in 6 production permits located East of the Shetland Islands. Main fields are Ninian (Eni’s interest 12.94%) and Magnus (Eni’s interest 5%) which in 2007 accounted for 4% of Eni’s production in the United Kingdom.

Main discoveries in 2007 were in: (a) Block 205/5a (Eni’s interest 23%) with the Tormore discovery, at a depth of 610 meters, which yielded 32 mmCF/d of gas and 2,200 BBL/d of condensates. Production is expected to start through synergies with the adjoining Laggan discovery (Eni’s interest 20%); and (b) the J-Block gas and condensates were found nearby the recent Jasmine discovery. Joint development of these two structures is being assessed in combination with existing facilities.

 

Caspian Area

In 2007, Eni’s operations in the Caspian Area accounted for 6% of its total worldwide production of oil and natural gas.

Kazakhstan-Kashagan. Eni has been present in Kazakhstan since 1992. Eni is the single operator of the North Caspian Sea Production Sharing Agreement (NCSPSA) with a participating interest equal to 18.52% as of December 31, 2007. The other partners of this initiative are Total, Shell and ExxonMobil, each with a participating interest currently of 18.52%, ConocoPhillips currently with 9.26%, and Inpex and KazMunayGas each currently with 8.33%. Each partner’s participating interest in the project will change according to the terms of the Memorandum of Understanding signed among the parties, including the Kazakh authorities, on January 14, 2008. Information on this agreement is included below. The change in participating interests will apply retroactively as of January 1, 2008.

The NCSPSA defines terms and conditions for the exploration and development activities to be performed in the area covered by the contract. The Kashagan field was discovered in the northern section of the contractual area in the year 2000. Management believes this field to contain a large amount of hydrocarbon resources.

As of December 31, 2007, Eni’s proved reserves booked for the Kashagan field amounted to 520 mmBOE, recording a decrease of 76 mmBOE with respect to 2006 mainly due to the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. Proved reserves for the field as of December 31, 2007 were determined according to Eni’s then current participating interest of 18.52%. As part of the agreements defined with the Kazakh Republic, the change of Eni’s interest to 16.81% in 2008 will determine a decrease of approximately 50 mmBBL in Eni’s estimated net proved reserves of the Kashagan field with respect to December 31, 2007.

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As of December 31, 2006, Eni’s proved reserves booked for the Kashagan field amounted to 596 mmBOE, recording an increase of 107 mmBOE with respect to 2005 due to an extension of the proved area and project cost revision, offset in part by the impact of price revisions.

As of December 31, 2007, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $2.6 billion. This capitalized amount included: (i) $1.8 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $0.8 billion relating primarily to accrued 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. The $2.6 billion amount was equivalent to euro 1.8 billion based on the 2007 year-end euro/U.S. dollar exchange rate. As of December 31, 2006 the aggregate costs incurred by Eni for the Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion, corresponding to euro 1.5 billion based on 2006 year-end exchange rates.

Costs borne by Eni to explore and develop this field are recovered in accordance with the mechanisms typically contemplated by a PSA scheme, which is widely used in the industry. In this type of contract the national oil company or State-owned entity assigns to the international oil company (the contractor) the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is generally 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. Accordingly, recoverability of the expenditures is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Similarly, cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement.

To date, costs incurred for the development of the Kashagan oilfield relate to scheduled works and in accordance to the budget duly approved by the Kazakhstan authorities, and are therefore recoverable subject to customary audit rights.

The development plan of the Kashagan field was originally sanctioned by the Kazakh authorities in February 2004, contemplating a three-phase development scheme including partial gas re-injection in the reservoir to enhance the recovery factor of the crude oil. The sanctioned plan budgeted expenditures amounting to U.S. $10.3 billion (in 2007 real terms) to develop phase-one, with a target production level of 300 KBBL/d. First oil was originally scheduled to be produced by the end of 2008. Eni was expected to fund these expenditures according to its participating interest in this project. On June 29, 2007, Eni, as operator, filed with the relevant Kazakh authorities amendments to the sanctioned development plan. These amendments rescheduled the production start-up to 2010 and estimated development expenditures for phase-one at U.S. $19 billion. The production delay and cost overruns were driven by a number of factors: depreciation of the U.S. Dollar versus the Euro and other currencies; cost price 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 off-shore facilities.

In July 2007, the Kazakh authorities rejected the proposed amendments to the sanctioned development plan. In August 2007, the Government of the Kazakh Republic sent to the companies forming the NCSPSA consortium a notice of dispute alleging failure on part of the consortium to fulfil certain contractual obligations and violation of the Republic’s laws. Negotiations commenced with a view to settle this dispute.

On January 14, 2008, all parties to the NCSPSA consortium and the Kazakh authorities signed a memorandum of understanding for the amicable resolution of this dispute. The material terms of the agreement are: (i) the proportional dilution of the participating interest of all the international members of the Kashagan consortium, following which the stake held by the national Kazakh Company KazMunayGas and the stakes held by the other four major shareholders will each be equal to 16.81%. These changes will be effective January 1, 2008. The Kazakh partner will pay the other co-venturers an aggregate amount of U.S. $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPSA, the amount of which will vary in proportion to future levels of oil prices. Eni is expected to contribute to the value transfer package in proportion to its new participating interest in the project; and (iii) an increased role of the Kazakh partner in operations and a new operating and governance model which will entail a greater involvement of the major international partners.

Although the project was not stopped during the negotiation process, its progress slowed down. The NCPSA consortium has presented to the Kazakh authorities a revised budget and schedule for the execution of the phase-one of the project, and the relevant discussions are currently ongoing.

The magnitude of the reserves base, the results of the first four tests conducted on development wells and the subsurface studies completed to date support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer (Ryder Scott Petroleum Consultants) fully supports the target production plateau of the Kashagan field. The achievement of the full field production plateau will require a material

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amount of expenditures in addition to the development expenditures needed to complete the execution of phase-one. However, taking into account that future development expenditures will be incurred over a long time horizon, management does not expect any material impact on the company’s liquidity or its ability to fund these capital expenditures.

In addition to the expenses incurred for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets, for which various options are currently under consideration by the consortium. These include: (i) the use of existing infrastructure, such as the Caspian Pipeline Consortium pipeline (Eni’s interest 2%) and the Atyrau-Samara pipeline, both of which are expected to undergo a capacity expansion; and (ii) the construction of a new transportation system. In this respect, it is worth mentioning the project aimed at building a line connecting the onshore Bolashak production center with the Baku-Tbilisi-Cehyan pipeline (where Eni holds an interest of 5% corresponding to the right to transport 50 KBBL/d).

Kazakhstan-Karachaganak. Located in West onshore Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by Production Sharing Agreement lasting 40 years, until 2037. Eni is co-operator of the venture with 32.5% interest.

In 2007, production from this field averaged 234 KBBL/d of liquids and 743 mmCF/d of natural gas, being 70 KBBL/d and 238 mmCF/d Eni’s share, respectively. This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. This scheme enables to increase the recovery of liquids. Approximately two-thirds of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of 150 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni's interest 2%) and the Atyrau-Samara pipeline. The remaining third of non-stabilized liquid production and volumes of associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg. The plant treatment capacity is being upgraded which will enable to increase exported volumes by 56 KBBL/d from 2009.

In June 2007, the operating consortium and KazRosGaz, a joint company established by KazMunaiGaz and Gazprom, signed a gas sale contract. According to the terms of this agreement, the consortium will deliver, from 2012, approximately 565 BCF/y of raw gas to the Orenburg plant, in Russia. This agreement has created conditions for the start up of Phase 3 of the development project of the field targeting development of natural gas reserves that management believes to amount to significant volumes. The agreement was approved by the Boards of both parties. In this context, in 2007 construction started of the Uralsk gas Pipeline, 150-kilometer long linking from 2009 the field to the Kazakh pipeline network.

As of December 31, 2007, Eni’s proved reserves booked for the Karachaganak field amount to 541 mmBOE, recording a decrease of 82 mmBOE with respect to 2006 as a result of downward and upward revisions of previous estimates. Downward revisions mainly related to an adverse price impact in determining volume entitlements in accordance with the PSA scheme. These negative revisions were partly offset by upward revisions mainly related to the finalization of the gas sale contract as outlined above.

Rest of the World

In 2007, Eni’s operations in the rest of world accounted for 13% of its total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2000. In 2007, Eni’s net production of oil and natural gas averaged 18 KBOE/d. Activities are focused on conventional and deep offshore fields.

The main production blocks in which Eni holds interests are WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Eni’s interest 10.99%). In the exploration phase Eni is operator with a 100% interest of 7 blocks in permits WA-279 P and WA-313-P, where the Blacktip and Penguin fields are located.

 

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In August 2007, Eni signed an agreement to purchase a 30% interest in four exploration blocks in the Exmouth Plateau area in Australia. The four blocks are located at a maximum water depth of 2,000 meters. Eni’s equity interest will increase by 10% after at least one exploration well is drilled. Eni will be the operator during the development phase.

In September 2007, Eni acquired a 40% interest and the operatorship of the JPDA 06-105 exploration permit, located in the international offshore cooperation zone between East Timor and Australia. Two oil discoveries are located in this permit. The exploration plan provides the drilling of a well in 2008.

Exploration and production activities in Australia are regulated by concessions, while in the cooperation zone between East Timor and Australia (JPDA) they are regulated by PSAs.

In the medium term, management expects to increase Eni’s production in Australia through ongoing development activities.

China. Eni has been present in China since 1984. In 2007, Eni’s production amounted to 8 KBOE/d. Activities are located in the South China Sea.

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

Production derives mainly from offshore blocks 16/08 and 16/09 operated by the CACTOG consortium (Eni’s interest 16.33%). Oil production, destined to the domestic market, derives mainly from the HZ26-1 field (Eni’s interest 16.33%) through fixed platforms, one of them underwater, linked to an underwater transport facility to the Zhuhai treatment plant. Ongoing development activities concerned mainly the HZ25-3/1 field with expected start-up in 2009.

Croatia. Eni has been present in Croatia since 1999. In 2007, Eni’s net production of natural gas averaged 51 mmCF/d. Activities are deployed in the Adriatic offshore facing the city of Pula.

Exploration and production activities in Croatia are regulated by PSA.

The main producing gas fields are Ivana, Ika & Ida, Marica and Katerina which operated by Eni through a 50/50 joint venture with the national Croatian oil company.

Development activities of the Annamaria, Irina and Ana/Vesna discoveries are ongoing. A common project is expected to be deployed in all of them, envisaging the installation of production platforms which shall be linked to existing facilities. Start-up is expected in 2009.

India. Eni has been present in India since 2005 and is performing exploration activities in onshore Block RJONN-2003/1 (Eni’s interest 34%) and offshore Blocks AN-DWN-2003/2 (Eni’s interest 40%) and MNDWN 2002/1 (Eni’s interest 34%).

The exploration program for Block RJ-ONN-2003/1, located in the desert of Rajastan, provides drilling of four wells in the first four years of the license. Any hydrocarbons discovered will be sold locally.

The exploration program for Block AN-DWN-2003/2 near the Andaman Islands provides drilling of three wells in the first four years of the license. In 2007, activity concerned the acquisition of seismic data in order to plan the exploration and drilling activity.

Indonesia. Eni has been present in Indonesia since 2000. Eni’s production amounted to 17 KBOE/d, mainly gas, in 2007. Activities are concentrated in the western offshore and onshore of Borneo and offshore Sumatra.

Exploration and production activities in Indonesia are regulated by PSAs.

Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%) with seven production fields. This gas is treated at the Bontang liquefaction plant, the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets. Ongoing activities aim at maintaining the current production plateau by means of infilling wells and the optimization of existing ones.

In January 2007, Eni and Pertamina signed a Memorandum of Understanding aimed at identifying joint development opportunities for exploration and development activities.

Main ongoing projects include the joint development of the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%). Production will be treated at the Bontang LNG plant. The project has not yet been sanctioned by authorities.

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Exploration activity was successful with the Tulip East offshore discovery (Eni’s interest 100%), and an appraisal well of the Aster field (Eni’s interest 66.25%) was drilled and yielded 5 KBOE/d in test production.

Iran. Eni has been present in Iran since 1957. In 2007, production net to Eni averaged 26 KBOE/d. Eni’s activities are concentrated in the offshore of the Persian Gulf and onshore.

Exploration and production activities in Iran are regulated by buy-back contracts.

The main producing fields are South Pars phases 4 and 5 in the offshore of the Persian Gulf and Darquain located onshore which accounted for 88% of Eni’s production in Iran in 2007. Eni also holds interests in the Dorood field (Eni’s interest 45%).

The main ongoing project regards the Darquain field operated by Eni with a 60% interest. Upgrading activities are underway by means of drilling additional wells, increasing capacity of the existing treatment plant and gas-injection. These actions aim at increasing production from the present 50 KBBL/d to over 160 KBBL/d (14 net to Eni) by 2009.

The legislation and other regulations of the United States of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties. Particularly, under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under, ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 8 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country. It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation.

Pakistan. Eni has been present in Pakistan since 2000. In 2007, production net to Eni averaged 50 KBOE/d, mainly gas.

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

Eni’s main permits are Bhit (Eni operator with a 40% interest), Sawan (23.68%) and Zamzama (17.75%), which in 2007 accounted for 90% of Eni’s production in Pakistan.

In 2007, Eni and State oil company PPL signed an agreement providing for a swap of interests in the offshore Blocks M, N and C. Within this agreement, Eni holds 70% interest in the M and N blocks and 60% interest as operator in the C block.

In April 2008, upgrading facilities was completed at the Bhit gas field leading to the start-up of the satellite Badhra field.

Main discoveries for 2007 were achieved in: (a) the Gambat permit (Eni’s interest 30%) where the Tajjal 1 exploration well showed the presence of gas at a depth of 3,845 meters; (b) the Kadanwari permit (Eni operator with a 18.42% interest) where the Kadanwari 18 appraisal well confirmed the presence of gas at a depth of approximately 3,400 meters; and (c) the Latif permit (Eni’s interest 33.3%) where the Latif 1 exploration well discovered a hydrocarbon formation at a depth of 3,520 meters.

Russia. In April 2007, as part of Eni’s strategic alliance with Gazprom, Eni, through the partnership in SeverEnergia (60% Eni, 40% Enel), former EniNeftegaz, acquired assets of Lot 2 as part of the liquidation procedure of bankrupt Russian company Yukos. Eni’s share of cash consideration of this transaction amounted to euro 3.73 billion. Acquired assets included: (i) a 100% interest in three Russian companies (Eni’s share being 60%) operating in the exploration and development of natural gas reserves, OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia with proved reserves amounting to 617 mmBOE net to Eni, as well as certain minor assets that are expected to be sold or liquidated. Eni and Enel granted Gazprom a call option to purchase a 51% interest in these investments to be exercisable within two years from the purchase date. Should Gazprom exercise its call option, Eni’s interest would be diluted to approximately 30% and proved reserves that were booked in connection with the acquisition would be reduced by approximately 50%. These investments are accounted under

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the equity method as Eni jointly controls them based on agreed terms with the other partners. As these entities did not produce any revenue in the year, no significant loss or gain on equity evaluation was recorded in the profit or loss account; and (ii) a 20% interest in OAO Gazprom Neft which was purchased only by Eni. Eni granted Gazprom a call option on this 20% interest in OAO Gazprom Neft to be exercisable within two years from the purchase date. The strike price equals the purchase price plus a contractual remuneration on capital employed, less dividend distributed. This interest is classified as a current asset and assessed at fair value trough profit or loss as provided by the fair value option of IAS 39, considering that the call option is being assessed in the same way. The fair value of OAO Gazprom Neft is based on currently quoted market price as this company is listed at the London Stock exchange. As a result of this accounting treatment, a gain equal to the contractual remuneration of capital employed was recognized in 2007 profit and loss account (net gain of euro 188 million). See Item 5 for a more detailed discussion.

The three acquired gas companies are located in the Yamal Nenets region: (i) OAO Arctic Gas Co owns two exploration licenses, Sambugurskii and Yevo-Yahinskii including seven fields currently in the appraisal/development phase. Main fields are Sambugorskoye currently under development and production testing and Urengoiskoye; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensate field; and (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chasselskoye field.

During 2007, certain activities were executed in order to set up the operational organization and take control of existing assets. An overall plan was assessed to complete and start acquired assets. Ongoing development activities moved forward bringing the wells to a sufficient level of safety and assessing resumption of construction of production and transportation facilities, as well as defining a seismographic activity. Finalization of the gas sale contracts is underway.

Saudi Arabia. Eni has been present in Saudi Arabia since 2004. Ongoing activities concern exploration of the so-called C area in order to discover and develop gas reserves. This license is located in the Rub al Khali basin at the border with Qatar and the United Arab Emirates. The exploration plan provides for the drilling of four wells in five years. In case of a commercial discovery, the contract will last 25 years with a possible extension to a maximum of 40 years. Any gas discovered will be sold locally for power generation and as feedstock for petrochemical plants. Condensates and NGL will be sold on international markets. Drilling of the second commitment exploratory well is underway.

United States. Eni has been present in the United States since 1966. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore Alaska.

In 2007, Eni’s oil and gas production deriving only from the Gulf of Mexico averaged 68 KBOE/d, significantly growing from 2006 (up 114%) due to the acquisition of producing assets from Dominion Resources. This acquisition closed in July 2007 with an outlay of euro 3.5 billion. Acquired properties brought in an additional production of approximately 75 KBOE/d and proved reserves amounting to 123 mmBOE.

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

Eni holds interests in 400 exploration and production blocks in the Gulf of Mexico, 60% operated.

In October 2007, following an international bid procedure Eni was awarded 26 new exploration licenses in the Gulf of Mexico, covering a gross acreage of 606 square kilometers.

In March 2008, following an international bid procedure Eni was awarded 32 exploration leases. The subsequent development phase will leverage synergies relating to proximity of acquired acreage to existing operated facilities. Formal assignation is subject to approval by the relevant authorities.

The main fields operated by Eni with a 100% interest are Allegheny, East Breaks and Morphet as well as assets acquired from Dominion Resources including Devils Towers, Triton and Goldfinger (Eni operator with a 75% interest). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and King Kong (Eni operator with a 56% interest) fields.

Development of acquired assets in the year allowed the start-up of production at the San Jacinto (Eni is operator with a 53.3% interest), Q (Eni’s interest 50%) and Spiderman (Eni’s interest 36.7%) fields. Development of these fields was performed by installing underwater facilities to link to the Independence Hub platform. The production plateau of approximately 25 KBOE/d has been reached at the end of 2007. Main projects include the development of reserves at the Longhorn discovery (Eni’s interest 75%) trough installing production platform. Production is expected to start in 2009 peaking at 28 KBOE/d (approximately 19 net to Eni).

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Exploration activity was successful with the Kodiak oil and gas discovery (Eni’s interest 25%) that will be developed trough the facilities of the operated Devil’s Tower platform.

Eni’s activities in Alaska are currently in the exploration and development phase in 158 blocks with interests ranging from 10 to 100%, over half as operator.

In February 2008, following an international bid procedure Eni was awarded 18 exploratory license in Alaska, 4 blocks as operator. Formal assignation is subject to approval by the relevant authorities.

In April 2007, Eni acquired 70% and the operatorship of the Nikaitchuq field, located offshore on the North Slope of Alaska. Eni, which already owned a 30% stake in the field, now retains the 100% working interest. Nikaitchuq will be the first development project operated by Eni in Alaska. In October 2007, the phased development plan was sanctioned by the authorities. Production is expected to start at the end of 2009 with production plateau at 25 KBOE/d in 2014.

Main projects include the development of reserves at the offshore Oooguruk field (Eni’s interest 30%) in the Beaufort Sea. Production is expected to start in the second half of 2008 peaking at 17 KBOE/d (5 KBOE/d net to Eni) in 2010.

 

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In the medium term, management expects to increase Eni’s production reflecting the development and integration of assets acquired and the start-up of fields in Alaska.

Venezuela. Eni has been present in Venezuela since 1998.

In June 2007, Eni signed a memorandum of understanding with national state-owned company PDVSA which defines the terms for the transfer of the development activity of the Corocoro field in Venezuela to the new contractual regime of "empresa mixta". Eni will retain its 26% interest in this project. On December 5, 2007, the agreement was finalized. First oil was achieved in the first quarter of 2008. Production is expected to peak at 66 KBBL/d (17 KBBL/d net Eni).

In February 2008, Eni and the Venezuelan Authorities reached a final settlement over the dispute regarding the expropriation of the Dación field which took place on April 1, 2006. Under the terms of the settlement, Eni will receive cash compensation to be paid in seven yearly installments. This cash compensation is not subject to Venezuelan taxation and yields interest income from the date of the settlement. The net present value of this cash compensation is in line with the book value of assets, net of the related provisions. In February 2008, Eni dropped the international arbitration proceeding commenced in 2006 against PDVSA.

In February, 2008 Eni and PDVSA signed a strategic agreement for the development of the Junin Block 5 located in the Orinoco oil belt. This block covers a gross acreage of 670 square kilometers. Once relevant studies have been performed and a development plan defined, a joint venture between PDVSA (60%) and Eni (40%) will be established to execute the project. Eni intends to contribute its experience and leading technology to the project in order to maximize the value of the heavy oil. In particular, it will make available its EST (Eni Slurry Technology) proprietary technology. This is a highly innovative technology for the complete conversion of heavy oils into high-quality light products.

 

Capital Expenditures

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

 

Storage

Natural gas storage activities are performed by Stoccaggi Gas Italia SpA (Stogit) to which such activity was conferred on October 31, 2001 by Eni SpA and Snam SpA, in compliance with Article 21 of Legislative Decree No. 164 of May 23, 2000, which provides for the separation of storage from other activities in the field of natural gas.

Storage services are provided by Stogit through eight storage fields located in Italy, based on ten storage concessions3 vested by the Ministry of Productive Activities.

In 2007, the share of storage capacity used by third parties was 56%. From the beginning of its operations, Stogit markedly increased the number of customers served and the share of revenues from third parties; the latter, from a non-significant value, passed to 43%.

Storage  

2005

 

2006

 

2007

   
 
 
Available capacity:                
- modulation and mineral   (BCM)   7.5   8.4   8.5
  . share utilized by Eni   (%)   44   54   44
- strategic   (BCM)   5.1   5.1   5.1
Total customers   (No.)   35   38   44
   
 
 

(3)    Two of these are not yet operational.

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Gas & Power

Eni’s Gas & Power segment involves supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets.

Eni’s strategy in its Gas & Power segment is to grow international sales, preserve the profitability of Italian gas marketing operations, increase operational efficiency and effectiveness mainly in regulated businesses (i.e., Italian transport and distribution activities), and develop a global LNG business.

In the future, management expects that natural gas will satisfy an increasing portion of global energy needs. According to Eni’s internal estimates, worldwide gas demand will grow at an annual rate of approximately 2.8% through 2020, outpacing the expected annual growth rate in total energy consumption.

In Europe, Eni expects gas demand to grow at an average annual rate of 2-3% by 2020, reaching an amount of 780 BCM. The main driver of this growth will be the wider use of gas in power generation. A growing portion of European gas requirements is expected to be satisfied by imports via pipeline. According to Eni’s estimates, European gas imports will cover at least 85% of consumption from the current level of 60%, due to domestic production decrease. Eni expects that LNG will play an increasingly important role in diversifying sources of supply and will cover approximately 25% of European consumption needs by 2020 (currently LNG represents 15% of European needs).

Against this backdrop, management plans to increase international natural gas sales leveraging on Eni’s gas availability under long-term supply contracts and equity gas, access to infrastructures, long-term relationships with key producing countries (mainly Russia, Algeria and Libya), market knowledge and a wide portfolio of clients. Eni intends to strengthen its presence in European markets where its presence is already established – such as the Iberian Peninsula, Germany, France, the United Kingdom and Turkey – and to develop its marketing activities internationally, particularly in the U.S. leveraging on the planned expansion of the Company’s LNG business.

In 2007, natural gas demand in Italy amounted to 84.9 BCM; approximately 90% of gas requirements were met through imports and 10% was covered by domestic production. Eni expects natural gas consumption in Italy to increase at an average growth rate of approximately 2% through 2020, reaching an amount of 111.2 BCM in 2020 (gas volumes are projected at 93.2 BCM in 2011), driven by rising consumption in the power generation sector. Growing gas needs will be met by a projected increase in import capacity, which will be supported by significant capital expenditure projects designed to upgrade existing infrastructures and to build new ones.

In Italy, in an increasingly competitive market, Eni intends to preserve selling margins and sales volumes of its marketing operations by leveraging on the expected growth of gas demand and implementing marketing initiatives designed: (i) to focus the most profitable customer segments; (ii) to upgrade the commercial offer by tailoring pricing and services to customers’ specific needs; and (iii) to develop the combined offer of gas and electricity ("dual offer"). A strong focus will be devoted to reducing marketing expenses.

In the medium term, Eni plans to increase worldwide sales targeting a volume of 110 BCM by 2011, leveraging on expected growth in international sales that are projected to achieve an average annual rate of increase of 9%.

The matters regarding future natural gas demand and sales target discussed in this section and elsewhere here in 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.

 

Supply of natural gas

In 2007 Eni’s consolidated subsidiaries supplied 83.80 BCM of natural gas with a 5.47 BCM decrease from 2006, down 6.1%.

Natural gas volumes supplied outside Italy in 2007 (75.15 BCM) decreased by 3.91 BCM from 2006, or 4.9%, reflecting unusually mild winter weather in Europe. Lower volumes were purchased: (i) from the Netherlands (down 2.54 BCM from 2006); (ii) from Russia (down 2.51 BCM from 2006) also due to implementation of agreements signed in 2006 with Gazprom, whereby Gazprom started to supply certain Italian importers that were supplied by Eni in previous years; and (iii) from Algeria via pipeline (down 2.29 BCM from 2006).

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Supplies from Libya increased by 1.54 BCM in 2007 due to the build-up of gas production from Eni-operated fields. In addition supplies from Russia to Turkey increased by 0.97 BCM, in line with the development of the Turkish market.

Supplies in Italy (8.65 BCM in 2007) declined by 1.56 BCM from 2006, or 15.3%, due to mature fields declines.

Gas volumes from equity production amounted to 20 BCM representing approximately 20% of total volumes available for sales. Main equity volumes derived from: (i) Eni’s Italian gas fields (7.87 BCM); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2007, these two fields supplied 3.62 BCM of equity production to the Gas & Power segment; (iii) certain Eni’s fields located in the British and Norwegian sections of the North Sea (5.81 BCM); and (iv) the Gulf of Mexico (1.8 BCM).

In 2007, natural gas volumes uplifted from the storage deposits owned by Eni’s subsidiary Stoccaggi Gas were 1.49 BCM, compared to net input of 3.01 BCM in 2006.

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

Natural gas supply  

2005

 

2006

 

2007

   
 
 
  (BCM)
Italy   10.73     10.21     8.65  
Russia for Italy   21.03     21.30     18.79  
Russia for Turkey   2.47     3.68     4.65  
Algeria   19.58     18.84     16.55  
Libya   4.61     7.70     9.24  
the Netherlands   8.29     10.28     7.74  
Norway   5.78     5.92     5.78  
the United Kingdom   2.28     2.50     3.15  
Hungary   3.63     3.28     2.87  
Croatia   0.43     0.86     0.54  
Algeria (LNG)   1.45     1.58     1.86  
Others (LNG)   0.69     1.57     2.32  
Other supplies Europe   0.41     0.78     0.76  
Outside Europe   1.18     0.77     0.90  
Outside Italy   71.83     79.06     75.15  
Total supplies of subsidiaries   82.56     89.27     83.80  
Withdrawals from (input to) storage   0.84     (3.01 )   1.49  
Network losses and measurement differences   (0.78 )   (0.50 )   (0.46 )
Volumes available for sale of Eni’s subsidiaries   82.62     85.76     84.83  
Volumes available for sale of Eni’s affiliates   7.08     7.65     8.74  
E&P volumes   4.51     4.69     5.39  
Total volumes available for sale   94.21     98.10     98.96  
   
 
 

In order to meet the medium and long-term demand for natural gas, particularly in the European markets including Italy, Eni entered into long-term purchase contracts with producing countries. In 2006, Eni signed a long-term supply agreement with Gazprom whereby Eni extended the duration of its gas supply contracts to approximately 22 years. Existing contracts, which generally contain take-or-pay clauses, will ensure a total of approximately 62.4 BCM/y of natural gas by 2010.

Despite the fact that an increasing portion of natural gas volumes purchased under said contracts is planned to be sold outside Italy, management believes that in the long-term unfavorable trends in the Italian demand and supply for natural gas, also due to the possible implementation of all publicly announced plans for the construction of new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts. See "Item 3 – Risk Factors" and "Item 5 – Contractual Obligations".

In 2007, Eni purchases under its take-or-pay contracts were higher than its minimum uplift obligation. This amount relates mainly to a contractual year, rather than a calendar year (from October to end of September for a sizeable part of Eni Gas & Power long-term supply contracts).

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Marketing

Natural Gas Sales for the Year

In 2007, Eni’s worldwide gas sales (98.96 BCM, including own consumption, Eni’s share of affiliates sales and E&P sales in Europe and in the Gulf of Mexico) were up 0.86 BCM from 2006, or 0.9%, due to growth achieved on international markets, in particular in markets in Europe (up 3.64 BCM) and outside Europe (up 0.91 BCM). These increases were partly offset by lower sales to Italian importers (down 3.43 BCM) and to the domestic market (down 0.96 BCM).

Natural gas sales in Italy were 56.13 BCM (including own consumption) and declined by 0.96 BCM from 2006, or 1.7%.

The Italian market includes three groups of clients: industrial, residential and power generation users; they are further grouped as follows: (i) large industrial clients and power generation utilities directly linked to the national and the regional natural gas transport networks; (ii) residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and small businesses (also referred to as the middle market) located in large metropolitan areas and urban centers; and (iii) wholesalers, mainly local selling companies which resell natural gas to residential customers through low pressure distribution networks.

In 2007, the decline in sales on the Italian gas market was primarily due to lower sales to industrial users (down 1.56 BCM), also owing to competitive pressure, and residential users (down 0.64 BCM) mainly due to unusually mild winter weather. Sales increased by 0.54 BCM and 0.38 BCM in the power generation and wholesalers segments. Sales under the gas release programs (2.37 BCM) increased by 0.37 BCM from 2006. These sales related to certain proceedings settled between Eni and the Italian Antitrust Authority. In June 2004, Eni agreed with the Antitrust Authority to sell a total volume of 9.2 BCM of natural gas (2.3 BCM/y) in the four thermal years from October 1, 2004 to September 30, 2008 at the Tarvisio entry point into the Italian network. In March 2007 a new gas release program was signed for volumes amounting to 4 BCM of natural gas to sell in the two thermal years from October 1, 2007 to September 30, 2009 at a virtual exchange point in the Italian market.

Sales to importers in Italy (10.67 BCM) declined by 3.43 BCM mainly due to a switch from supplies of Libyan gas to volumes directly sold in Italy to a number of clients in view of optimizing Eni equity production, as well as the expiration of a supply contract with Promgas.

Gas sales in markets in the rest of Europe (24.35 BCM including affiliates) increased in 2007 by 3.64 BCM, or 17.6%, reflecting also market share gains. Main increases were mainly registered in: (i) Spain (up 1.67 BCM over 2006), due to higher supplies to the power generations segment; (ii) Turkey (up 0.94 BCM over 2006), due to the progressive reaching of full operations of the Blue Stream pipeline; (iii) France (up 0.55 BCM over 2006) due to marketing initiatives targeting small businesses and residential customers; and (iv) Northern Europe (up 0.53 BCM over 2006). Sales in markets outside Europe (2.42 BCM in 2007) grew by 0.91 BCM, or 60.3% as compared to 2006, on the back of higher LNG volumes sold on the Asian and Northern American markets by the affiliate Unión Fenosa Gas (Eni’s share 50%).

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

Natural gas sales by entities  

2005

 

2006

 

2007

   
 
 
  (BCM)
Total sales of subsidiaries   82.62   85.76   84.83
Italy   58.01   57.07   56.08
Rest of Europe   23.44   27.93   27.86
Outside Europe   1.17   0.76   0.89
Total sales of Eni’s affiliates (Eni’s share)   7.08   7.65   8.74
Italy   0.07   0.02   0.05
Rest of Europe   6.47   6.88   7.16
Outside Europe   0.54   0.75   1.53
Total sales of G&P   89.70   93.41   93.57
E&P in Europe and in the Gulf of Mexico (a)   4.51   4.69   5.39
Worldwide gas sales   94.21   98.10   98.96
   
 
 

(a)   E&P sales include volumes marketed by the Exploration & Production segment in Europe for 3.59 BCM and in the Gulf of Mexico for 1.8 BCM for the year 2007 (4.07 and 0.62 BCM, respectively for the year 2006). It also includes volumes marketed in Europe for 4.51 BCM for the year 2005.

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Natural gas sales by market  

2005

 

2006

 

2007

   
 
 
  (BCM)
Italy   58.08   57.09   56.13
Wholesalers   12.05   11.54   11.92
Gas release   1.95   2.00   2.37
Industries   13.07   13.33   11.77
Power generation   17.60   16.67   17.21
Residential   7.87   7.42   6.78
Own consumption   5.54   6.13   6.08
Rest of Europe   29.91   34.81   35.02
Importers to Italy   11.53   14.10   10.67
Markets   18.38   20.71   24.35
Iberian Peninsula   4.59   5.24   6.91
Germany-Austria   4.23   4.72   5.03
Turkey   2.46   3.68   4.62
Northern Europe   2.93   2.62   3.15
Hungary   3.39   3.10   2.74
France   0.15   1.07   1.62
Other   0.63   0.28   0.28
Outside Europe   1.71   1.51   2.42
E&P in Europe and in the Gulf of Mexico   4.51   4.69   5.39
Worldwide gas sales   94.21   98.10   98.96
   
 
 

 

Electricity Sales for the Year

In 2007, sales of electricity (33.19 TWh) increased by 2.16 TWh from 2006, up 7%, reflecting higher production availability due to full operations of the Brindisi plant and higher volumes purchased from third parties in Italy and outside Italy. Sales of steam (10,849 ktonnes) in 2007 increased by 562 ktonnes from 2006, up 5.5% and were directed to end customers.

Sales of electricity amounting to 33.19 TWh were directed to the free market (63%), the electricity exchange (26%), industrial sites (8%) and Electricity Sevice Operator (3%). In 2007, Eni started to market electricity to the retail segment leveraging on the launch of a combined integrated offer of gas and electricity (dual offer) leading to the acquisition of approximately 120,000 customers.

To this end, in 2007 Eni implemented an internal reorganization of its activities of production and marketing of electricity. Effective from January 1, 2007, electricity marketing activity has been managed by the Eni gas marketing department in order to better manage and integrate the marketing of gas and electricity. Power generation activity remained entrusted to Eni’s subsidiary EniPower.

 

Planned Actions and Sales Target

In the medium term, Eni plans to increase its sales volumes of natural gas in international markets, mainly in Europe and the U.S., in order to compensate for lower growth opportunities on its domestic market due to sector-specific regulation imposing limits to the size of Italian gas operators. In order to achieve its growth targets, Eni will leverage on its strengths represented by gas availability both as equity gas and under long-term purchase contracts, operational flexibility ensured by access to a large transport network, re-gasification terminals and logistic assets, a large portfolio of clients and market knowledge.

 

(i) Italy

In the medium term management expects to comply with market limits imposed by Italian sector-specific regulation, in terms of both volumes intake into the national network and sales volumes, through the optimal allocation of Eni’s available volumes of gas between sales in Italy and in the rest of Europe, and the use of gas in Eni’s power generation plants, leveraging also on the expected increase in demand.

Eni targets sales volumes of approximately 50 BCM in 2011. This target takes account of the expected increase in competitive pressure due to new supplies coming on stream on the Italian gas market. Specifically, import capacity to Italy is projected to increase by 25 BCM over the next four years. In next two-year period, approximately 21 BCM of new capacity are expected to come on stream in connection with Eni’s ongoing upgrading projects of its international pipelines, mainly from Russia and Algeria, as well as the ongoing construction of an LNG plant by a third party.

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In order to support sales and profitability of its marketing operations in Italy, Eni intends to implement an effective marketing policy, intended to deliver value to customers leveraging on the quality of the service and the offer of customized price formulas. Eni’s marketing initiatives will focus mainly the middle and retail markets, also leveraging on the expected development of the combined offer of gas and electricity to residential customers ("dual offer").

At the same time, Eni expects to preserve its selling margins by means of reducing the cost to serve leveraging on technological innovation, streamlining front-end and back-end processes and achieving economies of scale and synergies, particularly those driving from the dual offer in terms of process integration for acquiring, retaining and managing customers.

 

(ii) European Markets

In the future, Eni intends to strengthen its leadership in the European gas markets, targeting to increase both volumes and market shares. A review of Eni’s presence in key European markets and volume targets for 2011 is presented below.

France. Eni sells natural gas to industrial clients and resellers and plans to increase its market share mainly in the segments of small businesses and retail, leveraging on the liberalization of the market that has started from July 1, 2007.

Specifically, the retail segment presents attractive grow opportunities with 11.5 million of customers and consumption equaling 60% of total national consumption. Eni expects to ramp-up sales on the French market to achieve approximately 5 BCM of sales by 2011. This target represents an annual average growth rate of 33%. Eni expects its market share to reach 9% from the current 3%.

Eni’s development plans on the French market will leverage on the expansion of direct sales and on the partnership with the affiliated entity Altergaz, of which Eni acquired a 27.8% stake in 2007 exercising joint control with the other partners. Altergaz markets gas to small businesses and the retail segments supplying 3,500 clients, with revenues of approximately euro 60 million. Eni will support Altergaz’s development in the target segments through a 10-year supply contract of 1.3 BCM/y and will pursue synergies with its own commercial structure.

Germany. Eni is present on the German natural gas market through its affiliate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.94 BCM in 2007 (2.47 BCM being Eni’s share). Eni boasts also a direct marketing structure.

In the medium term, Eni plans to increase significantly its sales to the business segment, leveraging on the pursuit of opportunities arising from the ongoing liberalization process. The planned target is to sell 6.9 BCM in 2011, equal to a 6% market share with an annual growth rate of 8.4%.

Iberian Peninsula
Portugal.
Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%), which sold approximately 5.94 BCM in 2007 (1.98 BCM being Eni’s share). In the medium term, sales are expected to remain stable.

Spain. Eni operates in the Spanish gas market through Unión Fenosa Gas (Eni’s interest 50%) which mainly supplies natural gas to final customers and power generation utilities. Eni boasts also a direct marketing structure. In 2007, gas sales of Unión Fenosa Gas amounted to 3.64 BCM (1.82 BCM Eni’s share). Unión Fenosa Gas operates in the LNG business through 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, with 42.5% and 18.9% interest, respectively.

Eni plans to increase sales volumes in the Iberian Peninsula from the current 6.91 BCM level to approximately 8.9 BCM by 2011, with an annual average growth rate of 7%. Sale increases will be driven by an expected expansion of Unión Fenosa Gas and the development of direct sales, mainly to the Spanish power generation segment supplied by means of LNG.

UK/Northern Europe. Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). Eni plans to grow volumes sold on the markets of the UK/Northern Europe from the current 3.2 BCM level to approximately 6.9 BCM by 2011, with a 21% average annual growth rate.

Turkey. Eni and Gazprom jointly market natural gas to the Turkish company Botas under a long-term supply contract. Volumes of natural gas are supplied via the Blue Stream transport system (see below) that links the Russian coast (Dzhubga) to the Turkish coast (Samsun) crossing the Black Sea. In 2007, Eni’s share of sales amounted to 4.62 BCM. Leveraging on the expected demand growth, Eni plans to increase sales up to 6.4 BCM by 2011, equal to a 9% growth rate.

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(iii) The United States

Eni’s plans to expand its natural gas sales in the U.S. are described under the "LNG business" below.


Infrastructures

Eni operates a large European network of integrated infrastructures for transporting natural gas, linking key consumption basins with the main producing areas (North Africa, Russia and the North Sea).

In Italy, Eni operates almost all the national transport network and a significant portion of local distribution networks for the delivery of natural gas to residential and commercial users. Availability of re-gasification capacity in Italy and the Iberian Peninsula and storage sites ensure a high level of operating flexibility. These assets represent a significant competitive advantage. In order to increase the diversification and reliability of supplies and to cope with expected European demand growth, Eni is implementing plans for upgrading the transport capacity of its import pipelines from Russia, Algeria, North Europe and Libya, and expanding and modernizing its national transport and distribution networks. This plan envisages capital expenditures of approximately euro 5.6 billion to be deployed in the next four-year period. Particularly, the Company plans to increase the transport capacity of its international pipeline by 10 BCM, coming on stream in 2008, and further 6 BCM coming on stream in 2009 relating to ongoing upgrading projects.

 

International Transport Activities

In order to import natural gas to Italy, Eni owns capacity entitlements in a network of international high pressure pipelines extending for a total of over 4,300 kilometers enabling the Company to import natural gas produced in Russia, Algeria, the North Sea and Libya to Italy. A description of the main pipelines is provided below.

  The TAG pipeline imports natural gas from Russia. This is a 1,140-kilometer long pipe made up of three lines, each about 380-kilometer long, with a transport capacity of 37 BCM/y, and three compression stations. Russian natural gas is transported from Baumgarten, the delivery point at the border of Austria and Slovakia, to Tarvisio, point of entry in the Italian natural gas transport system. This facility is undergoing an upgrade project designed to increase the transport capacity by 6.5 BCM/y from the current level of 37 BCM/y. A first portion of 3.2 BCM/y is expected to be operating from October 2008. The second portion is expected to start operating late in 2009. The whole new capacity has been or is expected to be awarded to third parties.
  The TTPC pipeline imports natural gas from Algeria. This is a 742-kilometer long pipe made up of two lines each 371-kilometer long with a transport capacity of 27 BCM/y and three compression stations. Natural gas from Algeria is transported 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 transport capacity of this facility is expected to be increased by 6.5 BCM/y from the current level of 27 BCM/y. A first portion of 3.2 BCM/y has come on line late in April 2008, while the second portion is expected to start operations by October 2008. The whole new capacity has been awarded to third parties. The capacity of the TMPC downstream pipeline is already adequately dimensioned. TMPC crosses underwater the Sicily channel.
  The TMPC pipeline importing natural gas from Algeria is 775-kilometer long, is made up of five lines each 155-kilometer long with a transport capacity of 33.5 BCM/y. It crosses underwater the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.
  The TENP pipeline importing natural gas from the Netherlands is 1,000-kilometer long (two 500-kilometer long lines) with transport capacity of 15.5 BCM/y and four compression stations. This facility transports natural gas from the Netherlands through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border. Eni plans to expand the transport capacity of this pipeline by 2 BCM coming on stream late in 2009. A further capacity expansion is being assessed.
  The Transitgas pipeline importing natural gas from the Netherlands and Norway is 291-kilometer long, with one compression station, transports natural gas from the Netherlands and from Norway crossing Switzerland with its 165-kilometer long main line and a 71-kilometer long doubling line, from Wallbach where it joins the TENP pipeline to Passo Gries at the Italian border. It has a transport capacity of 20 BCM/y. A new 55-kilometer long line from Rodersdorf at the French-Swiss border to Lostorf, an interconnection point with the line coming from Wallbach was built for the transport of Norwegian gas. Eni is assessing an upgrade of the capacity of this pipeline of 2 BCM. The final investment decision is subject to the approval of the relevant authorities.
  The GreenStream pipeline imports natural gas from Libya. This is a 520-kilometer long pipe on a single line. This facility has transport capacity of 8 BCM/y and crosses underwater the Mediterranean Sea from Mellitah to Gela in Sicily, the entry point into the Italian natural gas transport system. The pipeline started operations in October 2004 and transports gas volumes produced by the Libyan fields of Wafa and Bahr Essalam operated by Eni with a 50% interest. Eni plans to upgrade the transport capacity of this pipeline from the current level of 8 BCM to 11 BCM/y with full capacity available from 2012.

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Eni holds a 50% interest in the Blue Stream underwater pipeline linking the Russian coast to the Turkish coast of the Black Sea. Through this pipeline, Eni transports gas volumes purchased in Russia to be sold on the Turkish market. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 BCM/y.

Agreement with Gazprom: South Stream project

On June 23, 2007, as part of the strategic alliance with Gazprom, Eni signed a Memorandum of Understanding for building the South Stream pipeline system that will transport volumes of Russian gas to European markets across the Black Sea. The agreement provides for a technical and economic feasibility study of the project, also including political and regulatory evaluations and considerations, and sets the guidelines for the cooperation between both companies for planning, funding, building and running the pipeline. The transport capacity of South Stream will be defined through feasibility studies on the basis of market analyses that will be carried out in the countries involved as well as in end markets. An evaluation by Saipem indicates that expenditures required by this project are comparable to those required for the construction of a full LNG chain. The South Stream pipeline is expected to be composed of two sections: (i) an offshore section crossing the Black Sea from the Russian coast at Beregovaya (where also the Blue Stream pipeline originates) to Varna on the Bulgarian coast for a total of 900 kilometers at maximum depths of 2,000 meters; and (ii) an onshore section crossing Bulgaria, with two alternatives: one directed to North-West crossing Serbia and Hungary linking with the gaslines from Russia and the other directed to South-West through Greece and Albania linking directly to the Italian network. This initiative will support Eni in extracting further value from the gas properties that Eni bought in Russia upon a bid for assets of bankrupt Russian company Yukos. See "Exploration & Production – Russia".

 

Italian Transport Activity

Eni, through Snam Rete Gas, a company listed on the Italian Stock Exchange, in which Eni holds a 50.04% interest, owns the major part of the Italian natural gas transport network as well as the only re-gasification terminal currently operating in Italy.

Under Legislative Decree No. 164/2000 that regulates the Italian natural gas market, transport activities are supervised by the Authority for Electricity and Gas which sets methods for calculating tariffs and transport return on capital employed.

Eni’s network extends for 31,081 kilometers and comprises:

(i)   a system of trunk-lines that extends for approximately 8,548 kilometers and is made up of high pressure large diameter pipes 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. This network also includes certain interregional lines reaching important markets; and
(ii)   a system of regional transport networks extending over 22,533 kilometers, made up of smaller pipes which transport volumes of natural gas to large industrial complexes, power stations and local distribution companies in the various local areas served.

In 2007, Eni’s national transport network increased by 192 kilometers due to certain upgrades to both national backbones (69 kilometers) and the regional network (123 kilometers).

The major pipelines interconnected with import trunklines that are part of Eni’s national network are:

  for natural gas imported from Algeria:
    -   two lines with a 48/42-inch diameter, 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 an upgrade with the laying of a third line with a 48 inch diameter 403-kilometer long (of these 309 are already operating). Available transport capacity at the Mazara del Vallo entry point is approximately 91 mmCM/d;
  for natural gas imported from Libya:
    -   a 36-inch line, 67-kilometer long linking Gela, the entry point of the GreenStream underwater pipeline into the national network near Enna along the backbone that transports gas coming from Algeria. Transport capacity at the Gela entry point is approximately 30 mmCM/d;
  for natural gas imported from Russia:
    -   two lines with 42/36/34-inch diameters extends for a total length of approximately 900 kilometers and are connected to the TAG pipeline from Russia at Tarvisio. This facility cross the Po Valley reaching Sergnano (near Cremona) and Minerbio. This pipeline has been upgraded by the laying of a third 264-kilometer long line with diameter from 48 to 56 inches from Tarvisio to Zimella (Verona) and by upgrading the Malborghetto compression station. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 113 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:

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    -   one line, with a 48-inch diameter, 177-kilometer long extends from the Italian border at Passo Gries (Verbania) where it connects with the Transitgas pipeline carrying gas from Norway and the Netherlands, to the node of Mortara, in the Po Valley. The pipeline transport capacity at the Passo Gries entry point is of 64 mmCM/d;
  for natural gas coming from the Panigaglia LNG terminal:
    -   one line, with a 30-inch diameter, 170-kilometer long, which links the Panigaglia terminal to the national transport network near Parma. The pipeline transport capacity at the Panigaglia entry point is of 13 mmCM/d.

Eni’s transport system is complemented by: (i) 10 compressor stations with a total power of 758 MW; (ii) 5 marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo, Messina and Gela in Sicily and Favazzina and Palmi in Calabria for the GreenStream pipeline; and (iii) a control room of the dispatching system located in San Donato Milanese, which oversees and monitors the whole network in cooperation with peripheral units.

Snam Rete Gas is currently assessing the construction of the Italian section of the new Galsi pipeline connecting Algeria to Italy through Sardinia with an 8 BCM/y capacity.

The Italian section of this new infrastructure will be made up of an onshore section crossing Sardinia and an offshore section reaching Tuscany where it will link with the national network for a total length of 600 kilometers. Galsi will be responsible for project engineering and obtaining needed licenses and authorizations, while Snam Rete Gas will build the pipeline and manage it when operational.

For the next four years Snam Rete Gas approved a capital expenditure plan of approximately euro 4.3 billion aimed mainly at the upgrade of its transport network in view of the expected increase in import capacity.

In 2007, volumes of natural gas input in the national grid (83.28 BCM) decreased by 4.71 BCM from 2006, down 5.4%, mainly due to lower volumes of natural gas input to storage for the rebuilding of stocks. Eni transported 30.89 BCM of natural gas on behalf of third parties in Italy in line with 2006.

In 2007, the LNG terminal in Panigaglia (La Spezia) regasified 2.38 BCM of natural gas (3.13 BCM in 2006), discharging 73 tanker ships (96 in 2006).

Gas volumes transported (a)  

2005

 

2006

 

2007

   
 
 
  (BCM)
Eni   54.88   57.09   52.39
On behalf of third parties   30.22   30.90   30.89
Enel   9.90   9.67   9.36
Edison Gas   7.78   8.80   7.16
Others   12.54   12.43   14.37
Total   85.10   87.99   83.28
   
 
 

(a)   Includes amounts destined to domestic storage.

 

Distribution Activity

Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. Eni, through its 100% subsidiary Italgas and other subsidiaries, operates in the distribution activity in Italy serving 1,318 municipalities through a low pressure network consisting of approximately 49,000 kilometers of pipelines supplying 5.6 million customers and distributing 7.3 BCM in 2007.

Under Legislative Decree No. 164/2000 that regulates the Italian natural gas market, distribution activities are supervised by the Authority for Electricity and Gas which sets methods for calculating distribution tariffs and return on capital employed. Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. According to Legislative Decree No. 164/2000, the award of the service will have to take place by competitive bids from the end of a transition period and however, no later than December 31, 2012. Future concessions will last no more than twelve years.

Eni intends to develop its served market and improve efficiency and quality of services rendered. For the next four years Eni defined a capital expenditure plan of approximately euro 1 billion for the development/upgrade of its distribution networks and their technological upgrade.

The target is to serve 6 million clients and increase distributed volumes to 8.3 BCM by 2011.

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The LNG Business

Eni intends to speed up the development of its LNG business on a global scale, aiming at building or acquiring assets in the LNG value chain in order to seize the opportunities arising from the increasing role of LNG in satisfying energy requirements. Expansion in LNG will enable Eni to fully monetize its large equity reserves.

By 2011 Eni plans to sell 14.5 BCM of LNG (including E&P sales) with an annual growth rate of 5.4% over the next four years.

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

Italy. Eni operates the only re-gasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can input 3.5 BCM/y into the Italian transport network. In 2007, a total of 2.38 BCM of natural gas were input in the national network, of these 47% were re-gassified on behalf on Eni. Eni plans to increase the capacity of the Panigaglia plant by 4.5 BCM, expected to come on line by 2014. Estimated capital expenditures amount to euro 359 million.

Egypt. Eni, through its interest in Unión Fenosa Gas, has an indirect interest in the Damietta liquefaction plant that produces approximately 5 mmtonnes/y of LNG equal to a feedstock of 7.6 BCM/y of natural gas. The partners of the project (including Eni’s Exploration & Production segment) agreed on terms for doubling the plant capacity. The project is expected to be sanctioned by relevant Egyptian authorities in the first half of 2008. In order to market its share of LNG, Eni intends also to build two gas tanker ships with a capacity of 155 KCM each.

Spain. Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto re-gasification plant, near Valencia, with a capacity of 6.7 BCM/y. At present, Eni’s capacity entitlements amount to 1.6 BCM/y of gas. A capacity upgrading plan has been sanctioned targeting a 0.8 BCM/y capacity increase by 2009. Eni through Unión Fenosa Gas also holds a 9.5% interest in the El Ferrol re-gasification plant, located in Galicia, which started operations in November 2007. This facility has treatment capacity of approximately 3.6 BCM/y, 0.4 BCM/y being Eni’s capacity entitlements.

USA. Eni is implementing plans to expand its presence in the strategic U.S. market where Eni holds a 40% capacity entitlement in the Cameron re-gasification terminal under construction on the coast of Louisiana. This facility is expected to have an initial capacity of 15.5 BCM/y, 6 BCM being Eni’s entitlement. Eni is entering into a number of agreements to ensure its share of supplies to the plant, particularly: (i) in February 2007, an agreement was signed with Nigeria LNG Ltd, which operates the Bonny LNG plant in Nigeria, to purchase, over a twenty-year period, 1.375 mmtonnes/y of LNG, equivalent to 2 BCM/y of gas, deriving from the upgrade of the Bonny liquefaction plant (Train 7) expected for 2012; and (ii) negotiations are also progressing with Brass LNG Ltd for the purchase of 1.67 mmtonnes/y of LNG capacity approximately equivalent to 2.3 BCM/y of gas.

In December 2007, Eni purchased a share of 5.6 BCM/y capacity of the Pascagoula re-gasification plant under construction in Mississippi. This deal is related to the Angola LNG project in partnership with Sonangol (See Development initiatives in the Exploration & Production segment) which envisages construction of an LNG plant designed to produce 5.2 mmtonnes/y to be fed with natural gas produced in Angola. The LNG will be marketed in the Unites States at the Pascagoula site. Under the agreement, Eni will also have the right to have its equity gas in Angola liquefied, shipped and regasified at Pascagoula by Angola LNG for a quantity equivalent to 0.94 BCM/y.

 

Electricity Generation

Eni conducts its power generation activities at its sites of Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi and Ferrara. In 2007, electricity production sold was 25.49 TWh, up 0.67 TWh or 2.7% as compared to 2006 mainly due to the ramp-up of the Brindisi plant. Total installed capacity was 4.9 GW at December 31, 2007.

By 2010 Eni intends to complete its plan for expanding power generation capacity, targeting an installed capacity of 5.5 GW. At full capacity, production is expected to amount to approximately 31 TWh. Supplies of natural gas are expected to amount to approximately 6 BCM/y from Eni’s diversified supply portfolio. Residual expected capital expenditure amount to euro 0.5 billion in addition to the euro 2.2 billion already invested until 2007.

High efficiency, low environmental impact and reduced expenditure and construction times are the main features of these plants, which show interesting profitability prospects due to the expected increase in demand for electricity and the ability to operate in co-generation (combined electricity and steam generation). The co-generation technology has been acknowledged by the Authority for Electricity and Gas as a production technology that entails priority on the national dispatching network and the exemption from the purchase of "green certificates". Article 11 of Legislative Decree No. 79/1999 concerning the opening up of the Italian electricity market obliges importers and

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producers of electricity from non renewable sources to input into the national electricity system a share of electricity produced from renewable sources set at 2% of electricity imported or produced from non renewable sources exceeding 100 GW. Calculations are made on total amounts net of co-generation and own consumption. This obligation can be met also by purchasing volumes or rights from other producers employing renewable sources (the so-called green certificates) to cover all or part of such 2% share. Legislative Decree No. 387/2003 established that from 2004 to 2006 the minimum amount of electricity from renewable sources to be input in the grid in the following year be increased by 0.35% per year. The Minister of Productive Activities, with decrees issued in consent with the Minister of the Environment, will define further increases for the 2007-2009 and 2010-2012 periods.

The development plan is underway at Ferrara (Eni’s interest 51%), where in partnership with EGL Luxembourg (a company belonging to Swiss group EGL), construction of two new 390 MW combined cycle units is underway.

Eni has also planned the installation of a new 240 MW combined cycle unit at the Taranto site (current capacity 75 MW).

New installed generation capacity uses the combined cycle gas fired technology (CCGT), ensuring a high level of efficiency and low environmental impact.

Power Generation  

2005

 

2006

 

2007

   
 
 
Purchases                
Natural gas   (mmCM)   4,384   4,775   4,860
Other fuels   (ktoe)   659   616   720
- including cracking steam       96   136   137
Sales                
Electricity production sold   (TWh)   22.77   24.82   25.49
Steam   (ktonnes)   10,660   10,287   10,849
   
 
 

Eni’s operated power stations are described below.

Ferrera Erbognone. This power station has an installed capacity of approximately 1,030 MW articulated on three combined cycle units, two of them with an approximately 390 MW capacity are fired with natural gas, the third one with approximately 250 MW capacity is fired in part with natural gas and complemented with refinery gas obtained from the gasification of a heavy residue form crude processing at the nearby Eni-operated Sannazzaro refinery.

Ravenna. Two new combined cycle 390 MW units started operations in 2004. Added to the existing 190 MW, the power station’s installed capacity reached approximately 970 MW.

Brindisi. This power station has been upgraded by installing three new combined cycle units, each with capacity of 390 MW, bringing overall capacity at approximately 1,320 MW.

Mantova. This power station has been upgraded by installing two new combined cycle units, each with capacity of 390 MW, bringing overall capacity at approximately 840 MW. This power station also provides steam for heating purposes delivered to the Mantova’s urban network through a heat exchanger.

 

Capital Expenditures

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

 

 

Refining & Marketing

Eni’s Refining & Marketing segment involves refining of crude oil and marketing of refined products in Italy and in a number of European markets. Based on public data, Eni is the main operator in the markets for refining and marketing of refined products in Italy. Eni’s refining and marketing operations are efficiently integrated and supported by a full set of logistic assets. Refining know-how, strong market acceptance of the Agip brand, the ability to develop innovative fuels, and the integration with upstream operations represent Eni’s principal competitive advantages. Eni’s key medium term target is to enhance the profitability of its downstream oil business.

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The strategic guidelines to attain this target are:

  to upgrade Eni’s refining system;
  to improve profitability and qualitative standards of the Italian retail network;
  to selectively develop the retail business outside Italy; and
  to pursue higher levels of operational efficiency.

In the next four years the implementation of these strategies is expected to be supported by a capital expenditure program of approximately euro 4 billion mainly targeting refinery upgrading, particularly by increasing conversion capacity, flexibility and efficiency of the Company’s plants. Significant expenditures are expected to be deployed to enhance Eni’s retail operations in Italy and to increase the market share in selected European markets.

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 and Trading

In 2007, a total of 59.56 mmtonnes of crude were purchased by the Company’s Refining & Marketing segment (65.70 mmtonnes in 2006), of which 31.57 mmtonnes from Eni’s Exploration & Production segment. Volumes amounting to 16.65 mmtonnes were purchased under long-term supply contracts with producing countries, while 11.34 mmtonnes were purchased on the spot market. Approximately 24% of crude purchased in 2007 came from West Africa, 22% from countries of the former Soviet Union, 18% from North Africa, 15% from the Middle East, 12% from the North Sea and 7% from Italy.

Approximately 25.82 mmtonnes of crude purchased in 2007 were resold, down 15.8% from 2006. In addition, 3.59 mmtonnes of intermediate products were purchased (3.18 mmtonnes in 2006) to be used as feedstock in conversion plants and 16.14 mmtonnes of refined products (16 mmtonnes in 2006) were purchased to complement production availability.

 

Refining

Eni’s refining system has total refinery capacity (balanced with conversion capacity) of approximately 38.1 mmtonnes (equal to 748 KBBL/d) and a conversion index of 56%. Eni’s five 100 percent owned refineries have balanced capacity of 27.2 mmtonnes (equal to 544 KBBL/d), with a 58.6% conversion rate. In 2007, refinery throughputs in Italy and outside Italy were 37.15 mmtonnes.

In the next four years, Eni plans to increase the profitability of its refining operations by investing euro 2.4 billion in plant upgrading and enhancement.

Eni’s investment plans are designed to take advantage of certain expected market trends in the refining industry:

(i)   a significant reduction in European demand for gasoline is expected in the medium term, while consumption of diesel fuel is expected to grow driven by the continuing renewal of the car fleet;
(ii)   a slowdown in the demand for gasoline on the U.S. market is expected, reflecting the diffusion of more energy efficient car models and the increasingly widespread use of bio-fuels;
(iii)   demand for middle distillates is expected to increase from current levels reflecting, in addition to the above mentioned higher needs of diesel fuels for automotive uses, increased demand form the airlines sector and for petrochemical feedstock;
(iv)   implementation of increasingly tight environmental regulations in Europe will require significant capital expenditures for refinery upgrading;
(v)   demand for fuel oil is expected to decrease due to increasingly strong competition from natural gas in firing power plants; and
(vi)   opportunities will arise to monetize heavy crudes and non conventional resources by applying advanced refinery technologies.

Eni’s refinery capital projects will be designed to: (i) increase plant conversion capacity in view of boosting middle distillate yields and extracting value from equity crude, the availability of which is expected to increase in the Mediterranean basin over the medium term; (ii) improve refinery flexibility in order to optimize processed feedstock and capture market opportunities arising from an expected increased availability of heavy/sour crudes that are typically discounted in the marketplace; (iii) produce fuels in line with product specifications provided for increasingly tight European environmental standards; and (iv) enhance operational efficiency of refineries. By 2011, Eni targets to achieve a conversion index of 60% (65% in Italy) and a volume of refinery throughputs on own account of 37 mmtonnes (the comparable volume in 2007 was 35 mmtonnes that excludes volumes processed at

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refineries where the Company has no interest). Middle distillate yields are expected to come in at 43% in 2011 from 41% in 2007 and equity crude volumes processed to increase from 30% to 35% relative to all processed feedstock.

The table below sets forth certain statistics regarding Eni’s refineries at December 31, 2007.

Refining system in 2007

   

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
(%)

 

Fluid catalytic cracking - FCC
(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      

678

 

678

 

544

 

58.6

 

69

 

22

 

36

 

29

 

89

 

46

 

82

   

102

 
Italy                                                        
   Sannazzaro  

100

 

223

 

223

 

170

 

46.6

 

34

         

29

 

29

     

73

   

95

 
   Gela  

100

 

129

 

129

 

100

 

143.5

 

35

     

36

         

46

 

82

   

106

 
   Taranto  

100

 

118

 

118

 

110

 

64.3

     

22

         

38

     

97

   

104

 
   Livorno  

100

 

106

 

106

 

84

 

11.4

                         

88

   

110

 
   Porto Marghera  

100

 

102

 

102

 

80

 

20

                 

22

     

79

   

100

 
Partially owned refineries (1)      

917

 

232

 

204

 

48.3

 

172

 

25

     

56

 

27

     

77

   

88

 
Italy                                                        
   Milazzo  

50

 

248

 

124

 

80

 

72.3

 

41

 

25

     

32

         

68

   

106

 
Germany                                                        
   Ingolstadt/Vohburg/
   Neustadt (Bayernoil)
 

20

 

258

 

54

 

52

 

32.6

 

58

                     

90

   

95

 
   Schwedt  

8.33

 

231

 

19

 

19

 

41.8

 

49

             

27

     

91

   

92

 
Czech Republic                                                        
   Kralupy e Litvinov
   (Ceska Rafinerska)
 

32.4

 

180

 

35

 

53

 

29.6

 

24

         

24

         

80

 (2)

 

80

 (2)

Total refineries      

1,595

 

910

 

748

 

56

 

241

 

47

 

36

 

85

 

116

 

46

 

81

   

101

 
   
 
 
 
 
 
 
 
 
 
 
 
 

(1)   Capacity of conversion plant is 100%.
(2)   The utilization rates consider, all over the year 2007, the Eni’s share in Ceska Rafinerska as at year end (it became 32.4% in September 2007).

Italy

Eni’s refining system in Italy is composed of five 100 percent owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy has 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 capacity of 170 KBBL/d and a conversion index of 46.6%. Management regards it as one of Eni’s most profitable refining assets. Located in the Po Valley, it supplies mainly markets in North-Western Italy and Switzerland. This refinery processes a wide range of feedstock, such as Caspian Pipeline Consortium Blend crude oil from the Caspian Sea and the Bonga crude from Nigeria. 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 (FCC4), a hydro-cracker (HDCK) middle distillate conversion unit and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syngas to feed the nearby EniPower electricity production plant at Ferrera Erbognone. A significant conversion capacity and flexibility upgrading program is ongoing in order to further enhance this facility. Specifically, a high pressure hydrocracking unit with a processing capacity of 28 KBBL/d is under construction with expected start-up in 2009. In addition, Eni plans to develop a conversion plant employing the Eni Slurry Technology with a 20 KBBL/d capacity for the processing of extra heavy crude and tar sands producing high quality middle distillates and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled in 2012.

The Taranto refinery has balanced refinery capacity of 110 KBBL/d and a conversion index of 64.3%. This refinery can process a wide range of crude and other feedstock. It mainly 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 includes 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 feedstock. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2007 a total of 2.5 mmtonnes of this oil were processed).

Eni plans to upgrade the conversion capacity of this refinery by building plants that will enable to extract value from fuel oil and other semi-finished products currently exported.


(4)   This definition applies to the term margin whenever used in Item 5.

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Gela, with a balanced refinery capacity of 100 KBBL/d and a conversion index of 143.5%, this refinery located on the southern coast of Sicily is highly integrated with upstream operations as it processes heavy crude produced from nearby Eni fields offshore and onshore Sicily. In addition, it is integrated downstream as it supplies large volumes of petrochemical feedstock to Eni’s in site petrochemical plants. The refinery also manufactures fuels for automotive use and residential heating purposes.

Its high conversion level is ensured by an FCC unit with go-finer for the upgrading of feedstock and two coking plants for the vacuum conversion of heavy residues. The power plant of this refinery also contains modern residue and exhaust fume treatment plants which allow full compliance with the tightest environmental standards.

An upgrade of the Gela refinery will be implemented by means of an upgrade of the power plant, the building of a new gas fired generation plant and other facilities to increase profitability by exploiting the synergies deriving from the production of feedstock for electricity generation and sale of increasing volumes of electricity on the market.

Livorno, with a balanced refinery capacity of 84 KBBL/d and a conversion index of 11.4%, manufactures mainly gasoline, fuel oil for bunkering, specialty products 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 optimizing intake, handling and distribution of products.

Porto Marghera, with a balanced refinery 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 plants (visbreaking/thermal cracking) designed to produce yields of valuable products.

 

Rest of Europe

In Germany Eni holds 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that includes the Ingolstadt, Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 70 KBBL/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany.

The partners of these refineries plans to restructure the whole complex, by building a new hydrocracker with a capacity of approximately 2 mmtonnes/y (40 KBBL/d), revamping other assets (in particular a reformer and a hydrofiner) and shutting-down a topping unit. This project is expected to be completed in 2009 and aims at increasing middle distillate yields and reducing the production of gasoline. In 2007, Eni purchased a further 16.11% stake in Ceska Rafinerska, increasing its overall stake to 32.4%. The Ceska Rafinerska includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to 53 KBBL/d.

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

Availability of refined products  

2005

 

2006

 

2007

   
 
 
  (mmtonnes)
Italy                  
Refinery throughputs                  
At wholly-owned refineries   27.34     27.17     27.79  
Less input on account of third parties   (1.70 )   (1.53 )   (1.76 )
At affiliates refineries   8.58     7.71     6.42  
Refinery throughputs on own account   34.22     33.35     32.45  
Consumption and losses   (1.87 )   (1.45 )   (1.63 )
Products available for sale   32.35     31.90     30.82  
Purchases of refined products and change in inventories   4.85     4.45     2.16  
Products transferred to operations outside Italy   (5.41 )   (4.82 )   (3.80 )
Consumption for power generation   (1.09 )   (1.10 )   (1.13 )
Sales of products   30.70     30.43     28.05  
Outside Italy                  
Refinery throughputs on own account   4.57     4.69     4.70  
Consumption and losses   (0.24 )   (0.32 )   (0.31 )
Products available for sale   4.33     4.37     4.39  
Purchases of refined products and change in inventories   11.19     11.51     13.91  
Products transferred from Italian operations   5.41     4.82     3.80  
Sales of products   20.93     20.70     22.10  
Refinery throughputs on own account   38.79     38.04     37.15  
Total equity crude input   12.53     13.66     11.22  
Total sales of refined products   51.63     51.13     50.15  
   
 
 

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In 2007, refining throughputs on own account in Italy and outside Italy were 37.15 mmtonnes, down 0.89 mmtonnes from 2006, or 2.3%, owing to the expiry of a processing contract at the Priolo refinery. Excluding this effect, refinery throughputs in Italy increased by 1.5% due to the better performance of Livorno and Gela refineries because of lower planned and unplanned downtime.

Total throughputs on wholly-owned refineries in 2007 (27.79 mmtonnes) increased 0.62 mmtonnes from 2006, up 2.3%.

Approximately 30.2% of volumes of processed crude in 2007 was supplied by Eni’s Exploration & Production segment (35.9% in 2006), representing a decrease of over 5% from 2006. Lower equity volumes of some 2.44 mmtonnes related to a reduction of supplies of the Libyan Bu-Attifel crude processed at the Priolo refinery due to the above mentioned process contract expiry.

 

Logistics

Eni is the leader in storage and transport of petroleum products in Italy with its logistical integrated infrastructures consisting of 12 operated storage sites and a network of petroleum product pipelines.

Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genoa (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic costs and increasing efficiency.

Eni operates in the transport of oil and refined products: (i) on land through a pipeline network of leased and owned pipelines extending over 2,130 kilometers (1,315 kilometers are wholly owned by Eni); and (ii) by sea through spot and long-term lease contracts of tanker ships.

Secondary distribution to retail and wholesale markets is executed almost exclusively through the management of third parties who also owns their means of transportation.

In the medium term Eni plans to enhance the efficiency of its logistic operations by: (i) implementing an integrated logistic model ("hub" model) designed to centralize handling of products flows on a single platform enabling real time monitoring; and (ii) introducing more efficient operating modes in the collection and delivery of orders with the aim of reducing unit delivery costs.


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  

2005

 

2006

 

2007

   
 
 
  (mmtonnes)
Italy            
Retail marketing   10.05   8.66   8.62
Wholesale marketing   12.11   11.74   11.09
    22.16   20.40   19.71
Petrochemicals   3.07   2.61   1.93
Other sales   5.47   7.42   6.41
Total   30.70   30.43   28.05
Outside Italy            
Retail marketing   3.67   3.82   4.03
Wholesale marketing   4.50   4.60   4.96
    8.17   8.42   8.99
Other sales   12.76   12.28   13.11
Total   20.93   20.70   22.10
    51.63   51.13   50.15
   
 
 

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In 2007, sales volumes of refined products (50.15 mmtonnes) decreased by 0.98 mmtonnes from 2006, or 1.9%, mainly due to lower volumes sold to oil companies and traders in Italy, lower volumes supplied to the petrochemical sector due to the expiry of a processing contract at the Priolo refinery and a decline in wholesale sales in Italy. These declines were partly offset by higher retail and wholesale sales on markets in the rest of Europe (up 0.41 mmtonnes, or 5.1%).

Retail Sales in Italy

Eni markets refined products in Italy trough its Agip-branded network of operated service stations.

In 2007, volumes of refined products marketed on the Italian network (8.62 mmtonnes) were down 39 ktonnes from 2006, or 0.5%, mainly due to a decline in domestic consumption. This decline mainly regarded gasoline volumes, while gasoil sales increased following the same pattern as national consumption trends. Market share decreased slightly from 29.3% to 29.2%; market share is computed as ratio of Eni’s sales volumes to national consumption as published in national statistics.

The average throughput per service station measured on gasoline and gasoil sales was 2,444 kliters, down 0.8% from 2006.

At December 31, 2007, Eni’s retail network in Italy consisted of 4,390 service stations, 34 more than at December 31, 2006, resulting from the start of 26 new service stations and a positive balance between acquisitions/releases of leased outlets concessions (up 23 units), in addition to 13 service stations that were acquired upon rental from third parties. In 2007, 23 low throughput service stations were shut down or divested and 5 highway concessions expired.

Retail volumes of BluDiesel – a high performance and low environmental impact gasoil – amounted to approximately 735 ktonnes (850 mmliters in 2007), up 1.2% from 2006 and represented 14% of gasoil sales on the Eni’s retail network. At year-end, virtually all Agip branded service stations marketed BluDiesel (about 4,094 equal to 93%).

Retail volumes of BluSuper – a high performance and low environmental impact gasoline, on sale since 2004 – amounted to approximately 98 ktonnes (114 mmliters), in line with 2006 and covered 3% of gasoline volumes sold on the Eni’s retail network. At year-end, service stations marketing BluSuper totaled 2,565 units (2,316 at December 31, 2006) covering to approximately 58% of Eni’s network.

In March 2007, Eni launched its new "You&Agip" promotional program designed to boost customer loyalty to the Agip brand. This three-year long initiative offers prizes to customers in proportion to purchases of fuels and convenience items at Agip’s stores as well as at the ones of certain partners to the program. At every purchase of fuels or convenience items, clients are granted a proportional amount of points that are credited to a fidelity card. Clients are able to decide how to accumulate points and when to spend them. At year end, the number of active cards was approximately 3.9 million. Volumes of fuel marketed under this initiative represented 40.1% of total volumes marketed on Eni’s service stations joining the program, and 39.4% of overall volumes marketed on the Agip network.

Eni plans to strengthen its competitive position in Italy by upgrading its outlets to attain European standards of quality and service. The Company intends to leverage on marketing initiatives designed to retain the various segments of clients, develop the offer of premium products and execute its convenience offer through quality store formats. A strong focus will be devoted to pursue high levels of operating efficiency. In the next four years, Eni plans to invest approximately euro 0.7 billion in the upgrading of its network, targeting to build, acquire and upgrade service stations with planned standards of service and quality. Expenditures will also be directed to comply with applicable environmental standards and regulations.

By 2011, Eni expects to achieve approximately 11.4 billion liters of volumes sold (approximately 11 billion liters in 2007) with a retail network composed of approximately 4,400 service stations, of which 75% of owned sites.

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Retail Sales in the Rest of Europe

In recent years, Eni’s strategy focused on selectively growing its market share, particularly by means of acquiring valuable assets in European areas with interesting profitability perspectives. In implementing its growth strategy, Eni has been able to leverage on synergies ensured by the proximity of these markets to Eni’s production and logistic facilities, brand awareness and economies of scale.

Over the last four years, retail volumes of refined products marketed in the rest of Europe have grown more than 33% (equal to a compound average growth rate of 7.5%).

Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets. Capital expenditures aimed at growing and upgrading Eni’s network are planned at euro 0.4 billion in the next four years.

In 2007, retail volumes of fuels marketed in the rest of Europe totaled 5 billion liters (4.03 mmtonnes), up 5.5% from 2006 reflecting both organic growth and the purchase of 102 service stations in the Czech Republic, Slovakia and Hungary.

At December 31, 2007 Eni’s retail marketing network outside Italy was represented by 2,051 service stations an increase of 113 units from December 31, 2006. The network’s evolution was as follows: (i) 125 service stations were acquired, of which 102 units in the Czech Republic, Slovakia and Hungary; (ii) 10 new outlets were opened; (iii) 25 low throughput service stations were closed in Spain and Austria; and (iv) a positive balance of acquisitions/releases of lease concessions (up 3 units) was recorded, with positive changes in Spain, Hungary and the Czech Republic, and negative ones in Germany and France. Average throughput (2,578 kliters) was up 3.7%.

The key markets of Eni’s presence are: Austria with a 7.8% market share, Hungary with 7.9%, Czech Republic with 7.7%, Switzerland with 5.9%, South-Central Germany with a 4.2%, and South-Western France with 1.1% on national base. These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes.

In 2008, management expects to divest its retail and wholesale marketing activities in the Iberian Peninsula following the exercise of a call option on part of Eni’s partner Galp Energia (Eni’s share being 33.34%), in accordance with the agreement signed in December 2005 by the majority shareholders of Galp Energia (in addition to Eni, Amorim Energia and Caixa Geral de Depósitos). The transaction, subject to approval from European antitrust authorities, includes 371 Agip-branded service stations.

 

Other businesses

Wholesale

Eni markets gasoline and other fuels on wholesale markets, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels, gasoline and fuel oil. Major customers are wholesalers, agricultural users, manufacturing industries, public utilities and transports.

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 present all over Italy and articulated in local marketing offices and a network of agents and concessionaires.

In 2007, volumes marketed on wholesale markets in Italy, which excludes the Avio and Bunker businesses, were approximately 7.54 mmtonnes down 0.68 mmtonnes from 2006, or 8%, mainly reflecting a decline in domestic consumption of heating oil by the power generation sector, the exceptionally mild weather conditions that negatively influenced the sales of heating products in the first quarter and competitive pressure.

Sales volumes on wholesale markets outside Italy in 2007 were 4.96 mmtonnes, up approximately 360 ktonnes from 2006, or 7.8%, mainly due to the growth in the Czech and Iberian markets.

Eni also markets jet fuel directly at 47 airports, of which 27 in Italy. In 2007, these sales amounted to 2.35 mmtonnes (of which 1.97 mmtonnes in Italy) up approximately 175 ktonnes. Eni is active also in the international market of bunkering, marketing marine fuel in 38 ports, of which 23 in Italy. In 2007, marine fuel sales were 1.72 mmtonnes (1.58 in Italy) decreasing approximately 86 ktonnes as compared to 2006.

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Other sales amounted to 21.31 mmtonnes and mainly regarded sales to oil companies and traders (19.39 mmtonnes) and 1.93 mmtonnes supplies to the petrochemical sector.

LPG

In Italy Eni is leader in LPG production, marketing and sale with 539 ktonnes sold for heating and automotive use (under the Agip brand and wholesale) equal to a 17.4% market share. Additional 225 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 11 bottling plants and a number of owned storage sites in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna.

Lubricants

Eni operates 8 (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa and the Far East which manufacture finished and fatty lubricants. With a wide range of products composed of over 650 different blends, Eni has an important 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 according to public data. Base oils are manufactured primarily at Eni refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero.

In 2007, retail and wholesale sales in Italy amounted to 132 ktonnes with a 24.3% 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 90 ktonnes, of these about 50% were registered in Europe (mainly Spain, Germany, and France).

Oxygenates

Eni, through its subsidiary Ecofuel (Eni’s interest 100%), markets over 2 mmtonnes/y of oxygenates mainly ethers (approximately 10% of world demand) and methanol (approximately 1.5% of world demand). About 56% of products are manufactured in Italy at Eni’s plants in Ravenna, Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic), the remaining 44% is bought and resold. In 2007, a test campaign of ETBE from bioethanol was carried out at Eni’s plant in Ravenna. In Venezuela MTBE plants are being converted to the production of isooctane.

 

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 and the commoditized feature of Eni’s main 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, also considering the cyclical nature of demand. See "Item 3 – Risk factors". The Company does not expect to incur significant amount of expenditures to develop this business. In future years, management forecast a yearly level of expenditures in line with 2007 mainly targeted to upgrade plant efficiency, execute de-bottlenecking interventions and to comply with all applicable regulations on environment, health and safety issues.

In 2007, sales of petrochemical products (5,513 ktonnes) increased by 237 ktonnes from 2006, up 4.5%, increasing in all business areas except for aromatics (down 2.9%). Increases reflected the fact that performance in 2006 was hit by an accident occurred at the Priolo refinery in April 2006, as well as positive market trends.

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Petrochemical production (8,795 ktonnes) increased by 1,723 ktonnes from 2006, up 24.4% due to the transfer of the Porto Torres plant from the Other Activities segment (up 1,274 ktonnes) and the impact on 2006 production of an accident occurred at the Priolo plant as outlined. Excluding these effects, production increased by 195 ktonnes, or 2.8%, due to a good performance at the Ravenna, Ragusa and Sarroch plants. Production was lower at Porto Marghera due to unplanned standstills in the second half of the year.

Nominal production capacity was in line with 2006. Excluding the impact of the consolidation of the Porto Torres plant, average plant utilization rate calculated on nominal capacity increased by 4 percentage points from 76.4% to 80.6%, due to the impact of the Priolo plant outage in 2006.

Approximately 48.9% of total production was directed to Eni’s own productions cycle (35.2% in 2006). Oil based feedstock supplied by Eni’s Refining & Marketing segment covered 21% of requirements (10% in 2005).

Prices of Eni’s main petrochemical products increased on average by 4%; all business areas posted increases. The most relevant increases were registered in: (i) styrenes (up 6.0%), in particular compact polystyrene and ABS/SAN; (ii) elastomers (up 5.5%), in particular nytrilic, SBR and thermoplastic rubbers; (iii) polyethylene (up 4.9%) with increases in all products; (iv) intermediates (up 4.8%) in particular phenol and cycloexanone; and (v) olefins (up 3.8%), in particular ethylene. However, these prices increases did not made for higher purchase costs of oil-based feedstock (virgin naphtha was up 20.4% in dollar terms, 10.3% in euro), particularly from the second half of the year, and as a result product margins significantly decreased from a year ago. Based on current trends in oil prices, the Company does not expect any meaningful improvement in 2008.

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

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (ktonnes)
Basic petrochemicals   4,450     4,275     5,688  
Styrene and elastomers   1,523     1,545     1,632  
Polyethylene   1,309     1,252     1,475  
    7,282     7,072     8,795  
Internal consumption   (2,606 )   (2,488 )   (4,304 )
Purchases and change in inventories   700     692     1,022  
Total products   5,376     5,276     5,513  
   
 
 

The table below sets forth Eni’s sales of main petrochemical products by volume for the periods indicated.

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (ktonnes)
Basic petrochemicals   3,022     2,882     3,023  
Styrene and elastomers   1,003     1,000     1,041  
Polyethylene   1,351     1,394     1,449  
Total sales   5,376     5,276     5,513  
   
 
 

Basic petrochemicals

Sales of basic petrochemicals of 3,023 ktonnes reported an increase of 141 ktonnes from 2006, up 4.9%, mainly due to higher product availability and due in particular to the fact that 2006 was affected by the outage of the Priolo cracker. Main increases were registered in olefins (up 5.8%) and intermediates (up 8.9%) while aromatics sales declined (down 3%), in particular xylene (down 12.5%) due to the shutdown of the paraxylene line at Priolo in April 2007, offset in part by higher sales of benzene (up 15.8%).

Basic petrochemical production (5,688 ktonnes) increased by 1,413 ktonnes, up 33.1%.

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Styrene and elastomers

Styrene sales in 2007 (594 ktonnes) were slightly higher from 2006 (up 1.2%). Increasing sales in ABS/SAN (up 34%) reflect the higher product availability due to the fact that 2006 was affected by technical problems at the Mantova plant. Increases of compact polystyrene (up 7.3%) were due to market recovery. Declines were registered in styrene (down 41%) due to lower availability because of unexpected outages.

Elastomers sales in 2007 (447 ktonnes) increased by 8.3% from 2006 due to the consolidation of nytrilic rubber sales following the purchase of the Porto Torres plant from Syndial. Excluding this effect, elastomer sales were in line with 2006. Increases recorded in SBR (up 1.3%), BR (up 5.3%) and thermoplastic rubbers (up 5.5%), due to a positive market trend, were offset by lower sales of EPR (down 3.6%) and lattices (down 5.1%).

Styrene production in 2007 (1,117 ktonnes) increased by 2.7% over 2006.

Elastomer production in 2007 (515 ktonnes) increased by 12.7% over 2006 due to the consolidation of the Porto Torres plant. Excluding this effect, elastomer production increased by 6%. Increases were registered in all products, except for EPR rubber (down 2.7%) reflecting lower availability of raw materials due to technical problems at the Porto Marghera plant and lattices (down 3.8%) due to technical problems at the Hythe plant.

Polyethylene

Polyethylene sales in 2007 (1,449 ktonnes) were up 55 ktonnes or 3.9%, from 2006, reflecting positive market conditions for LPDE (up 6.7%) and EVA (up 3.6%).

Production in 2007 (1,475 ktonnes) increased by 223 ktonnes over 2006, or 17.8%, affecting all products, except for EVA (down 2%). HDPE production increased (up 78.7%) due to the consolidation of the Porto Torres

plant, also LLDPE and LDPE increased by 9.8% and 8% respectively due to the fact that 2006 was impacted by the outage of the Priolo cracker.

 

Capital Expenditures

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

 

 

Engineering & Construction

Eni operates in engineering, oilfield services and construction both offshore and onshore through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 43%). Saipem boasts strong competitive position in the relevant market leveraging on technological and operational skills, engineering and project management capabilities and ability to operate in complex environments, owing also to the integration with Snamprogetti. Considering ongoing favorable trends in demand and profitability in the market of oilfield services, Saipem intends to leverage on its skills, to carry out the following fundamental strategies: (i) to strengthen its competitive position in the field of large offshore and onshore projects for the development of hydrocarbon fields; (ii) to develop its market share in the strategic field of deepwater, FPSO, gas monetization and heavy crude upgrading; (iii) to increase efficiency levels, particularly by reducing procurement and execution costs while maintaining a high utilization rate of equipment and improving its flexible structure in order to reduce the impact of possible negative cycles; (iv) to promote use of local contractors and assets in host countries; and (v) to support Eni’s investment plans.

Saipem expects to invest approximately euro 4.7 billion over the next four years to upgrade its fleet of construction vessels and offshore drilling rigs as well as logistic centers and support facilities.

Orders acquired in 2007 amounted to euro 12,011 million, of these projects to be carried out outside Italy represented 95%, while orders from Eni companies amounted to 16% of the total. Order backlog was euro 15,390 million at December 31, 2007 (euro 13,191 million at December 31, 2006). Projects to be carried out outside Italy represented 95% of the total order backlog, while orders from Eni companies amounted to 22% of the total.

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2005

 

2006

 

2007

   
 
 
Orders acquired and breakdown by business   (million euro)   8,395   11,172   12,011
Offshore construction       3,096   3,681   3,496
Onshore construction       4,720   4,923   6,236
Offshore drilling       367   2,230   1,644
Onshore drilling       212   338   635
Originated by Eni companies   (%)   11   24   16
To be carried out outside Italy   (%)   90   91   95
Order backlog and breakdown by business   (million euro)   10,122   13,191   15,390
Offshore construction       3,721   4,283   4,215
Onshore construction       5,721   6,285   7,003
Offshore drilling       382   2,247   3,471
Onshore drilling       298   376   701
Originated by Eni companies   (%)   7   20   22
To be carried out outside Italy   (%)   88   90   95
   
 
 


Business areas

Offshore construction

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, ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to enhance its market share strengthening its EPIC oriented business model and leveraging on its relationships with major oil companies and National Oil Companies ("NOCs"). Higher levels of profitability are expected to be achieved outsourcing non core engineering and building activities to low cost centers, achieving economies of scales in its engineering hub and using local resources in contests where this represents a competitive advantage. Investments will be focused on constantly upgrading Saipem’s fleet, by building a new pipe layer, a semi-submersible unit for sub-sea development and two FPSO units to be leased to customers. These investments will allow the upgrading of operational capabilities in deepwater and sub arctic contexts. Investments will also be directed to upgrading yards and related equipment and facilities and building and upgrading local construction centers to support the execution of important projects.

Saipem’s offshore construction fleet is made up of 25 vessels and 45 robotized vehicles able to perform advanced sub-sea 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 Saibos FDS 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 orders awarded in 2007 in Offshore construction were: (i) an EPC contract on behalf of MEDGAZ for the installation of an underwater pipeline system to transport natural gas from Algeria to Spain; (ii) an EPC contract on behalf of Saudi Aramco for the construction and installation of 16 platforms, 80 kilometers of underwater pipelines and related facilities aimed at maintaining production capacity at certain oilfields in Saudi Arabia; (iii) an EPIC contract on behalf of Total for the construction and installation of a sub-sea pipeline designed to transport natural gas from Block 17 field to an onshore LNG terminal under construction in Soyo in Angola; and (iv) an EPIC contract on behalf of Enagas SA for the construction and installation of two pipelines for gas transportation in Spain.

Onshore construction

Saipem operates in the construction of plants for hydrocarbon production (separation, stabilization, collection of hydrocarbons, pumping stations, 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 (pipeline, compression stations, terminals). Saipem intends to capture opportunities arising from an expected increase in demand for those services from oil majors, by leveraging on its solid competitive position and integration with Snamprogetti engineering capabilities.

Operations are mainly conducted in Africa and the Middle East. Saipem also boasts an established presence in remote areas such as the Caspian Sea and Far East Russia, leveraging on its ability to operate in hostile

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environments, managing complex projects and enhancing local content, in addition to providing on land services complementing offshore activities (key factor in projects in areas such as the Caspian Sea).

The most significant orders awarded in 2007 in Onshore construction were: (i) an EPC contract on behalf of Qatar Fertliser Company SAQ for the construction of two new plants designed to produce ammonia and urea and associated production facilities at the Qafco industrial complex in Qatar; (ii) an EPC contract on behalf of Sonatrach for the construction of three oil stabilization and treatment trains with a capacity of 100 KBBL/d and transport and storage facilities as part of the development project of the Hassi Messaoud field in Algeria; (iii) an EPC contract on behalf of Saudi Aramco for the construction of nine sea water treatment units as part of the expansion plan of the Qurayya plant installed at the Khursaniyah field in Saudi Arabia; and (iv) an EPC contract also for the construction of in field water injection units at the Qurayya plant.

Offshore drilling

Saipem provides offshore drilling services to oil companies mainly in West Africa, the North Sea and the Mediterranean Sea. It 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. Demand for drilling services is expected to substantially increase in future years reflecting exploration and development plans of oil majors. Based on current trend in equipment availability, management expects unit tariff to rise in future years. In order to pursue market opportunities, Saipem intends to upgrade its drilling rigs, improving their technical characteristics to enhance its role as high quality player capable of operating also in complex and harsh environments. Particularly, over the next four years Saipem intends to build: (i) the two semi-submersible new generation platforms Scarabeo 8 and 9, to be employed in drilling operations in the deep-water of the Barents Sea and in the Gulf of Mexico on behalf of Eni’s upstream activity; (ii) the Perro Negro 6 to conduct operations in shallow water; and (iii) the new S12000 drilling ship to perform operations in West Africa. Significant investments are planned to upgrade the equipment considering the characteristics of certain important projects and relevant contractual conditions, as well as to set up equipment supporting the project itself.

Saipem’s offshore drilling fleet consists of 10 vessels fully equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. One of its most important offshore drilling vessels is the Saipem 10000, designed to explore and develop hydrocarbon reservoirs operating in excess of 3,000 meters water depth in full dynamic positioning. The ship has a storage capacity of 140,000 BBL and is able to maintain a steady operating position without anchor moorings by means of 6 computerized azimuth thrusters, which offset and correct the effect of wind, waves and current in real time. The vessel is operating in ultra deep waters (over 1,000 meters) in West Africa. Other relevant vessels are Scarabeo 5 and 7, third and fourth generation semi-submersible rigs able to operate at depths of 1,900 and 1,200 meters of water, respectively. Average utilization of drilling vessels in 2007 stood at 94.7% (89.6% in 2006).

The most significant contracts awarded in Offshore drilling in 2007 included: (i) a 5-years long contract for the use of the S12000 drilling ship, currently under construction, in Angola on behalf of Total. This drilling ship is expected to commence operations in the first quarter of 2010; (ii) a 12-month long contract for the use of the drilling ship Saipem 10000 in Angola on behalf of Total; and (iii) a 12-month long contract for the use of the semi-submersible platform Scarabeo 3 in Nigeria on behalf of Addax Petroleum.

Onshore drilling

Saipem operates in this area as main contractor for the major international oil companies executing its activity mainly in Saudi Arabia, North Africa and South America, where it can leverage on its knowledge of markets, long-term relations with customers and integration with other business areas. Saipem boasts a solid presence 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 2007 stood at 99.6% (94.3% in 2006). Rigs were located as follows: 13 in Peru, 12 in Venezuela, 9 in Saudi Arabia, 7 in Algeria, 3 in Kazakhstan, 2 in Italy and 1 in Ecuador.

The most significant orders awarded in 2007 in Onshore drilling were: (i) a contract on behalf of PDVSA for a five-year lease of three new rigs in Venezuela; (ii) a contract on behalf of Saudi Aramco for a three-year lease of five rigs in Saudi Arabia; and (iii) a contract on behalf of Petrobras for a four-year lease of three new rigs (one conventional rig and two new-generation hydraulic rigs) in the north-east of Brazil.

 

Capital Expenditures

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

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Corporate and other activities

These activities include the following businesses:

  the "Other activities" segment only encompasses 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 in past years; and
  the "Corporate and financial companies" segment encompasses Eni Corporate and certain Eni’s subsidiaries engaged in treasury, finance and other general and business support services. Eni Corporate is the 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 Sofid 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 intercompany basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group’s 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.

Research and Development

Technological research and innovation represent key factors in implementing Eni’s business strategies. Eni’s efforts in technological innovation are primarily intended to develop such technologies so as to meet the environmental issues and climate change, to overcome limits in accessing to hydrocarbon resources, to strengthen partnerships with producing countries and to develop renewable sources of energy.

Eni is conducting R&D activities aimed primarily at reducing the costs of finding and recovering hydrocarbons, upgrading heavy oils, monetizing stranded gas and protecting the environment. Over the next four years, Eni plans to invest approximately euro 1.7 billion to implement its strategy in technological innovation matters. Particularly, the main management expects to upgrade the following lines of R&D:

  Reserve replacement ratio and reduction of mineral risk;
  Production and exploitation of unconventional hydrocarbon reserves and optimization in managing reserves with a high level of hydrogen sulphide and sulphur;
  Expansion of the natural gas market and monetization of flaring gas or localized in remote areas;
  Better quality and performance of fuels, in connection with the evolution in the automotive sector towards even more improved systems, efficient and with lower impact on air quality; and
  Efficient exploitation of fossils, improved distillate yield and optimal use of fossils with a lower environmental impact.

With regards to environmental protection, Eni intends to develop the "Along with Petroleum" program aimed at identifying and developing research projects on the most advanced aspects of large scale use of renewable energy sources and energy efficiency. Over the next four years, approximately euro 120 million will be addressed to this program. In particular, Eni expects to focus on the fields of greenhouse effect mitigation through bio-fuels, photovoltaics, solar energy, hydrogen production from renewable sources as well as carbon dioxide capture and geological sequestration.

In 2007, Eni’s expenditures on R&D amounted to euro 208 million which were almost entirely expensed as incurred. 47% of R&D expenditures were directed to the Exploration & Production segment, 32% to the Refining & Marketing segment, 14% to the Petrochemical segment and 7% to the Engineering & Construction segment. Eni’s expenditures on R&D amounted to euro 220 million and euro 204 million in 2006 and 2005.

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At December 31, 2007, a total of 1,082 people were employed in research and development activities.

In 2007, a total of 69 applications for patents were filed.

 

 

Insurance

Eni constantly assesses its exposure for the Italian and foreign activities that are mainly covered through the Oil Insurance Limited ("OIL"), a mutual insurance and reinsurance company that provides its members a broad coverage tailored to the specific requirements of oil and energy companies. Eni makes use of a captive insurance company that covers the risks and implements Eni’s Worldwide Insurance Program re-insured with high quality securities in order to integrate the terms and conditions of the OIL coverage.

An insurance risk manager works in close contact with managers directly involved in core business activities in order to evaluate potential risks and their financial impact on the Group. This process allows Eni to define a constant level of risk retention and, conversely, the amount of risk to be transferred to the market.

The level of insurance maintained by Eni is generally appropriate for the risks of its businesses.

 

 

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 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.

A brief description of major environmental laws impacting Eni’s activities located in Italy and Europe is outlined below.

               Italy
On April 29, 2006, Legislative Decree No. 152/2006 "Environment Regulation" came into force. This 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);
  procedure 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;
  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, criteria for waste classification.

The Decree 152/2006 was amended by two subsequent decrees: Legislative Decrees 284/2006 and 4/2008; the latter introduced important changes regarding SEA and EIA procedures, landfill, waste and remediation. A principle of waste hierarchy was introduced along with definition of by-product and secondary raw materials.

The most important aspects of these regulations to Eni are those regulating permits for industrial activities, waste management, remediation of polluted sites, water protection and environmental liability.

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               European Union
On January 29, 2008, the new IPPC (Integrated Pollution Prevention and Control) directive 2008/1/EC was published in the Official Journal of the European Union No. 24. Therefore, from February 18, 2008, the new IPPC directive repeals the Directive 96/61/EC with its successive amendments. This directive rationalizes all existing regulations on this issue, confirming the achievement of high levels of environmental protection to be of primary importance to member states.

According to the IPPC Directive, the 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. The European Commission published in Official Journal of European Union, May 16, 2007 (2007/C 110/01) the definitive replacement of the European Pollutant Emission Register (EPER) by the European Pollutant Release and Transfer Register (E-PRTR), published in 2006 (Regulation No. 166/2006). 2009 will be the first year of implementation of measures intended to publicly disclose environmental data collected in 2007 according to PRTR register. Eni is implementing an Integrated Environmental Information System, able to gather, manage and report the data on all the pollutants requested by PRTR Regulations.

On December 21, 2007, the European Commission published its proposal of directive on the issue of industrial emissions. In view of the general call for "better regulation", the draft incorporates the reviews of six sector-specific directives (IPPC, Large Combustion Plants, VOC - Volatile Organic Compounds - emissions, incineration of waste and titanium industry). The draft of directive intends to enforce BAT definition, together with a tightening of current minimum emission values in some sectors. The directive extends the scope of the IPPC directive to cover certain activities (e.g. combustion plants between 20 and 50 MW). The new proposal introduces also more robust monitoring and inspections on installations, the review of permit conditions and the reporting of compliance.

In December 2005, the European Commission proposed a Waste Framework Directive which is now at the last stage of elaboration. The draft introduces a new waste strategy and proposes 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. Moreover the new proposal simplifies waste legislation by clarifying definitions, streamlining provisions and integrating the directives on hazardous waste (91/689/EEC) and on waste oils (75/439/EEC).

HSE Activity for the Year

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

In 2007, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. In 2007, the total number of certifications obtained was 212 (185 in 2006), of which 113 certifications according to the ISO 14001 standard, 9 certifications according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 28 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements).

Environment. In 2007, Eni incurred total expenditures amounting to euro 1,063 million for the protection of environment, down 8.4% from 2006. Current environmental expenses represented approximately 64% of the whole environmental expenditure and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure mainly related to soil and subsoil protection, water management and air emissions.

Safety. The safety of Eni’s employees and contractors, people living in the area where its industrial activities and assets are located, is of fundamental importance to the Company.

As to safety regulations, in 2008 the Legislative Degree No. 81/2008 on health and safety in workplaces came into force. This decree meaningfully increases the administrative responsibility of companies for violating applicable laws regulating work safety in industrial sites, also requiring a lot of attention on part of people in charge of supervisory and managing functions.

Eni’s safety strategy is based on:

  the dissemination of a safety culture within its organization;
  a comprehensive policy, specific guidelines and proper management systems in line with International standards and best practices;

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  identification of all exposures and risks related to processes, products and operations performed, control, prevention and protection from exposure to dangerous situations; and
  minimization of exposure to risk in all production activities.

In 2007, safety indicators improved from 2006. The injury frequency rate was 3.01, down 5%, and the injury severity rate was 0.10 in line with 2006.

Costs incurred in 2007 to support the safety levels of operations and to comply with applicable rules and regulations were euro 468 million, up 18.8% from 2006.

Health. Eni’s activities for protecting health aim at the continuous improvement of work conditions. They address the following issues:

  improvement of efficiency and reliability of plants;
  adoption of best practices and operating management systems based on advanced criteria of protection of health and the internal and external environment;
  research and innovation, specifically with reference to health issues and the exposure to work-related risks;
  results of internal and external audits;
  identification and monitoring of indicators and guidelines for analysis and intervention areas; and
  certification programs of management systems for production sites and operating units.

To protect the health and safety of its employees, Eni relies on a network of 296 health care centers located in its main operating areas; of these, 203 centers are outside Italy. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies.

In 2007, Eni incurred a total expense of euro 54 million to protect the health of its employees.

 

Implementation of the Kyoto Protocol

On February 16, 2005, the Kyoto Protocol entered into force and, with it, the commitments of the Annex I Parties which have ratified 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 fulfil the Kyoto compliance.

Italy, as an EU Member State, is part of the EU Emission Trading Scheme ("ETS") that was established by Directive 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. Eni is part to the ETS. Moreover, Eni is active in the utilization of 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 of the Environment signed a Voluntary Agreement for using flexible mechanisms, promoting CDM and JI and contributing to the sustainable development of host countries.

The ETS EU directive provides that each Member State shall ensure that any operator who produces GHG emissions in excess of the amounts awarded based on national allocation plan, will provide allowances to cover excess emissions a year later in addition to pay a penalty. The excess emissions penalty shall be EUR 100 (EUR 40 for the first period 2005-2007) for each tonne of carbon dioxide equivalent emitted. All companies are expected to identify and carry out projects for emission reductions. Eni participates in the ETS scheme with 56 plants in Italy and 1 outside Italy, which collectively represent about a third of all greenhouse gas emissions generated by Eni’s plants worldwide. In the whole period (2005-2007) Eni was entitled to allowances equal to 77.2 mmtonnes of carbon dioxide for existing and new installations (of which 25.7 mmtonnes of carbon dioxide for 2007). 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 complied with mandatory limits in the whole period.

Management believes that a significant emission reduction can be achieved in connection with oil and gas production activities outside Italy, that in a number of cases, given lack of local market outlets, require the flaring of natural gas associated to oil production. The elimination of flaring and the use of associated gas for the development of local economies allow sustainable development while reducing greenhouse gas emissions. The validation of such projects as CDM and JI will provide emission credits and facilitate the achievement of the Italian reduction target, as

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set by the Kyoto Protocol. Eni already carried out Zero Gas Flaring projects in Nigeria and Congo while others are underway. In November 2006 the Nigerian Kwale-Okpai project has been registered as a CDM project. It regarded the construction of a combined cycle power station, which utilizes the associated gas to oil production formerly flared. More projects are being assessed or implemented in Congo, Nigeria and Angola. Moreover, Eni endorsed the Global Gas Flaring Reduction Initiative of the World Bank, in order to fight for the elimination of obstacles to the completion of gas flaring reduction projects.

The best solutions for compliance with the Kyoto Protocol are the use of low emission energy sources and the 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.

To ensure comprehensive, transparent and accurate accounting for GHG emissions, which is consistent over time, Eni introduced in 2005 its own Protocol for the accounting and reporting of greenhouse gas emissions (GHG Accounting and Reporting Protocol), which is an essential requirement for emission certification. Indeed, accurate reporting will support the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the evaluation of progress.

For safer and more accurate management of GHG emissions and with a view to supporting accounting, Eni provided all its divisions and 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.

As a support to its general strategy for a sustainable management of greenhouse gases, Eni continued its programs for the development of natural gas in Italy and outside Italy, by means of technologically advanced projects such as the Blue Stream gas pipeline from Russia to Turkey and the GreenStream pipeline from Libya to Sicily. Increased gas availability in Italy will lead to a further expansion of the gas-power integration, through high efficiency combined cycles with much lower carbon dioxide emissions than coal and liquid fuels.

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. In the long-term, Eni is actively engaged in the political process regarding future emission reduction regulations. In particular Eni is involved in bioenergy and biofuels.

Regulation of Eni’s Businesses

Overview

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

 

Regulation of Exploration and Production Activities

Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil 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

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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 Agreement (PSAs), 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 recover 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 PSAs 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 an additional five-year extension until the field depletes.

Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. Royalties are equal to 7% and 4%, respectively, for onshore and offshore production of oil and 7% for both onshore and offshore production of natural gas.

Storage of natural gas

Storage activities in Italy are regulated by Legislative Decree No. 164/2000 ("Decree No. 164"), which enacted the European Directive on Natural Gas 98/30/CE into Italian legislation. 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 at most 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 importing from non-EU countries, which have to provide a strategic storage capacity in Italy corresponding to 10% of the amount of natural gas imported each year; (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 Authority for Electricity and Gas 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 expenditure for upgrading the storage system; and (vii) the Authority for Electricity and Gas establishes the criteria and priority of access storage operators have to include in their own storage codes.

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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.

On March 3, 2006, the Authority for Electricity and Gas with Resolution No. 50/2006 published the criteria for determining storage tariffs for a regulated period starting from April 1, 2006 and ending on March 31, 2010.

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 7.1% (8.33% in the first regulated period);
(ii)   depreciation and amortization charges; and
(iii)   operating costs.

In the years following the first year of the newly 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.

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.

In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regards to the lack of investments by operators aimed at expanding natural gas storage capacity to store natural gas in Italy. Eni, through its wholly-owned subsidiary Stogit Italia, owns nearly the entire storage capacity currently existing in Italy.

With Resolution No. 220/2006, the Italian Authority for Electricity and Gas approved the storage code proposed by Stoccaggi Gas Italia on the basis of the framework and criteria established by Resolution No. 119/2005 ("Adoption of guarantees for free access to natural gas storage services, duties of subjects operating storage activities and rules for the preparation of a storage code").

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 code has been in force since November 1, 2006.

The storage company offers services according to an access priority established by the Italian Authority for Electricity and Gas 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. 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 of Economic Development.

The strategic storage service aims to satisfy certain obligations of natural gas importers from countries not belonging to the EU in accordance with Article 3 of Legislative Decree No. 164/2000. The relevant storage capacity dedicated to this service is determined by the Ministry of Economic Development.

Storage capacity is awarded by the storage company for periods no longer than a thermal year by April 1, of each year. 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

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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.

Eni held natural gas for strategic reserve purposes in its storage business, as established by Decree No. 164. 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 of the Economic Development determines quantities and usage criteria of such reserves. As of December 31, 2007 Eni held approximately 179 BCF of strategic reserves of natural gas (180 BCF at year end 2006).

 

Gas & Power

Natural gas market in Italy

The European Directive on Natural Gas was implemented into Italian legislation through Legislative Decree No. 164 of May 23, 2000 ("Decree No. 164"), effective from June 21, 2000. As concerns natural gas activities carried out by Eni, the most relevant aspects of the decree are as follows:

(i)   Starting in 2003 all customers are eligible customers (with access to the natural gas system and free to choose their supplier of natural gas);
(ii)   Antitrust thresholds are in place for gas operators in Italy as follows: (a) effective January 1, 2002, operators are prohibited to transmit into the national transport network imported or domestically produced gas volumes higher than a preset share of Italian final consumption. This share is 75% of total final consumption in the first year of regulation and then is to decrease by 2 percentage points per year to reach a 61% threshold in terms of final consumption by 2009; and (b) effective January 1, 2003, operators are prohibited to market gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified yearly by comparing actual average shares obtained by any operator in a given three-year period for both volumes input and volumes marketed to customers with average shares permitted by the law for the same period. Actual shares are computed net of losses (in the case of sales) and volumes of natural gas consumed in own operations. Based on a bill passed by the Italian upper house, Eni expects that these antitrust thresholds will be renewed when they expire in 2010;
(iii)   natural gas transport and dispatching activities have to be carried out by a separate company that is not allowed to carry out any other activity in the natural gas field, with the only exception of storage, for which, however, accounting and operating separation is envisaged. Also distribution, which includes the transport of natural gas by means of local gas pipeline networks for delivery to customers, has to be carried
    out by a separate company which cannot perform other gas related activities. Sales activity to final customers is compatible only with import, export and production activities and is subject to authorization from the Ministry of Productive Activities. Concessions for the distribution of natural gas will be awarded by bid procedure; and
(iv)   tariff criteria and return on capital employed for transport, dispatching, storage, use of LNG terminals and distribution are determined by the Authority for Electricity and Gas. Third parties are allowed to access transport infrastructure, storage sites, LNG terminals and distribution networks on a regulated basis. As provided for by the decree, a Network Code containing norms and regulations for the operation of and access to infrastructure was prepared by operators on the basis of criteria set by the Authority for Electricity and Gas.

In 2007, the fourth three-year regulated period closed for natural gas volumes input in the domestic transport network (for which the allowed average percentage was 67% of domestic consumption of natural gas) and the second three-year regulated period for sales volumes (for which the allowed average percentage is 50% of gas sales). In this three-year period Eni’s presence on the Italian market complied with said limits.

Law No. 239 of August 23, 2004 on the restructuring of the energy sector in Italy

This law provides for:

  a derogation to third party access granted 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 conferral of new capacity for a portion of not less than 80% of the new capacity installed and for a period of at least 20 years;
  paragraph 69 provides the authentic interpretation of the rule introduced by Legislative Decree No. 164/2000 concerning the transitional regime of concessions for natural gas distribution activities in urban centers existing at June 21, 2000, which allows for an anticipated repayment of the distribution service, despite being provided through a bid procedure rather than direct entitlements. This law changes the provisions defined by Legislative Decree No. 164/2000 by: (i) extending to December 31, 2007, the

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    transitional period for the continuation of existing concessions, with a possible extension of one further year when public interest is considered important by local authorities; and (ii) canceling the adding up of possible extensions, as provided for by Legislative Decree No. 164/2000, in case of certain conditions (business restructuring, size parameters, shareholding composition). The end of concessions awarded on the basis of a bid procedure remains set at December 31, 2012.

Law Decree No. 239/2003 and Budget Laws for 2006 and 2007

Law Decree No. 239/2003, converted with amendments into Law No. 290/2003, prohibits companies operating in the natural gas and electricity industries to hold stakes higher than 20% in the share capital of companies owning and managing national networks for the transmission of natural gas and electricity. The term by which companies must comply with this provision is December 31, 2008 as established by the Budget Law for 2006. The Italian Budget Law for 2007 establishes that the provisions to implement Law No. 290/2003 will be enacted through a decree from the Italian Prime Minister. The term for the disposal envisaged by Law No. 290/2003, which was initially fixed at December 31, 2008, will be re-determined in 24 months after the effective date of said decree from the Italian Prime Minister. Currently, Eni is unable to predict that date.

In addition, on March 23, 2006 a Presidential Decree defined criteria and methods for the divestment of the interest held by Eni in Snam Rete Gas SpA, introducing the special powers of the Ministry of Economy and Finance provided for by the regulations on the divestment of interests held by the Italian Government ("golden share") in the By-laws of this company.

Natural gas prices

Prices of natural gas sold to industrial and thermoelectric customers as well as to wholesalers are freely established among buyers and sellers following the liberalization of the natural gas sector introduced by Decree No. 164. Notwithstanding this, the Authority for Electricity and Gas holds a power of surveillance on this matter (see below) under Law No. 481/1995 (establishing the Authority for Electricity and Gas) and Legislative Decree No. 164/2000. Furthermore, the Authority is entrusted with the power of regulating natural gas prices to residential and commercial customers which were not eligible customers until December 31, 2002.

In fact, the Presidential Decree dated October 31, 2002 entrusted the Authority for Electricity and Gas with the power to define, calculate and update gas selling prices for customers who were not-eligible customers until December 31, 2002, also after the opening up of the gas markets from January 1, 2003, additionally targeting the public goal of containing inflationary pressure deriving from increasing energy costs. Consistently with this decree, the Authority for Electricity and Gas: (i) with Decision No. 195 of November 29, 2002 changed the methods for periodically updating selling prices for natural gas in connection with changes in international prices of crude oil and refined products. Such changes regarded the scheduled update process (from every two months to every three), and the duration of the reference period for the calculation of changes in average international prices as compared to the first application quarter (changes are calculated with reference to a nine-month period preceding the update). The invariance threshold, beyond which tariffs are updated, remained at 5%; and (ii) with Resolution No. 207 of December 12, 2002, it decided that companies selling natural gas through local networks have to maintain the conditions applied to non-eligible customers until December 31, 2002 until the customer accepts a new contract offer. In addition, the Authority for Electricity and Gas decided that these companies can propose their own new contract offers and the tariffs determined according to the criteria established by the Authority for Electricity and Gas, adequately advertising them before March 31, 2003 (such offers must be published on the companies web page, on at least one newspaper of general circulation and on the Gazzetta Ufficiale of their region or autonomous province).

Changes introduced to the indexation mechanism of the raw material component in supplies to residential customers by the Authority for Electricity and Gas: Resolutions No. 248/2004; 134/2006 and 79/2007

With Resolution No. 79/2007 the Italian Authority for Electricity and Gas, after concluding a consultation procedure with gas operators also taking account of the annulment of its Resolution No. 248/2004 due to formal flaws by the Administrative justice bodies, established a new indexation mechanism for the raw material cost component in natural gas supplies to customers consuming less than 200,000 CM/y who were not-eligible customers until December 31, 2002 (mainly residential and commercial customers located in urban centers). This Resolution reorganized in a single measure this matter. In particular with this Resolution the Authority: (i) confirmed the indexation mechanism for the raw material cost component contained in Resolution No. 248/2004 and the changes introduced to this mechanism by Resolution No. 134/2006 starting on July 1, 2006 (see below for a full description of said indexation mechanism); (ii) waiving this provision, it reviewed the updating of the raw material cost component for 2005 determining incremental values equal to those deriving from the application of the indexation criteria of Resolution No. 195/2002; this provision resulted in the annulment of the negative impact of Resolution No. 248/2004 on Eni’s 2005 accounts; and (iii) decided that selling companies, only for wholesale purchase/sale contracts entered after January 1, 2005 and in place in the January 1, 2006-June 30, 2006 period, would offer their customers new contractual conditions consistent with the new indexation mechanism and inform the Authority of

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contract updates. Selling companies complying with this requirement would be entitled to 50% of the difference between the updating of the raw material cost component under the new mechanism and the more favorable one under Resolution No. 195/2002 applied to volumes consumed by customers under the 200,000 CM/y threshold. On the basis of this Resolution in 2007, Eni reversed part of the reserves accrued in Eni’s accounts for 2005 and 2006 with respect to the estimated impact of Resolution No. 248/2004. See "Item 5 – Results of Operations – Gas & Power".

The new indexation mechanism of the raw material cost component in tariffs paid by end customers consuming less than 200,000 CM/y as set in Resolution No. 79/2007 basically works this way: (i) it has limited the ability of gas operators to transfer to customers changes in the raw material cost by setting a cap of 75% for changes in the raw material component linked to a fall in Brent crude prices below 20 $/BBL or a rise within the 35-60 $/BBL range, raising the cap at 95% if Brent crude prices are higher than 60 $/BBL; (ii) it has changed the relative weight of the three products making up the reference index of energy prices whose variations – when higher or lower than 2.5% as compared to the same index in the preceding period – determine the adjustment of raw material costs; (iii) it has replaced one of the three products included in the index (a pool of crudes) with Brent crude; and (iv) it has reduced the value of the variable wholesale component of the selling price by 0.26 euro/CM.

This indexation mechanism applies for a two-year period effective July 1, 2006, with the option of a one year extension following a decision of the Authority.

Transport

Transport tariffs. With Resolution No. 120 of May 30, 2001, the Authority for Electricity and Gas published the criteria transport companies have to apply in determining natural gas transport and dispatching tariffs on national and regional transportation networks, for the first regulatory period made up of four thermal years (each thermal year begins on October 1 of each calendar year and ends on September 30), as provided for by Decree No. 164/2000. Tariffs are subject to approval by the same Authority, which ensures their compliance with preset criteria. This tariff system substituted previous agreements between Eni and customers of all categories. Within the first quarter of each calendar year, transport companies submit the tariff proposal to the Authority for Electricity and Gas who grants approval.

Criteria established by the Authority for Electricity and Gas set a cap on revenues from transport and dispatching activity ("allowed revenues") which is adjusted annually; the criteria also define a separate treatment of revenues on existing assets and on new capital expenditure on expansions and extension of infrastructure. In the first thermal year allowed revenues 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. Net capital employed is calculated by reevaluating historic costs of transport infrastructure (pipelines, compressor stations and other support equipment) on the basis of certain inflationary indexes; resulting amounts are adjusted to take into account the residual useful life of assets (pipelines are estimated to have a useful life of 40 years) and also subtracting State grants. The application of this methodology implies an estimated value of Eni’s transport assets of approximately euro 9.6 billion. This, however, is a valuation for regulatory purposes and should not be read as an indication of the market value of Snam Rete Gas. The rate of return on capital employed set by the Authority for Electricity and Gas was 7.94% (pre-tax), for the first regulatory period. Once established, allowed revenues for the first year are divided into two components: (i) capacity revenues equal to 70% of allowed revenues which are the maximum amount of revenues collectable from the sale of transport capacity to customers; and (ii) commodity revenues equal to 30% of allowed revenues which are the maximum amount of revenues collectable from transported volumes.

Starting from the second year these two components are adjusted on a yearly basis to take into account inflation and certain reduction factors (set at 2% and 4.5% for capacity revenues and commodity revenues, respectively); commodity revenues are also adjusted to transported volumes of the current regulatory period. The 2% reduction factor on capacity revenues provides scope for improving results of operations of the transport company if cost reductions exceed the set amount, whereas the 4.5% reduction factor on commodity revenues provides scope for improving results of operations of the transport company if transported volumes grow more than the reduction factor. New capital expenditures in extension and expansion enable transport companies to increase the capacity revenue by a stated percentage in the regulatory period following the period in which new capital expenditures are incurred. In addition, those capital expenditures give rise to a six year fixed increase in allowed commodity revenues. At the end of the first regulatory period, all transport cost components were recalculated and 50% of higher cost reductions with respect to established efficiency improvements were recognized to transport companies and 50% were transferred to customers. Once the allowed revenues are established, transport companies define individual tariffs to clients which are based on a charge for the capacity used at the entry location (border, fields, storage sites) and the capacity used at interconnection nodes with regional networks (divided into 17 zones) and on a charge for the capacity used at regional level, providing for discounts to those outgoing the network at less than 15 kilometers from the interconnection point between regional and national networks. A further charge (commodity charge) is related to the amounts of gas transported plus an annual fixed charge varying according to the delivery

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points. This tariff system regulated the four-thermal year period starting October 1, 2001 and ending on September 30, 2005.

With Resolution No. 166/2005, the Authority for Electricity and Gas revised the outlined tariff regime for the second regulatory period (October 1, 2005-September 30, 2008). The new tariff structure confirms the breakdown of the tariff into two components: capacity and commodity in a ratio of 70 to 30 and the entry-exit model for the determination of the capacity component on the national pipeline network, already present in the previous tariff regime established by Resolution No. 120/2001. The major new elements of the new regime are the following: (i) a reduction of the rate of return of capital employed in transport activities from 7.94% to 6.7% (pre-tax); (ii) a new set of incentives for new capital expenditure. In the previous regime, the return on upgrade and capacity expansion expenditure was 7.47% for one year only included in the calculation of the capacity component of the transport tariff and 4.98% for 6 years in the calculation of the commodity component. The new tariff structure provides an additional rate of return depending on the type of expenditure on the return rate recognized for capital employed: from a minimum of 1% for safety measures that do not increase transport capacity, applied for 5 years, to a maximum of 3% for expenditure that increases capacity at entry points into the national network, applied for 15 years. The additional return is part of the determination of the maximum allowed revenues in the calculation of the capacity component of the tariff and therefore is not influenced by changes in volumes transported; (iii) the updating by means of a price cap mechanism of the allowed revenues the transport undertaking is entitled to and the annual recalculation of the portion of allowed revenues relating to costs incurred for capital expenditure. This price cap mechanism applies to operating costs and amortization charges (previously it applied to all the allowed revenues). The annual rate of recovery of productivity was confirmed at 2%; this is used to reduce the effect of changes in the consumer price index on the updating of the preceding year’s allowed revenues; instead the preset annual rate of change of productivity recovery for the updating of the commodity component of the tariff was reduced from 4.5% to 3.5% of; and (iv) confirmation of the tariff reduction for start ups (construction/upgrade of combined cycle plants for electricity generation) and for off take in low season periods (from May 1 to October 31) already contained in Decisions No. 5/2005 and 6/2005 which updated the previous tariff regime. The companies active in the field of gas transport submit their tariff proposals to the Authority who grants approval, within the first quarter of each calendar year.

Network code. With Resolution No. 75 of July 1, 2003, the Authority for Electricity and Gas approved Snam Rete Gas Network Code, which defines rules and regulations for the operation and management of the transmission network. The Network Code, in accordance with Legislative Decree No. 164/2000, is based on the criteria set by the Authority for Electricity and Gas with Resolution No. 137/2002, aimed at guaranteeing equal access to all customers, maximum impartiality and neutrality in transport and dispatching activities. The Network Code regulates entitlement of transport capacity, obligations of transporter and customer and the procedures through which customers can sell capacity to other users. Transport capacity at entry points in the national gasline network (point of interconnection with import gas lines) is assigned on an annual basis and can last up to five thermal years.

Entities eligible to be assigned transport capacity on a multi-year basis are those having multi-year import contracts within the limit of their daily average contract volumes. Priority criteria envisage that available capacity is assigned first to parties in multi-year import contracts containing take-or-pay clauses signed before August 10, 1998 (date of coming in force of European Directive 98/30/CE). If requests for capacity in a given thermal year are higher than available capacity, a pro-rata mechanism is applied in compliance with the aforementioned priority.

Parties in annual or shorter import contracts and parties in multi-year import contracts are entitled to annual capacity conferrals corresponding to maximum daily contract volumes and the difference between maximum daily contract volumes and average daily contract volumes, respectively. Available transport capacity is assigned first to parties in annual import contracts and parties in multi-year import contracts. If requests for capacity in a given thermal are higher than available capacity, a pro-rata mechanism is applied in compliance with the aforementioned priority.

Eni filed a claim against this decision with the Regional Administrative Court of Lombardy, which was partially accepted with a decision of December 2004. The Authority filed a claim against this decision with the Council of State and informed Eni on February 19, 2005. This proceeding is still pending.

Regulation (EC) No. 1775/2005. On November 3, 2005 Regulation (EC) No. 1775/2005 concerning conditions for accessing international natural gas transport networks was published. The Regulation establishes non discriminatory access rules and will be effective starting on July 1, 2006. The Regulation will be directly applicable in each Member State and national regulatory authorities will be responsible for its enactment. Eni’s transport network code is compliant with this regulation.

Adoption of guarantees for free access to LNG regasification services and rules for the regasification code. With Resolution No. 167 of August 1, 2005, the Authority for Electricity and Gas published the criteria for access to LNG regasification services. The Decision also defines criteria for the allocation of regasification 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 regasified in the period starting from

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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 of 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 No. 237 dated December 28, 2000 as amended, the Authority for Electricity and Gas determined tariff criteria for natural gas distribution activity for the first regulated period ending on September 30, 2004. Tariffs are determined so that annual revenues from natural gas distribution activity cover operating costs and the remuneration of capital employed and are adjusted yearly according to the price cap method based on parameters and formulas determined by the Authority for Electricity and Gas. Capital employed is determined by applying a parameter-based method or, alternatively, a method of revalued historical cost for those companies that published audited financial statements starting from the fiscal year ended before January 1, 1991 (which include Italgas). With Resolution No. 170 of September 29, 2004 the Authority for Electricity and Gas defined gas distribution tariffs for the second regulated period from October 1, 2004 to September 20, 2008, setting at 7.5% the rate of return on capital employed of distribution companies, as compared to the 8.8% rate set for the preceding regulated period. The rate of productivity recovery – one of the components of the annual adjustment mechanism of tariffs – was set at 5% of operating expenses and amortization charges (as compared to the 3% rate applied to total expenses and charges in the preceding regulated period). With Resolution No. 122 of June 21, 2005, the Authority integrated and changed Resolution No. 170/2004, defining a new determination mechanism for distribution tariffs that takes account of capital expenditures incurred by distributing companies.

 

Refining and Marketing of Petroleum Products

Refining. Under Decree No. 112, companies that seek to establish refining operations in Italy or to expand the capacity of existing refining operations must obtain an operating concession from the relevant Region, while companies that seek to build or operate new plants that do not increase refining capacity must obtain an authorization from the relevant Region. Management expects no material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term.

Service stations. Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 348 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, significantly changed Italian regulation of service stations. The decree replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities. Legislative Decree No. 112/1998 confers the power to grant concessions for the construction and operation of service stations on highways to Regions. Decree No. 32 also requires that contracts between license holders and service station operators have a duration of not less than six years and be drafted in accordance with arrangements agreed by the relevant trade group of license holders and the union representatives for the service station operators. 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 goal of renewing the Italian distribution network, Law No. 57/2001 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 decree was issued on October 31, 2001 and established 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.

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.

With a recommendation approved at its meeting of January 18, 2007 and submitted to the Government and the Regions, the Italian Antitrust Authority requested the elimination of local constraints to the opening up of the fuel distribution outlets aimed at increasing competition and reducing retail prices. Specifically, the Authority urged the following measures in order to enhance the level of competition in the sector of retail marketing of fuels: (i) the development of the marketing of fuels by large retailers (supermarkets, large chain-stores, etc.); (ii) the elimination of administrative constraints to the opening of new service stations; (iii) a liberalization of opening hours; and

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(iv) transparency for consumers, identifying any useful tools for proper information on actual prices imposed by operators in each outlet. Currently, Eni is unable to forecast a time frame for this matter. Implementation of any of these suggested measures could enhance the level of competition in the retail marketing of fuels, leading to a reduction in retail margins for all operators.

Compulsory stocks. According to Legislative Decree of January 31, 2001, No. 22 ("Decree 22/2001") enacting European Directive No. 98/1993 (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 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 22/2001 states that compulsory stocks are determined each year by a decree of the Minister of Productive Activities 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.

At December 31, 2007 Eni owned 7 mmtonnes of oil products inventories, of which 4.8 mmtonnes as "compulsory stocks", 1.4 mmtonnes related to operating inventories in refineries and depots (including 0.2 mmtonnes of oil products contained in facilities and pipelines), 0.4 mmtonnes related to oil products contained in ships and 0.4 mmtonnes related to specialty products.

Eni’s compulsory stocks (at December 31, 2007) were held in term of crude oil (35%), light and medium distillates (41%), fuel oil (19%) and other products (5%) and they were located throughout the Italian territory both in refineries (73%) and in storage sites (27%).

 

Competition

Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in 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 ("Article 81" and "Article 82", respectively being the result of the new denomination of former Articles 85 and 86) and EU Merger Control Regulation No. 4064 of 1989 ("EU Regulation 4064"). Article 81 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 82 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among member states. EU Regulation 4064 sets certain 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 81 and 82 of the Treaty. In order to simplify the procedures required of undertakings in case of concentration, the new regulation substitutes the obligation to inform the Commission with a declaration that such concentration does not infringe the Treaty. In addition, the burden of proving an infringement of Article 81(1) or of Article 82 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 81(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 81 and 82 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions:

  requiring that an infringement be brought to an end;
  ordering interim measures;
  accepting commitments; and
  imposing fines, periodic penalty payments or any other penalty provided for in their national law.

National courts shall have the power to apply Articles 81 and 82 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 81 or of Article 82 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 81 and 82 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 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 "Antitrust Law"). In accordance with the EU competition rules, the Antitrust Law prohibits collusion among competitors that restricts

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competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers. The Antitrust Authority has intervened on the basis of the Antitrust Law in several instances, particularly in order to prohibit the imposition of discriminatory tariffs in the telecommunications, railway and air transport sectors, among others.

 


Property, Plant and Equipment

Eni has freehold and leasehold interests in real estate in numerous countries throughout the world, but no one individual property is material to Eni as a whole. See "Exploration & Production" above for a description of Eni’s 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, 2007, there were 341 subsidiaries, of which 257 were fully consolidated and 84 entities were accounted for under the equity or cost method. For a list of subsidiaries of the Company, see "Exibit 8 – List of Eni’s fully consolidated subsidiaries for year 2007".

 

 

Item 4A. UNRESOLVED STAFF COMMENTS

None.

 

 

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 and IFRS as adopted by the European Union.

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 iii.

 


Executive Summary

In 2007, net profit attributable to Eni amounted to euro 10,011 million, representing an increase of 8.6% from 2006.

Operating profit in 2007 amounted to euro 18,868 million, down 2.4% from 2006, mainly reflecting lower operating profit reported by the Exploration & Production segment, down euro 1,792 million from 2006, or 11.5%. This reduction was mainly due to a negative impact of the appreciation of the euro against the dollar, rising operating costs and amortization charges, higher exploration expenditures and lower production volumes. These negative factors were partly offset by improved operating profit recorded by:

(i)   the Refining & Marketing segment, which reported an increase in operating profit of euro 410 million over 2006. This improvement mainly reflected a gain deriving from the impact of higher year-end prices on the valuation of year-end inventories of oil and refined products under the weighted-average cost method of accounting. This method of accounting for inventories of oil, gas and products implies a high degree of volatility in Eni’s results of operations for the Refining & Marketing segment as inventory valuation is based on current market prices. This positive effect was partly offset by lower realized refining margins, mainly for complex refineries, and the appreciation of the euro over the dollar;
(ii)   the Engineering & Construction segment, which reported an increase in operating profit of euro 332 million over 2006. This increase mainly reflected an improved underlying performance against the backdrop of favorable market trends; and

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(iii)   the Gas & Power segment, which reported increased operating profit of euro 325 million over 2006. This improvement mainly reflected a positive development with Italy’s regulatory framework on gas pricing to residential clients and resellers and an improved operating performance delivered by the regulated business in Italy.

Eni’s net profit for the year was supported by lower income taxes, down euro 1,349 million, mainly reflecting a one-time gain due to implementation of certain changes to the tax regime applicable to Italian subsidiaries (net gain of euro 394 million) as well as recognition of certain deferred tax liabilities in the previous year in connection with changes in the tax regime applicable to certain of the Group’s oil and gas operations (totaling euro 347 million). Higher income from equity-accounted entities and gains on divestments were recorded (up euro 340 million). These positives were partly offset by higher net interest expenses mainly due to an increased level of net borrowings (up euro 244 million).

Net cash provided by operating activities of euro 15,517 million, coupled with cash from divestments (euro 659 million), was used to partially fund the cash outflows related to: (i) capital and exploratory expenditures totaling euro 10,593 million; (ii) the acquisition of investments and businesses (euro 9,665 million); and (iii) a dividend distribution to Eni’s shareholders (euro 4,583 million) and Eni share repurchases (euro 680 million), as well as minority dividend payments and share repurchases relating mainly to the listed subsidiaries Snam Rete Gas SpA and Saipem SpA (totaling euro 647 million).

As of December 31, 2007 net borrowings amounted to euro 16,327 million, a euro 9,560 million increase over 2006, more than 100%, reflecting the large amount of capital expenditures and acquisitions executed in the year which was only partially funded with cash flows from operations.

On the basis of the results achieved, Eni’s management proposed to the Annual Shareholders’ Meeting the distribution of a dividend of euro 1.30 per share, of which euro 0.60 was already paid as interim dividend in October 2007. This dividend is 4% higher than in 2006 (euro 1.25 per share) and was approved by the Annual Shareholders’ Meeting on April 29, 2008.

Eni’s oil and gas production for the year (on an available for sale basis) decreased by 2.1% from 2006 to 1,684 KBOE/d. This result was affected by:

(i)   disruptions in Nigeria due to social unrest (down 25 KBOE/d compared to 2006);
(ii)   unplanned downtime and technical issues in the North Sea and mature field declines, particularly in Italy and the United Kingdom; and
(iii)   lower entitlements in certain Production Sharing Agreements (PSAs) and similar contractual schemes (down 15 KBOE/d compared to 2006) due to higher oil prices. Under such contracts, Eni is entitled to fixed monetary amounts to recover the expenses incurred for the development of the relevant properties and as a consequence of higher oil prices, the volumes entitled necessary to cover the same amount of expenses are lower.

These negative factors were offset in part by the contribution of acquired assets in the Gulf of Mexico and Congo (up 45 KBOE/d on annual average) and underlying production growth in Libya, Egypt and Kazakhstan.

On January 14, 2008, the international partners of the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed a memorandum of understanding to settle a dispute commenced in August 2007 regarding conditions and rights for developing and exploiting the Kashagan field. For a more detailed discussion of the term of the agreement see "Item 4 – Exploration & Production – Kazakhstan".

Worldwide gas sales in 2007 amounted to 98.96 BCM, up approximately 1% from 2006 due to growth achieved on international markets, particularly in the main consumption target areas in the rest of Europe (up 3.64 BCM) and outside Europe (up 0.91 BCM), offset in part by lower sales to Italian importers (down 3.43 BCM) and to the domestic market (down 0.96 BCM).

Capital expenditures in 2007 amounted to euro 10,593 million (as compared to euro 7,833 million in 2006), of which 84.7% related to the Exploration & Production, Gas & Power and Refining & Marketing segments, and mainly regarded:

(i)   development activities (euro 4,788 million) mainly in Kazakhstan, Angola, Egypt, Italy and Congo;
(ii)   exploration projects (euro 1,659 million), of which 94% was spent outside Italy, primarily in the Gulf of Mexico, Egypt, Brazil, Norway and Nigeria;
(iii)   development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 886 million) and upgrading of natural gas import pipelines to Italy (euro 253 million);
(iv)   ongoing construction of combined cycle power plants (euro 175 million);
(v)   the Refining & Marketing segment (euro 979 million) for projects aimed at upgrading the conversion capacity and flexibility of refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, building of new service stations and upgrading of existing ones; and
(vi)   upgrading of the fleet used in the Engineering & Construction segment (euro 1,410 million).

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In 2007, Eni successfully executed a number of strategic acquisitions and deals that strengthen its competitive position in certain important markets to the Company. Total cash outlays for these acquisitions amounted to euro 9.7 billion mainly related to the purchase of oil and gas assets in the Gulf of Mexico and onshore Congo; the purchase of certain equity-investments in Russia; a stake in the Angola LNG Ltd Consortium responsible for the construction of an LNG plant; refining and marketing assets in the Czech Republic, Slovakia and Hungary, as well as a stake in the independent British company Burren Energy Plc following a recommended cash offer on the entire share capital of this entity launched in November 2007. This deal closed in January 2008.

In the 2008-2011 period, Eni expects to invest approximately euro 49.8 billion in capital expenditures and exploration projects to implement its strategy of organic growth.

 

Margin5

Margin: the difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.

 

Trading Environment

   

2005

 

2006

 

2007

   
 
 
Average price of Brent dated crude oil in U.S. dollars (1)   54.38   65.14   72.52
Average price of Brent dated crude oil in euro (2)   43.71   51.86   52.90
Average EUR/USD exchange rate (3)   1.244   1.256   1.371
Average European refining margin in U.S. dollars (4)   5.78   3.79   4.52
Euribor - three month euro rate % (3)   2.2   3.1   4.3
   
 
 

(1)   Price per barrel. Source: Platt’s Oilgram.
(2)   Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB).
(3)   Source: ECB.
(4)   Price per barrel. FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data.

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. See "Item 3 – Risk Factors".

In 2007, the trading environment was unfavorable to Eni’s business trends and results of operations due to the appreciation of the euro over the dollar (up 9.2% as compared to 2006) and sharply lower realized refining margins reflecting a decrease in sour crude discounts that affected Eni’s complex refineries. This decrease was driven by a relatively higher appreciation of sour crudes on the marketplace compared to Brent prices due to a situation of shortage, particularly in the Mediterranean basin, and rising demand. Also Eni’s refining margins were affected by the circumstance that margins on certain secondary products (particularly base lubricants and bitumen) were lower as the prices for these products did not increase in proportion to the cost of feedstock used to produce them. These negatives were partly offset by higher Brent crude oil prices averaging 72.52 $/BL for the year (up 11.3% as compared to 2006) which supported Eni’s realizations on oil (up 12.7% in dollar terms) in the Exploration & Production business. Eni’s realizations on oil were higher than Brent crude oil prices due to a reduction in sour crude discounts. Operating performance in the Engineering & Construction business was supported by robust demand trends for drilling and construction services driven by higher capital expenditures made by oil companies resulting in higher volumes and unit tariffs.

_______________

(5)   This definition applies to the term margin whenever used in Item 5.

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Key Consolidated Financial Data

   

2005

 

2006

 

2007

   
 
 
 

(million euro)

Net sales from operations       73,728   86,105   87,256
Operating profit       16,827   19,327   18,868
Net profit attributable to Eni       8,788   9,217   10,011
Net cash provided by operating activities       14,936   17,001   15,517
Capital expenditures       7,414   7,833   10,593
Acquisitions of investments and businesses       127   95   9,665
Shareholders’ equity including minority interest at year end       39,217   41,199   42,867
Net borrowings at year end (1)       10,475   6,767   16,327
Net profit per share attributable to Eni (basic and diluted)   (euro per share)   2.34   2.49   2.73
Dividend per share   (euro per share)   1.10   1.25   1.30
Net borrowings to total shareholders’ equity ratio including minority interest (leverage) (1)       0.27   0.16   0.38
   
 
 

(1)    For a discussion of the usefulness of and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures, which in the case of the Company refers to IFRS, see "Liquidity and Capital Resources - Financial Conditions" below.

Critical Accounting Estimates

The Company’s Consolidated Financial Statements are prepared in accordance with IFRS as issued by the IASB and IFRS issued by the IASB as adopted by the European Union. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements. Estimates made are based on complex and subjective judgments and on 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 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 significantly 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 can be produced with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Although there are authoritative guidelines regarding the engineering 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 and 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 will be classified as proved undeveloped. Volumes will subsequently be reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings will 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 as regards the initial estimate and, in the case of Production Sharing Agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered.

Oil and natural gas reserves have a direct impact on certain amounts reported in the 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

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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 volumes of estimated reserves, the lower is the likelihood of asset impairment.

 

Impairment of assets

Eni assesses its tangible assets and intangible assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate the carrying values of the assets are not recoverable. Such indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain 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.

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 costs and 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 reviews 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. The estimated future level of production is based on assumptions on: future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

Oil, natural gas and petroleum products prices used to quantify 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. Prior to 2007, our expected future cash flow estimates were entirely based upon management’s planning assumptions.

Goodwill and other intangible assets with an indefinite useful life are not subject to amortization. The Company tests such assets at the cash-generating unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value below its carrying amount. In particular, goodwill impairment is based on the determination of the fair value of each cash-generating unit to which goodwill can be attributed on a reasonable and consistent basis.

A cash generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditures. If the recoverable amount of a cash generating unit 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 on a pro-rata basis 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 well as 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).

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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 (interest accretion) and any change of 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 Company’s 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, including legislation that implements 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. Although management, considering the actions already taken, insurance policies 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, 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 a yet unknown contamination;
(ii)   the results of the ongoing surveys and other possible effects of statements required by Decree No. 471/1999 of the Ministry of Environment concerning the remediation of contaminated sites;
(iii)   the possible effect of future environmental legislation and rules;
(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.

 

Employee benefits

Defined benefit plans and other long-term benefits are evaluated with reference to uncertain events and based upon actuarial assumptions including discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trend rates, estimated retirement dates and mortality rates. The significant assumptions used to account for pensions and other post-retirement benefits 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. Indications used in selecting the discount rate include rates of annuity contracts and rates of return on high quality fixed-income investments (such as government 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 the individual employees involved, based principally on available actuarial data; and
(v)   determination of expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equities 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 10% of the greater 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,

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obligations for other 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 profit or loss in their entirety.

 

Contingencies

In addition to accruing the estimated costs for environmental liabilities, asset retirement obligations 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 appropriate amounts for accrual is a complex estimation process that includes subjective judgments.

 

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 contractual revenues. The estimate of future gross profit is based on a complex estimation process that includes the identification of risks related to the geographical region, market conditions in that region and any assessment that it is necessary to estimate with sufficient precision the total future costs as well as the expected timetable. Requests for additional revenues, deriving from a change in the scope of the 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, for instance, from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

 

 

2005-2007 Group Results of Operations

Overview of the Profit and Loss Account for Three Years Ended December 31, 2005, 2006 and 2007

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,

   

2005

 

2006

 

2007

   
 
 
  (million euro)
Net sales from operations   73,728     86,105     87,256  
Other income and revenues (1)   798     783     827  
   

 

 

Total revenues   74,526     86,888     88,083  
Operating expenses   (51,918 )   (61,140 )   (61,979 )
Depreciation, depletion, amortization and impairments   (5,781 )   (6,421 )   (7,236 )
   

 

 

OPERATING PROFIT   16,827     19,327     18,868  
Finance income (expense)   (366 )   161     (83 )
Income from investments   914     903     1,243  
   

 

 

PROFIT BEFORE INCOME TAXES   17,375     20,391     20,028  
Income taxes   (8,128 )   (10,568 )   (9,219 )
   

 

 

NET PROFIT   9,247     9,823     10,809  
Attributable to:                  
- Eni   8,788     9,217     10,011  
- minority interest   459     606     798  
   

 

 


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

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

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (%)
Operating expenses   70.4     71.0     71.0  
Depreciation, depletion, amortization and impairments   7.8     7.5     8.3  
OPERATING PROFIT   22.8     22.4     21.6  
   
 
 

2007 compared to 2006. Net profit attributable to Eni in 2007 was euro 10,011 million with a euro 794 million increase from 2006 (up 8.6%), primarily due to:

(i)   lower income taxes (down euro 1,349 million) mainly reflecting:
    -   a one-time gain (euro 394 million) recorded upon an adjustment to deferred tax assets and liabilities for Italian subsidiaries relating to certain amendments to the Italian tax regime, including a lower statutory tax rate enacted by the 2008 Budget Law; and
    -   the circumstance that in 2006 deferred tax liabilities were recorded due to changes in the tax regimes of Algeria and the United Kingdom and charges regarding disputes on certain tax matters (totaling euro 347 million);
(ii)   an increase in net income from investments, up euro 340 million, mainly due to net gains on the divestment of interests in certain associates of the Engineering & Construction segment and higher earnings from equity-accounted and cost-accounted entities.

These positive factors were partly offset by a lower operating profit (down euro 459 million) mainly in the Exploration & Production segment (down euro 1,792 million) and higher net finance charges (up euro 244 million as a result of the increase registered in average net borrowings).

2006 compared to 2005. Net profit attributable to Eni in 2006 was euro 9,217 million with a euro 429 million increase from 2005 (up 4.9%) reflecting an increase in operating profit (up euro 2,500 million) recorded in particular in the Exploration & Production segment, due to higher realized hydrocarbon prices in dollars (oil up 22.4% and natural gas up 17.8%) combined with increased production volumes sold (up 10.2 mmBOE), which were offset in part by higher operating costs and amortization charges, and increased exploration expenses. Operating profit increased also in the Gas & Power and Engineering & Construction segments (up euro 481 and euro 198 million, respectively) and lower restructuring charges were recognized in the Other activities segment (up euro 312 million). These increases were offset in part by a decrease in the operating profit of the Refining & Marketing segment (down euro 1,538 million) due to the circumstance that in 2005 an inventory holding gain of euro 1,064 million was recorded in connection with the impact of rising international prices of oil and refined products on the inventory evaluation according to the weighted-average cost method of inventory accounting, as compared to a euro 215 million inventory holding loss reported in 2006 as a result of a reversal in the trend of refined product and oil prices.

The effect of the increase in operating profit on net profit was offset in part by higher income taxes (up euro 2,440 million) reflecting the increase in Group tax rate, which rose from 46.8% to 51.8% mainly in the Exploration & Production segment due to:

  the circumstance that a windfall tax on upstream earnings was enacted in Algeria effective as from August 1, 2006 (with a negative impact of euro 328 million); and
  the circumstance that an increase in the supplemental tax rate applicable to profit before taxes earned by operations in the North Sea was enacted by the British Government effective as from January 1, 2006 (with a negative impact of euro 198 million).

 

Discontinued Operations

Discontinued operations in 2007, 2006 and 2005 were immaterial.

 

Analysis of the Line Items of the Profit and Loss Account

a) Total Revenues

Eni’s total revenues were euro 88,083, euro 86,888 and euro 74,526 million in 2007, 2006 and 2005, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s net sales from operations amounted to euro 87,256, euro 86,105 and euro 73,728 million in 2007, 2006 and 2005, respectively, and its other income and revenues totaled euro 827, euro 783 and euro 798 million, respectively, in these periods.

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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 intragroup sales, together with consolidated net sales from operations.

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
  (million euro)
Exploration & Production   22,531     27,173     27,278  
Gas & Power   22,969     28,368     27,633  
Refining & Marketing   33,732     38,210     36,401  
Petrochemicals   6,255     6,823     6,934  
Engineering & Construction   5,733     6,979     8,678  
Other activities   863     823     205  
Corporate and financial companies   1,239     1,174     1,313  
Consolidation adjustment (1)   (19,594 )   (23,445 )   (21,186 )
   

 

 

    73,728     86,105     87,256  
   
 
 

(1)   Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The most substantial intragroup sales are recorded by the Exploration & Production segment. See Note 35 to the Consolidated Financial Statements for a breakdown of intragroup sales by segment for the reported years.

2007 compared to 2006. Eni’s net sales from operations for 2007 (euro 87,256 million) were up euro 1,151 million, a 1.3% increase from 2006, primarily reflecting higher revenues in the Engineering & Construction segment and higher realizations on oil and natural gas in dollar terms, partially offset by the impact of the appreciation of the euro versus the dollar (up 9.2%) on revenues in the Refining & Marketing and Exploration & Production segments.

Revenues generated by the Exploration & Production segment (euro 27,278 million) increased by euro 105 million, up 0.4%, mainly due to higher oil realizations in dollars (up 12.7%). This increase was partially offset by the impact of the appreciation of the euro versus the dollar and lower hydrocarbon production sold (down 14.7 mmBOE, or 2.2%). For a discussion on the reduction of production volumes see "Executive Summary".

Revenues generated by the Gas & Power segment (euro 27,633 million) declined by euro 735 million, down 2.6%, mainly due to lower average natural gas prices reflecting negative trends in energy parameters to which gas prices are contractually indexed and a negative shift in the mix of volumes sold resulting in lower average realized prices on gas.

Revenues generated by the Refining & Marketing segment (euro 36,401 million) declined by euro 1,809 million, down 4.7%, mainly due to the effect of the appreciation of the euro over the dollar and lower product volumes marketed (down 0.98 mmtonnes), partly offset by higher international prices for oil and products.

Revenues generated by the Petrochemical segment (euro 6,934 million) increased by euro 111 million from 2006, up 1.6%, reflecting mainly the fact that performance in 2006 was adversely impacted by the unplanned downtime of the Priolo craker and downstream plants as a consequence of an accident that occurred at the nearby refinery in April 2006, resulting in a recovery in production volumes sold (up 4%). Commodity chemicals prices were also up by 4% on average.

Revenues generated by the Engineering & Construction segment (euro 8,678 million) increased by euro 1,699 million, up 24.3%, due to increased activity levels and higher prices in the Offshore and Onshore construction and Offshore drilling businesses due to favorable market trends as discussed under paragraph "Trading Environment".

Revenues generated by the Other activities segment decreased by euro 618 million to euro 205 million, due to the intragroup divestment of the Porto Torres plant for the production of basic petrochemical products to Polimeri Europa, which occurred in 2007.

2006 compared to 2005. Eni’s net sales from operations for 2006 were euro 86,105 million, up euro 12,377 million from 2005, or 16.8%, primarily reflecting higher product prices in all of Eni’s main operating segments, higher volumes sold of hydrocarbons and natural gas and higher activity levels in the Engineering & Construction segment, offset in part by the negative impact of the appreciation of the euro versus the dollar (up 1%).

Revenues generated by the Exploration & Production segment were euro 27,173 million, up euro 4,642 million, or 20.6%, primarily reflecting higher realizations in dollars (oil up 22.4%, natural gas up 17.8%) and higher oil and

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gas production sold (up 10.2 mmBOE). These positives were partially offset by the appreciation of the euro over the dollar.

Revenues generated by the Gas & Power segment were euro 28,368 million, up euro 5,399 million, or 23.5%, primarily reflecting increased natural gas prices related in particular to a favorable trading environment, higher natural gas volumes sold (up 3.14 BCM, or 3.8%) and higher electricity production sold (up 2.05 TWh, or 9%).

Revenues generated by the Refining & Marketing segment were euro 38,210 million, up euro 4,478 million, or 13.3%, primarily reflecting higher international prices for oil and refined products.

Revenues generated by the Petrochemical segment were euro 6,823 million, up euro 568 million, or 9.1%, primarily reflecting an increase in average selling prices.

Revenues generated by the Engineering & Construction segment were euro 6,979 million, up euro 1,246 million, or 21.7%, primarily reflecting higher activity levels in the Offshore and Onshore construction businesses and a higher utilization rate of vessels and higher tariffs in the Offshore Drilling area

b) Operating Expenses

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

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
 

(million euro)

Purchases, services and other   48,567   57,490   58,179
Payroll and related costs   3,351   3,650   3,800
Operating expenses   51,918   61,140   61,979
   
 
 

2007 compared to 2006. Operating expenses for 2007 (euro 61,979 million) increased by euro 839 million from 2006, up 1.4%, mainly due to higher purchase prices for refinery and petrochemical feedstock, as well as rising operating costs in the Exploration & Production segment in dollar terms, partly offset by the appreciation of the euro against the dollar. Purchases, services and other include: (i) an expense of euro 91 million relating to a provision against ongoing antitrust proceedings before the European authorities net of a gain deriving from the reversal of a previously accrued provision upon favorable developments in certain proceedings before the Italian Authority for Electricity and Gas; and (ii) environmental charges (euro 327 million), recognized particularly by Syndial and the Refining & Marketing segment.

Payroll and related costs (euro 3,800 million) increased by euro 150 million, up 4.1%, mainly due to higher unit labor costs in Italy and outside Italy and an increase in the average number of employees outside Italy in the Engineering & Construction segment related to higher activity levels and the Exploration & Production segment related to acquired assets. These increases were offset in part by exchange rate translation differences and a gain (euro 83 million) deriving from the curtailment of the provision for post-retirement benefits existing at 2006 year-end related to obligations towards Italian employees.

2006 compared to 2005. Operating expenses for 2006 (euro 61,140 million) were up euro 9,222 million from 2005, or 17.8%, reflecting primarily: (i) higher prices for oil-based and petrochemical feed-stocks and for natural gas, affected also by higher charges related to the climatic emergency of the first quarter of 2006; (ii) higher operating costs in the Exploration & Production segment, reflecting mainly the higher share of development projects in complex environments and sector-specific inflation; (iii) higher costs for refinery maintenance; and (iv) a provision of euro 239 million related mainly to fines imposed by certain antitrust and regulatory authorities. These negative factors were offset in part by the impact of the appreciation of the euro over the dollar.

Payroll and related costs (euro 3,650 million) were up euro 299 million, or 8.9%, reflecting primarily higher redundancy incentives (up euro 99 million), ordinary wage trends and higher average workforce outside Italy, in particular in the Engineering & Construction segment, partly offset by a reduction in average workforce in Italy.

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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.

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
 

(million euro)

Exploration & Production (1)   3,945     4,646     5,483  
Gas & Power   684     687     687  
Refining & Marketing   462     434     433  
Petrochemicals   118     124     116  
Engineering & Construction   176     195     248  
Other activities   16     6     4  
Corporate and financial companies   112     70     68  
Impact of unrealized intragroup profit elimination   (4 )   (9 )   (10 )
   

 

 

Total depreciation, depletion and amortization   5,509     6,153     7,029  
Impairments   272     268     207  
   

 

 

    5,781     6,421     7,236  
   

 

 


(1)   Exploratory expenditures of euro 1,778 million, euro 1,075 million and euro 618 million were included in these amounts for the years 2007, 2006 and 2005, respectively.

2007 compared to 2006. In 2007, depreciation, depletion and amortization charges (euro 7,029 million) increased by euro 876 million, or 14.2%, from 2006, mainly in the Exploration & Production segment (up euro 837 million) related to higher exploratory expenditures that are expensed in full when incurred (euro 703 million), the consolidation of activities acquired in the Gulf of Mexico and Congo and the impact on amortization charges of an estimate revision of asset retirement obligations for certain Italian and U.S. fields recognized upon preparation of 2006 consolidated financial statements which was applied prospectively, offset in part by exchange rate translation differences.

In 2007, impairment charges amounted to euro 207 million mainly regarding mineral assets in the Exploration & Production segment and plants and equipment in the Refining & Marketing segment.

2006 compared to 2005. In 2006, depreciation, depletion and amortization charges (euro 6,153 million) increased by euro 644 million, or 11.7%, from 2005 mainly in the Exploration & Production segment (euro 701 million) reflecting primarily higher exploration expenditure and increased development costs incurred for developing new fields and maintaining production levels in mature fields combined with the effects of higher production levels.

Impairments (euro 268 million) concerned mainly mineral assets in the Exploration & Production segment (euro 129 million), intangible assets in the Gas & Power segment and tangible assets in the Petrochemical segment.

 

d) Operating Profit by Segment

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

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
 

(million euro)

Exploration & Production   12,592     15,580     13,788  
Gas & Power   3,321     3,802     4,127  
Refining & Marketing   1,857     319     729  
Petrochemicals   202     172     74  
Engineering & Construction   307     505     837  
Other activities   (934 )   (622 )   (444 )
Corporate and financial companies   (377 )   (296 )   (217 )
Impact of unrealized intragroup profit elimination   (141 )   (133 )   (26 )
   

 

 

Operating profit   16,827     19,327     18,868  
   

 

 

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

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
 

(%)

Exploration & Production   55.9   57.3   50.5
Gas & Power   14.5   13.4   14.9
Refining & Marketing   5.5   0.8   2.0
Petrochemicals   3.2   2.5   1.1
Engineering & Construction   5.4   7.2   9.6
   
 
 
Group   22.8   22.4   21.6
   
 
 

Exploration & Production. Operating profit in 2007 amounted to euro 13,788 million, down euro 1,792 million from 2006, or 11.5%, reflecting: (i) the appreciation of the euro over the dollar (approximately euro 1,400 million), resulting in a decrease in revenues partly offset by lower dollar-denominated operating expenses when translated to the euro; (ii) lower production volumes sold (down 14.7 mmBOE, or 2%). For a discussion of this reduction in production see "Executive Summary" above; (iii) increased exploration expenses in connection with higher geological and geophysical expenses and increased exploratory drilling expenditures that are expensed in full as incurred (resulting in a cumulative increase of euro 840 million assuming constant exchange rates); (iv) rising operating costs reflecting the impact of sector-specific inflation; and (v) higher amortization and depreciation charges. These negatives were partly offset by higher realizations in dollars (oil up 12.7%, natural gas up 2.2%). For a discussion of trend in Eni’s realizations see "Trading Environment".

Operating profit in 2006 amounted to euro 15,580 million, up euro 2,988 million from 2005, or 23.7%, reflecting higher realizations in dollars (oil up 22.4%, natural gas up 17.8%) combined with higher production volumes sold (up 10.2 mmBOE, or 1.7%), partly offset by: (i) increased production costs and amortization charges related in particular to higher cost incurred in developing new fields and maintaining production levels at mature fields and sector-specific inflation; (ii) increased exploration expenses (euro 457 million, including exchange rate differences); and (iii) the negative net impact of the appreciation of the euro over the dollar (approximately euro 155 million), as a decrease in revenues due to exchange rate differences was only partly offset by a decrease in operating costs and amortization charges.

Gas & Power. Operating profit in 2007 amounted to euro 4,127 million, a euro 325 million increase compared to 2006, up 8.5%, reflecting: (i) a positive development with Italy’s regulatory framework on gas pricing to residential clients, reflecting a more favorable indexation mechanism of the raw material cost component as established by the Authority for Electricity and Gas with Resolution No. 79/2007, changing the regime in force in the first half of 2006 as established by Resolution No. 248/2004. Additionally, Eni fulfilled obligations provided by this resolution to renegotiate contracts with certain gas resellers based on the same indexation mechanism resulting in the partial reversal of provisions accrued in 2005 and in the first half of 2006 with respect to expected charges for these renegotiations. An in-depth discussion of these regulations is provided under "Item 4 – Regulation of Gas & Power – Natural gas prices"; (ii) higher supply costs incurred in 2006 caused by a climatic emergency during the 2005-2006 winter; and (iii) an increase in operating result from transportation activities in Italy.

Operating profit in 2006 amounted to euro 3,802 million, a euro 481 million increase compared to 2005, up 14.5%, reflecting: (i) higher selling margins on natural gas due to a favorable trading environment; (ii) a lower impact of the tariff regime implemented by the Authority for Electricity and Gas with Resolution No. 248/2004 as modified by Resolution No. 134/2006 enacted on July 1, 2006. Resolution No. 134/2006, mitigated the impact of the indexation mechanism provided for by Resolution No. 248/2004 and, additionally, established that the impact of Resolution No. 248 on 2005 be split among gas supplier and wholesaler in case the former renegotiated gas supply contracts based on the terms of Resolution No. 248/2004. As a consequence, Eni partly reversed a provision accrued in its 2005 consolidated financial statements with respect to Resolution No. 248 having fulfilled the renegotiation obligation set forth by Resolution No. 134/2006 (see "Item 4 – Regulation of Gas & Power – Natural gas prices"); and (iii) a growth in natural gas sales by consolidated subsidiaries (up 3.14 BCM, or 3.8%), in volumes transported outside Italy due to the coming on line of volumes transported through the GreenStream pipeline from Libya, and in electricity production sold (up 2.05 TWh, or 9%). Furthermore, the comparison of the operating result for 2007 to 2006 result benefits from the circumstance that in 2005 a provision pertaining to a fine imposed by the Italian Antitrust Authority was accrued for euro 290 million, partly offset by the circumstance that in 2006 a provision to the risk reserve regarding mainly certain fines imposed by the Authority for Electricity and Gas, and higher asset impairments environmental charges and provisions for redundancy incentives were recorded (for a cumulative amount euro 147 million).

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These positives were partly offset by: (i) a lower operating result from transportation activities in Italy due to the tariff regime enacted by the Authority for Electricity and Gas with Resolution No. 166/2005 resulting in lower transport tariff and a lower operating result from retail distribution activities due to lower volumes; and (ii) higher purchase costs incurred in the first quarter of the year, owing to a climatic emergency.

Refining & Marketing. Operating profit in 2007 amounted to euro 729 million, a euro 410 million increase compared to 2006, mainly due to: (i) an inventory holding gain of approximately euro 650 million recognized in 2007 profit and loss reflecting the impact of rising prices of crude oil and products on the valuation of year-end inventories using to the weighted average-cost method of inventory accounting. In 2006, an inventory holding loss of approximately euro 220 million had been recorded in connection with the impact of declining prices of oil and refined products; and (ii) the circumstance that in 2006 a provision was made for a fine imposed by the Italian Antitrust Authority for anti-competitive activities in the field of supplies of jet fuel (euro 109 million).

On the negative side, the refining business delivered a weaker operating performance on the back of an unfavorable trading environment for Eni’s complex refineries, reflecting reduced discounts on sour crudes, lower margins from certain of the Company’s secondary products (such as base lubricants and bitumen) as the prices for these products did not increase in proportion to the costs of the feedstock used to produce them and the appreciation of the euro over the dollar. Marketing activities in Italy also reported a lower operating profit mainly due to: (i) lower retail margins on refined products marketed on Eni’s networks due to increased international prices for purchasing those products which were net fully transferred to selling prices to customers; and (ii) a decline in the wholesale business results due to lower margins and volumes marketed (down 1.8% over 2006), the latter also reflecting unusually mild winter weather in the first quarter of 2007 causing lower sales of home-heating fuels.

Operating profit in 2006 amounted to euro 319 million, a euro 1,538 million decrease compared to 2005, down 82.8%, due essentially to: (i) the circumstance that in 2005 an inventory holding gain of approximately euro 1,100 million was recorded in connection with the impact of rising international prices of oil and refined products on the inventory evaluation according to the weighted-average cost method of inventory accounting, as compared to an approximately euro 220 million inventory holding loss reported in 2006 as a result of a reversal in the trend of refined product and oil prices; (ii) lower realized refining margins reflecting an unfavorable trading environment and the appreciation of the euro versus the dollar, combined with the impact of longer refinery standstills due to planned maintenance, partly offset by the higher profitability of processed crude; (iii) a decline in the operating performance of Italian marketing activities due to lower volumes sold which were negatively affected by the mild weather conditions registered in the fourth quarter and the divestment of Italiana Petroli carried out in September 2005; (iv) environmental provisions (euro 111 million); (v) a fine imposed by the Italian Antitrust Authority (euro 109 million); and (vi) provisions for redundancy incentives (euro 47 million).

On the positive side, marketing activities in the rest of Europe recorded improved results reflecting higher retail margins and higher volumes sold.

Petrochemicals. Operating profit in 2007 amounted to euro 74 million, a euro 98 million decrease compared to 2006, down 57%, due to lower selling margins of commodity chemicals, particularly the margin on cracker and on aromatic products (paraxylene), reflecting a sharp increase in the cost of oil-based feedstock which was not fully transferred to final selling prices. This negative was partly offset by: (i) higher production and sales volumes compared to 2006, when an accident occurred at the Priolo refinery which heavily impacted performance; and (ii) lower asset impairments (euro 50 million) and risk provisions (euro 31 million). In addition, a lower inventory holding gain was recorded (down euro 54 million).

Operating profit in 2006 amounted to euro 172 million, a euro 30 million decrease compared to 2005, down 14.9%, due to: (i) lower selling margins recorded mainly in the first half of the year. This decline affected all businesses with the exception of polyethylene, owing to increases in the cost of oil-based feed-stocks not transferred to selling prices; and (ii) higher asset impairments (euro 21 million), higher redundancy incentives (euro 15 million) and a risk provision related to a fine imposed by the European Antitrust Authority (euro 13 million). Results for the year were also negatively impacted by the accident that occurred at the Priolo refinery in April resulting in lower product availability.

Engineering & Construction. Operating profit in 2007 amounted to euro 837 million, a euro 332 million increase compared to 2005, or 65.7%. This increase related to an improved operating performance recorded in all business areas, particularly in the Offshore and Onshore construction and Offshore drilling businesses due to higher activity levels and improved prices driven by favorable demand trends. See "Trading Environment". Management expects this trend to continue in the foreseeable future based on capital expenditure plans announced by oil companies.

Operating profit in 2006 amounted to euro 505 million, a euro 198 million increase compared to 2005, up 64.5%. This increase was recorded in particular in the following business areas: (i) Offshore, due to a higher activity level in the Caspian region and Nigeria; (ii) Offshore Drilling, due to higher tariffs for the Scarabeo 3 and Scarabeo 5 semi-submersible platforms and higher activity levels of the Perro Negro 5 jack-up and Scarabeo 4 semi-

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submersible platform; and (iii) Onshore due to higher activity related essentially to the start up of some large projects acquired in 2005.

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 in past years.

Other activities reported an operating loss of euro 444 million for 2007, representing an improvement of euro 178 million, or 28.6%, compared to an operating loss recorded in 2006 (euro 622 million) mainly due to lower provisions for risks and lower asset impairments (for a cumulative positive effect of euro 78 million) and to a gain recognized upon settlement of certain contractual issues with Dow Chemical. This was partly offset by higher environmental charges (euro 84 million).

Other activities reported an operating loss of euro 622 million for 2006, improving by euro 312 million, or 33.4% compared to the loss recorded in 2005 (euro 934 million), due mainly to lower environmental charges, lower provisions for risks and lower asset impairments (for a cumulative positive effect of euro 395 million). This was partly offset by the recording of a charge related to a fine imposed by the European Antitrust Authority (euro 62 million).

Corporate and financial companies. These activities include expenses incurred in connection with corporate activities including the central treasury department and financial subsidiaries that makes available a range of financial services to the Group, including supporting the financing of Eni’s projects around the world, as well as results from operations of certain of Eni’s minor subsidiaries that provide a range of services including training, business support, real estate and general purposes services to Group’s companies.

The aggregate Corporate and financial companies reported an operating loss of euro 217 million in 2007, representing an improvement of euro 79 million, or 26.7%, compared to the loss recorded in 2006 (euro 296 million), mainly reflecting lower operating costs and lower provisions for redundancy incentives.

The aggregate Corporate and financial companies reported an operating loss of euro 296 million in 2006, representing an improvement of euro 81 million, or 21.5%, compared to the loss recorded in 2005 (euro 377 million), due essentially to lower operating costs and lower risk provisions.

 

e) Finance Income (Expense)

The table below sets forth a breakdown of Eni’s finance income (expense) for the periods indicated:

 

Year ended December 31,

   

2005

 

2006

 

2007

   
 
 
 

(million euro)

Gain (loss) on derivative financial instruments   (386 )   383     26  
Exchange differences, net   169     (152 )   (51 )
Interest income   60     194     236  
Finance expense on short and long-term debt   (420 )   (462 )   (703 )
Finance expense due to passage of time   (109 )   (116 )   (186 )
Income from equity instruments               188  
Other finance income (expense)   161     198     227  
    (525 )   45     (263 )
Capitalized finance expense   159     116     180  
   

 

 

    (366 )   161     (83 )
   

 

 

2007 compared to 2006. In 2007, net finance expense (euro 83 million) increased by euro 244 million from 2006 when a net finance income of euro 161 million was recorded. This change was mainly due to:

(i)   the recognition of significantly lower gains on the fair value valuation of certain financial derivative instruments that do not meet the formal criteria to be assessed as hedges under IFRS, including the ineffective portion of a change in fair value of certain commodity derivatives designated as cash flow hedges resulting in a loss of euro 52 million.

Eni entered into those commodity instruments to hedge the exposure to variability in future cash flows deriving from marketing an amount of Eni’s proved reserves equal to 2% of proved reserves as of December 31, 2006 (corresponding to approximately 125.7 mmBOE). These hedging transactions were undertaken in connection with the acquisitions executed in 2007 of proved and unproved properties in

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    Congo and in the Gulf of Mexico. Eni put in place certain forward sale contracts at a fixed price and call and put options with th