20-F 1 sj0607en20f.htm sj0607en20f

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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
6

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)

Piazzale Enrico Mattei 1, 00144 Rome, Italy
(Address of principal executive offices)


Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class

 

Name of each exchange on which registered

Shares
American Depositary Shares
(Which represent the right to receive two Shares)

 

New York Stock Exchange*
New York Stock Exchange

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 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 the 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 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 


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


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   4
    Risk Factors   4
Item 4.   INFORMATION ON THE COMPANY   13
    History and Development of the Company   13
    Business Overview   16
    Exploration & Production   16
    Gas & Power   35
    Refining & Marketing   45
    Petrochemicals   52
    Engineering & Construction   54
    Other activities   56
    Research and Development   56
    Insurance   59
    Environmental Matters   59
    Regulation of Eni’s Businesses   63
    Property, Plant and Equipment   75
    Organizational Structure   75
Item 4A.   UNRESOLVED STAFF COMMENTS   76
Item 5.   OPERATING AND FINANCIAL REVIEW AND PROSPECTS   76
    Executive Summary   76
    Basis of Presentation   79
    Critical Accounting Estimates   79
    Results of Operations   83
    Liquidity and Capital Resources   93
    Financial Condition   95
    Recent Developments   99
    Management Expectations of Operations   100
    Summary of Significant Differences between IFRS and U.S. GAAP   104
Item 6.   DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES   105
    Directors and Senior Management   105
    Board Practices   109
    Compensation   119
    Employees   127
    Share Ownership   129
Item 7.   MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS   129
    Major Shareholders   129
    Related Party Transactions   129
Item 8.   FINANCIAL INFORMATION   130
    Consolidated Statements and Other Financial Information   130
    Significant Changes   139
Item 9.   THE OFFER AND THE LISTING   139
    Offer and Listing Details   139
    Markets   141
Item 10.   ADDITIONAL INFORMATION   141
    Memorandum and Articles of Association   141
    Material Contracts   149
    Documents on Display   149
    Exchange Controls   149
    Taxation   150

i


Table of Contents

 

Item 11.   QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK   153
Item 12.   DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES   156
         
PART II        
Item 13.   DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES   157
Item 14.   MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS   157
    AND USE OF PROCEEDS    
Item 15.   CONTROLS AND PROCEDURES   157
Item 16.        
16A.   Board of Statutory Auditors Financial Expert   158
16B.   Code of Ethics   158
16C.   Principal Accountant Fees and Services   158
16D.   Exemptions from the Listing Standards for Audit Committees   159
16E.   Purchases of Equity Securities by the Issuer and Affiliated Purchasers   159
         
PART III        
Item 17.   FINANCIAL STATEMENTS (*)   161
Item 18.   FINANCIAL STATEMENTS (**)   161
Item 19.   EXHIBITS   161

 

 

 

 

 

 


(*)   Omitted pursuant to General Instructions for Form 20-F.
(**)   The Registrant has responded to Item 18 in lieu of responding to Item 17.

 

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 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 term "Eni", the "Group", or the "Company" refers 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 adopted by the European Commission following the procedure contained in Article 6 of the EC Regulation No. 1606/2002 of the European Parliament and Council of July 19, 2002. 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 require adopting companies to restate only one year of past financial statements.
Accordingly this annual report includes financial informations prepared in accordance with IFRS as of and for the three years ended December 31, 2004, 2005 and 2006.

IFRS, under which Eni’s Consolidated Financial Statements have been prepared, differ in certain significant respects from U.S. GAAP. For information on the differences between IFRS and U.S. GAAP as they relate to Eni, see Notes 36, 37 and 38 to Eni’s Consolidated Financial Statements included herein.

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", "USD" and "U.S. $" are to the currency of the United States and references to "euro", "EUR" and "€" are to the currency of the European Monetary Union.

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STATEMENTS REGARDING COMPETITIVE POSITION

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

 

 

 

 

 

 

 

 

 

 

 

 

 

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GLOSSARY

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

 

Financial terms

   
     
Leverage   It is a non-GAAP measure of a 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, 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 deposits in escrow. Securities not related to operations consist primarily of government bonds and financing institutions securities. For a discussion of management’s view of the usefulness of this measure and its reconciliation with the most directly comparable GAAP measure, see "Item 5 – Financial Condition".
     

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.
     
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 petrochemicals 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 mining concession is assigned 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 on 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 additions to 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 value 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 sector that are downstream of exploration and production activities.

 

vii


Table of Contents

ABBREVIATIONS

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

 

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)
         
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)    
         
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)

(1)     From January 1, 2004 in order to conform to the practice of other international oil companies, Eni unified the conversion rate of natural gas from cubic meters to BOE. The new rate adopted is 1 barrel of oil equals 5,742 cubic feet of natural gas. This conversion rate has been determined by management based on a number of factors. Other oil companies may use a different conversion rate. The change introduced had a negligible impact on production expressed in BOE.

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

NOT APPLICABLE

 

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

NOT APPLICABLE

 

 

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB) and adopted by the European Commission following the procedure contained in Article 6 of the EC Regulation No. 1606/2002 of the European Parliament and Council of July 19, 2002. 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. Pursuant to SEC Release 33-8567, "First-time Application of International Financial Reporting Standards", Eni is not required to include in this annual report IFRS selected financial information for any earlier periods. Accordingly 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 and 2006 and in accordance with U.S. GAAP for the five-year period ended December 31, 2006. The selected historical financial data for the years ended December 31, 2004, 2005 and 2006 are derived from Eni’s Consolidated Financial Statements included herein. IFRS, under which Eni’s Consolidated Financial Statements have been prepared, differ in certain significant respects from U.S. GAAP. For information on the differences between IFRS and U.S. GAAP as they relate to the Eni, see Notes 36, 37 and 38 to the Eni’s Consolidated Financial Statements.

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
  (million euro except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA                  
Amounts in accordance with IFRS                  
Net sales from operations  

57,545

   

73,728

   

86,105

 
Operating profit                  
     Exploration & Production  

8,185

   

12,592

   

15,580

 
     Gas & Power  

3,428

   

3,321

   

3,802

 
     Refining & Marketing  

1,080

   

1,857

   

319

 
     Petrochemicals  

320

   

202

   

172

 
     Engineering & Construction  

203

   

307

   

505

 
     Other activities  

(395

)  

(934

)  

(622

)
     Corporate and financial companies  

(363

)  

(377

)  

(296

)
     Impact of inter-segment profits elimination (1)  

(59

)  

(141

)  

(133

)
Operating profit  

12,399

   

16,827

   

19,327

 
Net profit pertaining to Eni  

7,059

   

8,788

   

9,217

 
Data per ordinary share (euro) (2)                  
Operating profit:                  
- basic  

3.29

   

4.48

   

5.23

 
- diluted  

3.28

   

4.47

   

5.22

 
Net profit pertaining to Eni basic and diluted  

1.87

   

2.34

   

2.49

 
Data per ADR ($) (2) (3)                  
Operating profit:                  
- basic  

8.18

   

11.14

   

13.13

 
- diluted  

8.17

   

11.12

   

13.12

 
Net profit basic and diluted  

4.66

   

5.82

   

6.26

 

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Table of Contents
 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
  (million euro except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA                    
Amounts in accordance with U.S. GAAP                    
Net sales from operations  

43,632

 

48,018

 

54,698

 

70,331

 

80,011

Operating profit (4)  

7,861

 

9,215

 

11,739

 

15,528

 

19,345

Profit before cumulative effect of change in accounting principle and income taxes  

8,350

 

9,274

 

12,324

 

16,281

 

20,784

Net profit before cumulative effect of change in accounting principle      

6,098

           
Effect of adoption of SFAS No. 143      

198

           
Net profit  

5,292

 

6,296

 

6,401

 

7,583

 

10,005

Data per ordinary share (euro) (2)                    
Operating profit  

2.05

 

2.44

 

3.11

 

4.13

 

5.23

Net profit:                    
- basic  

1.38

 

1.67

 

1.70

 

2.02

 

2.71

- diluted  

1.38

 

1.67

 

1.70

 

2.01

 

2.70

Data per ADR ($) (2) (3)                    
Operating profit  

3.89

 

5.52

 

7.74

 

10.28

 

13.14

Net profit:                    
- basic  

2.62

 

3.77

 

4.22

 

5.02

 

6.80

- diluted  

2.62

 

3.77

 

4.22

 

5.01

 

6.79

 
 
 
 
 

 

 

As of December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(million euro except number of shares and dividend information)

CONSOLIDATED BALANCE SHEET DATA                    
Amounts in accordance with IFRS                    
Total assets          

72,853

 

83,850

 

88,312

Short-term and long-term debt          

12,684

 

12,998

 

11,699

Share capital          

4,004

 

4,005

 

4,005

Minority interest          

3,166

 

2,349

 

2,170

Shareholders’ equity          

32,374

 

36,868

 

39,029

Amounts in accordance with U.S. GAAP                    
Total assets  

66,122

 

71,995

 

72,354

 

82,977

 

85,806

Short-term and long-term debt  

15,320

 

16,144

 

12,697

 

12,954

 

11,568

Share capital  

4,002

 

4,003

 

4,004

 

4,005

 

4,005

Minority interest  

1,433

 

1,822

 

2,305

 

1,463

 

1,321

Shareholders’ equity  

27,736

 

28,948

 

31,649

 

35,125

 

37,656

Other financial information in accordance with IFRS                    
Capital expenditure          

7,499

 

7,414

 

7,833

Weighted average number of ordinary shares outstanding (fully diluted - shares million)  

3,827

 

3,778

 

3,775

 

3,763

 

3,701

Dividend per share (euro)  

0.75

 

0.75

 

0.90

 

1.10

 

1.25

Dividend per ADR ($) (3)  

1.71

 

1.83

 

2.17

 

2.73

 

3.24

 
 
 
 
 

(1)   This item concerned mainly intra-group sales of goods, services and capital assets recorded at period end in the equity of the purchasing business segment.
(2)   Euro per Share or dollars per American Depositary Receipt (ADR), as the case may be. Starting from 2006 one ADR represents two Eni shares. Previously one ADR was equivalent to five Eni shares. Data per ADR for prior periods have been recalculated accordingly.
(3)   The 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 euros 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/USD average exchange rate for each year presented (see the table on page 4). Dividends per ADR for the years 2002 through 2005 have been translated into U.S. dollars for each year presented using the Noon Buying Rate on the payment date, which occurs in the months of June and October for the payment of the balance dividend and the interim dividend, respectively. Eni started to pay an interim dividend in 2005. The dividend for 2006 was converted at the Noon Buying Rate of the interim dividend (euro 0.60 per share) payment date, occurred on October 26, 2006. The balance of euro 0.65 per share payable on June 21, 2007 was translated at the Noon Buying Rate of December 31, 2006. On May 31, 2007, the Noon Buying Rate was $1.35 per euro 1.00.
(4)   See Note 37 to the Consolidated Financial Statements for details of operating profit under U.S. GAAP by business segment for the last three years.

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Selected Operating Information

The table below sets 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, 2002, 2003, 2004, 2005, 2006. Data on proved reserves, production of oil and natural gas and hydrocarbon production sold includes Eni’s share of reserves and production of affiliates and joint ventures accounted for under the equity or cost method of accounting.

 

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
Proved reserves of oil at period end (mmBBL)  

3,783

 

4,138

 

4,008

 

3,773

 

3,481

Proved reserves of natural gas at period end (BCF)  

18,629

 

18,008

 

18,435

 

17,591

 

16,965

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

7,030

 

7,272

 

7,218

 

6,837

 

6,436

Reserve replacement ratio (2) (three year average)  

202

 

179

 

117

 

89

 

55

Reserve life index (3)  

13.2

 

12.7

 

12.1

 

10.8

 

10.0

Average daily production of oil (KBBL/d)  

921

 

981

 

1,034

 

1,111

 

1,079

Average daily production of natural gas available for sale (mmCF/d) (4)  

3,015

 

3,174

 

3,171

 

3,344

 

3,679

Average daily production of hydrocarbons available for sale (KBOE/d) (4)  

1,449

 

1,536

 

1,586

 

1,693

 

1,720

Hydrocarbon production sold (mmBOE)  

523.3

 

556.2

 

576.5

 

614.9

 

625.1

Oil and gas production costs per BOE (5)  

3.83

 

4.16

 

4.92

 

5.59

 

5.79

Profit per barrel of oil equivalent (6)  

5.08

 

5.95

 

8.87

 

12.20

 

14.97

Sales of natural gas to third parties (7)  

64.12

 

69.49

 

72.79

 

77.08

 

79.63

Natural gas consumed by Eni (7)  

2.02

 

1.90

 

3.70

 

5.54

 

6.13

Sales of natural gas of affiliates (Eni’s share) (7)  

2.40

 

6.94

 

5.84

 

7.08

 

7.65

Total sales and own consumption of natural gas of the Gas & Power segment (7)  

68.54

 

78.33

 

82.33

 

89.70

 

93.41

Upstream natural gas sales in Europe (7)  

4.49

 

5.03

 

4.70

 

4.51

 

4.07

Worldwide natural gas sales (7)  

73.03

 

83.36

 

87.03

 

94.21

 

97.48

Transport of natural gas for third parties in Italy (7)  

19.84

 

24.63

 

28.26

 

30.22

 

30.90

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

29.8

 

30.1

 

30.2

 

30.7

 

30.9

Electricity production sold (9)  

5.00

 

5.55

 

13.85

 

22.77

 

24.82

Refined products production (10)  

35.55

 

33.52

 

35.75

 

36.68

 

36.27

Balanced capacity of wholly-owned refineries (11)  

504

 

504

 

504

 

524

 

534

Capacity utilization of wholly-owned refineries (12)  

99

 

100

 

100

 

100

 

100

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

10,762

 

10,647

 

9,140

 

6,282

 

6,294

Average throughput per service station (in Italy and outside Italy) (13)  

1,858

 

2,109

 

2,488

 

2,479

 

2,470

Petrochemicals production (10)  

7.12

 

6.91

 

7.12

 

7.28

 

7.07

Engineering & Construction order backlog at period end (14)  

10,065

 

9,405

 

8,521

 

10,122

 

13,191

Employees at period end (units)  

80,655

 

75,421

 

70,348

 

72,258

 

73,572

 
 
 
 
 

(1)   Includes approximately 779, 747, 737, 760 and 754 BCF of natural gas held in storage in Italy at December 31, 2002, 2003, 2004, 2005 and 2006, respectively. See "Item 4 – Information on the Company – Exploration & Production – Storage".
(2)   Consists of: (i) the increase in proved reserves attributable to: (a) purchases of minerals in place; (b) revisions of previous estimates; (c) improved recovery; and (d) extensions and discoveries, less sales of minerals in place; divided by (ii) production during the year as set forth in the reserve tables, in each case prepared in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note 38 to the Consolidated Financial Statements. Expressed as a percentage.
(3)   Consists of proved reserves at year end divided by production during the year as set forth in the reserve tables, in each case presented in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note 38 to the Consolidated Financial Statements. Expressed on a yearly basis.
(4)   Natural gas production volumes exclude gas consumed in operations (132, 151, 220, 250 and 286 mmCF/d in 2002, 2003, 2004, 2005 and 2006, respectively).
(5)   Consists of production costs (costs incurred to operate and maintain wells and field equipment including also royalties) prepared under U.S. GAAP divided by actual production net of production volumes of natural gas consumed in operations. See the unaudited supplemental oil and gas information in Note 38 to the Consolidated Financial Statements. Expressed in dollars.
(6)   Results of operations from oil and gas producing activities, divided by actual sold production, in each case prepared in accordance with SFAS 69. See the unaudited supplemental oil and gas information in Note 38 to the Consolidated Financial Statements for a calculation of results of operations from oil and gas producing activities. Expressed in dollars.
(7)   Expressed in BCM.
(8)   Expressed in thousand kilometers.
(9)   Expressed in TWh.
(10)   Expressed in mmtonnes.
(11)   Expressed in KBBL/d.
(12)   Expressed in production as a percentage of capacity taking into account scheduled plant shutdowns.
(13)   Expressed in thousand liters per day. Referred to the Agip branded network.
(14)   The sum of the order backlog of Saipem SpA and Snamprogetti SpA, expressed in million euro.

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Exchange Rates

The following table 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,                
2002  

1.05

 

0.86

 

0.95

 

1.05

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

 
 
 
 

(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)

December 2006  

1.33

 

1.31

 

1.32

January 2007  

1.33

 

1.29

 

1.30

February 2007  

1.32

 

1.30

 

1.32

March 2007  

1.34

 

1.31

 

1.34

April 2007  

1.37

 

1.34

 

1.37

May 2007  

1.36

 

1.34

 

1.35

June 2007 (through June 12, 2007)  

1.35

 

1.33

 

1.33

 
 
 

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on June 12, 2007 was $1.33 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 for obtaining exploration and development rights, particularly outside of Italy. The current trend of the industry towards a reduction of the number of operators through takeovers or mergers might lead to stronger competition from operators with greater financial resources and a wider portfolio of development projects.
  In its domestic natural gas business, strong competition derives 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 relative to the market and third party access to transport infrastructure. In addition, Legislative Decree No. 164/2000 grants the Italian Authority for Electricity and Gas certain regulatory powers in the matters of natural gas pricing and access to infrastructure. Outside of Italy, particularly in Europe, Eni faces competition from large well-established players and other international oil and gas companies in growing its market share and acquiring new clients or retaining clients.
  In its domestic electricity business, Eni competes with other producers from Italy or outside of Italy who sell electricity on the Italian market.

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  In retail marketing 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 that the level of competition should be enhanced in the sector of retail marketing of fuels. Eni expects developments on this issue to further increase pressure on margins from the retail marketing of fuels.
  Competition in the oilfield services, construction and engineering industries is primarily on the basis of technical expertise, quality and number of services and availability of technologically advanced facilities (for example, vessels for offshore construction).

 

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 expenditure and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or 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 respect of 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 other adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, in particular in deep water, is generally more complex and riskier than in onshore areas; so it is exploratory activity in remote areas or in challenging environmental conditions such as those in the Caspian Region or Alaska.
Failures in the exploration for oil and natural gas could have an adverse impact on Eni’s future results of operations and financial condition. Because of the percentage of Eni’s capital plans devoted to higher risk exploratory projects, it is likely that Eni will continue to experience significant exploration and dry hole expenses. In particular Eni plans to explore for oil and gas offshore, often in deep water or at deep drilling depths, where operations are more difficult and costly than on land or at shallower 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 addition, lack of essential equipment such as a shortage of deep water rigs could further delay operations, thus increasing both operational and financial risks.
In addition, failure in finding additional commercial reserves could dampen 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 numerous 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 those 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);
  timely issuance of permits and licenses by government agencies;
  the ability to design development projects as to prevent the occurrence of technical inconvenience;
  delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment;
  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 costs of third party equipment or services such as drilling rigs and shipping;
  the actual performance of the reservoir and natural field decline; and
  the ability and time necessary to build suitable transport infrastructures to export production towards final markets.

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Furthermore, deep water 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 estimated and actual timing of critical events may adversely affect the completion and start up of production from such projects and, consequently, the actual returns on such projects. Finally, developing and market hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return of 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.

Inability in replacing 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. Future oil and gas production are 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 and hence 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 industry-wide operating factors: (i) the increasingly high percentage of complex development projects (such as those in deep and ultra deep waters and in harsh environments) which bear higher lifting and development costs as compared to development projects in traditional environments; (ii) continuing increases in the purchase prices of raw materials and services in connection with sector-specific inflation and a global economic recovery; 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. Eni’s management expects this rising trend in lifting and development costs to continue, in the medium-term leading to a reduction in our profit margins per BOE. If the Company is not able to compensate for lower unit profits with increased production volumes, its results of operations and financial condition will be negatively impacted.

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. Except with respect to single transactions, Eni does not hedge its exposure to price changes. 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 cover 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 new technology.

All these factors can affect world supply and prices of oil. Such factors can also affect the prices of natural gas because natural gas prices are typically tied to the prices of certain crude and refined petroleum products. Lower crude oil prices have an adverse impact on Eni’s results of operations and financial condition. Furthermore, lower oil and gas prices over prolonged periods may also reduce the rates of return of development projects either planned or being implemented, leading the Company to reschedule, postpone or cancel development projects. In addition, lower prices also affect liquidity, entailing lower resources to finance expansion projects, further dampening our ability to grow future production and revenues.

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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;
  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 production after the date of the estimates which may require substantial upward or downward revisions;
  changes in oil and natural gas prices which could have an effect on the quantities of Eni’s proved reserves because the estimates of reserves are based on prices and costs at the date when such estimates are made. In particular the reserves estimates are subject to revision as prices fluctuate due to the cost recovery feature under certain Production Sharing Agreements (PSAs); and
  the actual production performance of Eni’s reservoirs.

Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may prove to be incorrect over time. Accordingly, the estimated reserves could be materially 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, production taxes and royalties

Eni operates in different countries in the world and any of these countries could modify their tax laws, regarding both income taxes and other kind of taxes, in ways that would adversely affect Eni’s results of operations and its financial condition.
Adverse changes in tax regimes of each jurisdiction in which Eni operates may occur anytime, regardless of the level of stability of the political and legislative framework in each of our countries of operations. In addition, in the long-term, the marginal tax rate in the oil and gas industry tends 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, 2006, 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 2006, 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 such producing country may affect Eni’s ability to continue operating in that country, either temporarily or permanently, and affect Eni’s ability to access oil and gas reserves. Particularly Eni faces risks in connection with the following: (i) lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws and regulations leading for example to expropriation or forced divestiture of assets and unilateral cancellation or modification of contractual terms. A case in point is the expropriation of Eni’s titles and mineral assets relating to an important oil field in Venezuela which occurred in 2006, following the unilateral cancellation of the contract regulating oil activities in this field by the Venezuelan state oil company; (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 the 2006 episodes of social unrest in Nigeria which caused disruptions at certain Eni oil producing facilities, reducing our production in this Country by approximately 1.7% from the previous year. These episodes have been recurring in the first months of 2007. 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 possible that they can have a material adverse impact on Eni’s results of operations and financial condition.

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

In August 1996, the United States adopted the Iran and Libya Sanctions Act (the "Sanctions Act") with the objective of denying Iran and Libya the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction. In September 2006, the Sanctions Act was amended and extended until December 2011.

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This Act now applies only to Iran and authorizes the President of the United States to impose sanctions from a six-sanction menu under certain circumstances against any person, including any foreign company, making investments in Iran, thus contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources, or against any persons that knowingly contribute to certain military programs of Iran. 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. It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation. 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".

 

Cyclicality of the Petrochemical Industry

The petrochemical industry is subject to cyclical fluctuations in demand, with consequent effects on prices and profitability exacerbated by the highly competitive environment of the industry. Eni’s petrochemicals operations, which are located mainly in Italy, have been in the past and may be adversely affected in the future by worldwide excess installed production capacity, as well as by economic slowdowns in many industrialized countries. The dislocation of petrochemical activities to geographic areas like the Far East and oil producing countries which provide long-term competitive advantages has weakened the competitiveness of petrochemicals operations in industrialized countries, including Eni’s petrochemical operations. Petrochemical operations in industrialized countries are also less competitive than those located in the above-mentioned areas due to stricter regulatory frameworks and growing environmental concerns which prevail in industrialized countries.

 

Liberalization of the Italian Natural Gas Market

Legislative Decree No. 164/2000 opened to competition the Italian natural gas selling market starting on January 1, 2003. This means that 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 as follows: (i) effective January 1, 2002, no single operator can input into the national transport network imported or domestically produced gas volumes higher than 75% of final consumption, decreasing by 2 percentage points per year until it reaches 61% in 2009; and (ii) effective January 1, 2003, no single operator can market more than 50% of volumes sold to final customers.
Compliance with these ceilings is verified on a yearly base by comparing the allowed average percentage on a three year basis for volumes input or sold to the average percentage obtained by each operator in the same three-year period. Allowed percentages are calculated 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 these antitrust thresholds to be renewed once they have expired in 2010;
  transport of natural gas by means of high pressure trunklines, storage of natural gas, LNG facilities and distribution of natural gas in urban centers by means of low pressure networks are activities of public relevance and criteria for determining tariffs of those activities are set by the Authority for Electricity and Gas; and
  third parties are allowed to access natural gas infrastructure – which comprises, among other things, high pressure trunklines, low pressure networks and storage sites – according to certain conditions set by the Authority for Electricity and Gas.

The new regulatory regime has the effect of limiting the size and profitability of Eni’s natural gas business in Italy.

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 entailing lower selling margins on gas due to the entry of new competitors into the market. Certain competitors of Eni’s 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 input into 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 and marketing them on the Italian market. For more information on Eni’s take-or-pay contracts, see "Item 4 – Gas & Power – Natural gas purchases".

_______________

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

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Over both the medium and the long-term, management expects Eni selling margins on gas in Italy to remain under pressure due to the impact of the 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 upgrading of import infrastructure to Italy. In fact, Eni is currently implementing its plans to upgrade its natural gas import infrastructure from Algeria and Russia to Italy to achieve an increase of 13 BCM per year in transport capacity, with expected start up in 2008 reaching full operation in 2009. Further 3 BCM per year of new import capacity will be achieved by upgrading the GreenStream gasline from Libya with expected start up in 2010, reaching full operation in 2011. A large portion of this expected additional capacity has been or is planned to be awarded to third parties. In addition, certain operators in the Italian natural gas market have publicly announced plans to develop new import infrastructure to Italy. In particular, Eni expects that a new LNG terminal with an 8 BCM per year capacity will commence operations by 2009 thus adding new import capacity to the Italian market. Over the long-term, management believes that should the pace of demand growth not match the expected increase in supplies to the Italian natural gas market, Eni’s selling margins on gas could face a further increase in competitive pressure which would negatively affect Eni’s results of operations and financial conditions.

Eni 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 cannot exceed the growth rate of natural gas demand in Italy.

If Eni fails to grow natural gas sales in Europe as planned, Eni may be unable to fulfill its minimum take obligations under take-or-pay purchase contracts and this could adversely impact results of operations and financial condition.

Over the medium-term, Eni plans to increase its natural gas sales in Europe also to absorb its natural gas availability under take-or-pay contracts. Should Eni fail to increase natural gas sales in Europe as planned, some volumes of natural gas purchased under take-or-pay contracts might remain unsold, and this could adversely impact Eni’s results of operations and financial condition.

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

Over the next few years, Eni plans to import certain volumes of natural gas using the highest purchase flexibility as provided for by its take-or-pay purchase contracts. Eni also assumes that it will be entitled to the necessary transport capacity on the Italian transport infrastructure. However, Eni planning assumptions are inconsistent with current rules regulating the access to Italian transport infrastructure as provided for by the Network Code drafted under Decision No. 137 of July 17, 2002 of the Authority for Electricity and Gas. Such rules established certain priority criteria for the entitlement to transport capacity of natural gas at points where the Italian transport infrastructure connects with international transport networks (the so-called entry points to the Italian transport system). In particular current rules establish that take-or-pay contracts entered into before 1998, as in the case of Eni, have the right to a priority in the entitlement to available transport capacity equal to average daily contractual volumes. There is therefore no guaranteed access priority for Eni’s contracted volumes exceeding average daily contractual volumes. In fact, take-or-pay contracts entered into by Eni before 1998 envisage Eni’s right to off take daily volumes larger than the average daily contractual volume; this contractual flexibility provided by the difference between the maximum daily volume Eni is allowed to purchase and the average daily contractual volume is used when demand peaks, usually during the winter. In the event of congestion at entry points, natural gas volumes not receiving priority are entitled to available transport capacity in proportion with requests from operators. Eni considers Decision No. 137/2002 to be inconsistent with the overall rationale of the European natural gas legislative framework, especially with reference to Directive 98/30/CE and Legislative Decree No. 164/2000, and is challenging Decision No. 137/2002 before the competent administrative courts. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". However, Eni cannot rule out a negative outcome in this matter. Accordingly, management believes that Eni’s results of operations could be adversely affected should market conditions and/or regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill take-or pay contract obligations (e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure. Eni would be forced to off take a smaller volume of gas than the minimum contractual off take). See "Item 5 – Management Expectations of Operations".

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

Institutional and political forces are urging a higher degree of competition in the Italian natural gas market and this may produce significant developments on this matter. 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 of 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".

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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). 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 redetermined in 24 months after the effective date of said decree from the Italian Prime Minister. Currently, Eni is unable to predict that date.

On the basis of the findings 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") acknowledged 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 with the aim of defining measures to improve competition. The outcomes of this inquiry was that the retailing market for natural gas in Italy lacks 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 May 2007, the European Commission commenced anti-trust proceedings against Eni based on information obtained during inspections carried out in 2006 at the headquarters of Eni and of certain Eni subsidiaries. These proceedings against Eni are intended to verify the possible existence of any business conducts breaching European competition rules and preventing access to the Italian natural gas wholesale market by booking a majority share of transport capacity of certain international gas lines, thus limiting third party access to those infrastructures, and delaying or annulling certain plans for the upgrading of the international transport infrastructure.

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 financial condition and results of operations in future years.

Decisions of the Authority for Electricity and Gas in 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 selling tariffs for supply of natural gas to residential and commercial users taking into account, among other things, the public interest goal of containing the inflationary pressure due to a rise in energy costs. The decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of the imported gas on to the final consumers of natural gas. In particular following numerous decisions and a lengthy administrative procedure started in 2004 and finalized in March 2007, the Authority finally established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 CM/y, establishing, among other things: (i) that an increase in the international price of Brent crude oil is only partially transferred on to residential and commercial users of natural gas in case international prices of Brent crude oil exceed the 35 dollars per barrel threshold; and (ii) that Italian natural gas importers – including Eni – must renegotiate supply contracts to wholesalers in order to take account of the reduction of the price of natural gas sold to residential and commercial users. While the final outcome of the Authority’s decision on Eni’s accounts was lighter than the initial setup proposed by the Authority of this new indexation mechanism, in future years management cannot exclude the possibility that the Authority could implement similar measures that may negatively affect Eni results of operations and financial condition. 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".

 

Environmental, Health and Safety Regulation

Eni may incur material operating costs and liabilities 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, 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 and petrochemical operations.

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These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemicals 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, health and safety laws and regulations have a substantial impact on Eni’s operations. Risks of environmental, health and safety costs and liabilities are inherent in many of Eni’s operations and products, and there are risks that material expenses and liabilities may be incurred in relation to compliance with environmental, health and safety laws and regulations.

Eni’s results of operations and financial condition are exposed to risks deriving from future contaminations or the ascertain of as yet unknown contaminations, enactment of stricter environmental rules and regulations in the many jurisdictions in which Eni operates, or the arising of litigation with third parties.

Although management, considering remedial actions already performed the existing insurance policies to cover environmental risks and the provision for risks accrued, does not currently expect any material adverse effect on Eni’s consolidated financial statements as a result of the environmental impact of its operations and compliance with applicable environmental laws and regulations, there are risks that Eni may incur significant costs and liabilities in future years due to: (i) the chance of as yet unknown contamination; (ii) future developments in environmental, health and safety regulation, particularly implementation of measures decided at both international and country level to reduce or limit greenhouse gas emissions; (iii) the results of on-going surveys or surveys to be carried out on the environmental status of Eni’s industrial sites as required by the applicable regulations on contamined site; and (iv) 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.

 

Legal Proceedings

Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of business. Although Eni’s management does not currently expect a material adverse effect on Eni’s financial condition and results of operations on the basis of information available to date and taking account of existing provisions, Eni’s management cannot rule out that in future years Eni may incur material losses in connection with pending legal proceedings due to: (i) uncertainty regarding the 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) errors in the estimate of probable future losses.

 

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

Operating results in certain Eni’s businesses, particularly the Exploration & Production, Refining & Marketing, and Petrochemicals segments are affected by changes in the price of oil and by their impact on prices and 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 of oil prices is generally immediate. However Eni’s average realization for oil differs from the price of marker crude Brent due primarily to the circumstance that Eni’s production slate, which also includes heavy crudes, has a lower API gravity compared with Brent crude (when processed the latter allows for higher yields of valuable products compared to heavy crudes, hence higher market price).

The favorable impact of higher oil prices on Eni’s results of operations may be offset by the different trends of margins in 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 Petrochemicals 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. On the contrary, in the Refining & Marketing and Petrochemicals businesses a time lag exists between movements in oil prices and movements in the prices of finished products.

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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.

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

Eni’s petrochemical products margins are affected by trends in demand and changes in oil prices which influence changes in cost of petroleum-based feedstock. Generally, an increase in oil price determines a decrease in petrochemical products margins in the near term.

 

Risks from Acquisitions

In addition to its plans for organic growth, Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or corporations as a way to grow. Acquisitions normally 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 can 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 and no hedging transaction is put in place. 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 Petrochemicals 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 financial condition because it reduces booked revenues by an amount greater than the decrease in dollar-denominated expenses.

 

Risks deriving from Eni’s Exposure to Weather Conditions and Seasonality Factors

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may cause variations in 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, may be affected by such variations in weather conditions. In addition, 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. Furthermore, extreme weather phenomena can result in material disruption to our operations, particularly to offshore production of oil and natural gas.

 

Interest Rates

Interest on Eni’s financial 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 financial expense in respect to its finance debt.

 

Critical Accounting Estimates

The preparation of financial statements entails accounting estimates that are characterized by a high degree of uncertainty, complexity and judgment. Although these critical accounting estimates are thoroughly applied and underlying amounts are fairly determined, management cannot rule out that actual outcomes may 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".

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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 73,572 employees as of December 31, 2006.

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 and subsidiaries are described below.

Eni conducts its exploration and production activities through its Exploration & Production Division and certain operating subsidiaries. Eni’s exploration, development and production activities commenced in 1926, when Agip SpA was established by the Italian Government with a mandate to explore for and develop oil and natural gas. Agip SpA was merged into Eni SpA effective as of January 1, 1997 to become Eni’s Exploration & Production Division.
Eni is engaged in exploration and production of hydrocarbons in Italy, North Africa, West Africa, the North Sea, the Gulf of Mexico, Australia, South America and areas with great development potential such as the Caspian Sea, the Middle and Far East, India and Alaska. In 2006, Eni’s hydrocarbon production available for sale averaged 1,720 KBOE/d and, at December 31, 2006, Eni’s estimated proved reserves totaled 6,436 mmBOE with a life index of 10.0 years. In 2006, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 27,173 million and operating profit of euro 15,580 million.

Eni conducts its natural gas and electricity generation activities through its Gas & Power Division and certain operating subsidiaries. Eni’s natural gas supply, transmission and distribution activities commenced in the 1940s with the commercial sale of natural gas to industrial users in Northern Italy. In past years, Eni conducted its natural gas operations through the subsidiary Snam SpA. Snam SpA was merged into Eni SpA effective as of February 1, 2002 to become Eni’s Gas & Power Division. In 2006, Eni’s sales of natural gas to third parties totaled 50.94 BCM in Italy and 27.93 BCM in the rest of Europe; Eni’s share of natural gas volumes sold by its affiliates totaled 7.65 BCM (of which 6.88 BCM was sold in the rest of Europe). Natural gas volumes consumed in operations by Eni and Eni’s subsidiaries – mainly in electricity generation, refining and petrochemicals operations – totaled 6.13 BCM. Natural gas sales in Italy include: (i) sales to wholesalers, mainly local companies selling natural gas to residential and commercial customers, and to large industrial and thermoelectric customers who are supplied by a high and medium pressure pipeline network; and (ii) sales to residential and commercial customers which are supplied by a low pressure pipeline network. Eni’s high and medium pressure gas pipeline network for natural gas transport is about 30,890-kilometer long in Italy, while outside Italy Eni holds transmission rights on approximately 5,000 kilometers of high pressure pipelines. Eni’s natural gas transport network in Italy is owned and managed by Snam Rete Gas SpA. Snam Rete Gas is listed on the Italian Stock Exchange, Eni’s share being 50.04%. Snam Rete Gas transports natural gas on behalf of Eni and third parties ("shippers"); in 2006 its transported volumes were 87.99 BCM, of which 30.9 BCM were on behalf of third parties. Eni, through its 100% subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,317 municipalities through a low pressure network consisting of approximately 48,700 kilometers of pipelines as of December 31, 2006.
Eni conducts its electricity generation activities through its wholly-owned subsidiary EniPower SpA, which owns and manages Eni’s power stations in Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of approximately 4.9 GW as of December 31, 2006. In 2006, sold production of electricity totaled 24.82 TWh. Eni owns other minor power stations located in Eni’s petrochemical plants and refineries whose production is mainly for internal consumption. The accounts of these power stations are reported within Eni’s Refining & Marketing and Petrochemicals segments.

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In 2006, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 28,368 million and operating profit of euro 3,802 million.

Eni conducts its refining and marketing activities through the Refining & Marketing Division and certain operating subsidiaries. Activities commenced in the 1930s, when Eni initiated the development of the industrial and retail markets for refined products in Italy. In past years, Eni conducted its refining and marketing operations through the subsidiary AgipPetroli SpA. AgipPetroli SpA was merged into Eni SpA effective December 31, 2002 to become Eni’s Refining & Marketing Division. Eni’s refining and marketing activities are located primarily in Italy and in the rest of Europe. In 2006, Eni’s retailing market share for refined products in Italy through its Agip-branded network of service stations was 29.3%. In 2006, sales of refined products totaled 51.13 mmtonnes, of which 29.90 mmtonnes were in Italy. The balanced refining capacity of Eni’s wholly-owned refineries totaled 534 KBBL/d as of December 31, 2006. In 2006, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 38,210 million and operating profit of euro 319 million.

Eni’s petrochemicals activities commenced in the 1950s, when it began production of basic petrochemicals at its Ravenna industrial complex. Through Polimeri Europa SpA and its subsidiaries, Eni operates in olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and in Western Europe. In 2006, Eni sold 5.3 mmtonnes of petrochemical products. In 2006, Eni’s Petrochemicals segment reported net sales from operations (including inter-segment sales) of euro 6,823 million and an operating profit of euro 172 million.

Eni’s oilfield services, construction and engineering activities commenced in the late 1950s. In 2006 Eni SpA divested its 100% stake in Snamprogetti to Saipem SpA (a 43% owned subsidiary). Through Saipem and its subsidiaries, including Snamprogetti, Eni operates in offshore construction, in particular fixed platform installation, subsea pipe laying and floating production systems and onshore construction. Through Saipem and its subsidiaries Eni also provides offshore and onshore drilling services and engineering and project management services to the oil and gas, refining and petrochemical industries. In 2006, Eni’s Engineering & Construction segment reported net sales from operations (including intersegment sales) of euro 6,979 million and operating profit of euro 505 million.

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

 

Strategy

Eni plans to deploy a strategy of profitable growth over both the medium and the long-term, which is intended to create long-term shareholder’s value particularly through significant dividend distributions. In pursuing this strategy Eni plans a capital expenditure program amounting to euro 44.6 billion over the next four years. Eni plans to finance this capital expenditure program by using the cash flows provided by operating activities. Over the next four-year period, the Company expects to distribute to its shareholders an amount of dividends in line with the current level in real terms (See "Item 8 – Dividends"). Eni aims to allocate cash flow in excess of capital expenditure and dividend requirements to continue its programme of share buy-back while at the same time maintaining a strong balance sheet. See "Item 5 – Management Expectations of Operations".

In its Exploration & Production activities, Eni plans to grow production of oil and natural gas through organic growth and by leveraging on the contribution of recently acquired assets in the Gulf of Mexico and onshore Congo, targeting a compound average production growth rate of approximately 4% over the 2007-2010 period, subject to certain market assumptions (See "Item 5 – Management Expectations of Operations"). Organic production growth will be driven mainly by the development of new projects located in the key producing basins of North and West Africa and the Caspian region, and the contribution of long-life fields located mainly in Kazakhstan, Libya, Algeria, Norway, Italy and Egypt. Management will continue to evaluate opportunities to increase production through acquisitions. In addition, Eni intends to pay special attention to reserve replacement in order to secure the medium to long-term sustainability of its business. In the next four-year period, management expects additions to reserves to fully replace produced reserves, assuming a Brent crude oil price of 40 U.S. dollar per barrel in 2010.

In its Gas & Power activities, Eni plans to grow natural gas sales in the rest of Europe and safeguard its leading position in Italy, effectively manage regulated business and the power generation business, and expand LNG sales. In Europe, Eni intends to strengthen its presence in markets where its presence is already established – such as the Iberian Peninsula, Germany and Turkey – and to increase sales in markets with significant growth and profitability prospects (in particular, France and the United Kingdom). To achieve its growth strategy, Eni will leverage on its assets, including gas availability – both equity and purchased under long-term supply contracts – access to infrastructure, its important regasification capacity, long-standing relationships with natural gas producing countries, a large customer base, and market knowledge.

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In Italy, Eni plans to implement a more attractive commercial offer than Eni’s competitors on the basis of the quality of services, pricing formulas including different indexation schemes to suit various customers’ purchasing profiles, and the integration of supply of gas and electricity ("dual offer"), targeting mainly the middle and retail markets. Management expects that the dual offer will achieve important synergies from the integration of processes of client development and management.
By 2010, Eni plans to sell some 105 BCM worldwide, with international sales expected to grow by 10% per year on average.

In its Refining & Marketing activities, Eni intends to improve profitability. In its refining activities, Eni plans: (i) to increase the conversion capacity of its refineries in order to obtain a higher yield of middle distillates; (ii) to enhance the flexibility of its refineries in order to process low-quality crude that is typically discounted in the market-place; and (iii) to reduce operating costs. In marketing, Eni intends to strengthen its leadership position in the Italian retail market by improving the qualitative standards of the Italian network and implementing customer-focused marketing initiatives and effective differentiation of pricing, and to increase sales in selected neighboring countries in the rest of Europe.

In its oilfield services construction and engineering activities, Eni aims at capturing opportunities arising from a growing market, acquiring large projects in complex areas and supporting expenditure plans of the other Eni’s business segments. In order to achieve this, management plans to implement an important expenditure program intended to upgrade its fleet of vessels and rigs.

In technological research and innovation activities, Eni plans to implement an important capital expenditure program to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing existing programmes 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 the high pressure gas transmission (TAP) and Gas to Liquids (GTL) projects, and protecting the environment.

 

Results and Portfolio Developments

The most significant events that occurred during 2006 and to date in 2007 were the following:

  In 2006, hydrocarbon production available for sale averaged 1,720 mmBOE/d, a 1.6% increase compared to 2005. Eni’s net proved reserves of oil and natural gas were 6.44 BBOE (54% crude and condensates), down 401 mmBOE from 2005. The unilateral cancellation of the service contract for the Dación oilfield by the Venezuelan state oil company PDVSA effective April 1, 2006 resulted in a decrease in Eni’s proved reserves of 170 mmBBL. In 2006 Eni’s proved reserves replacement ratio was 38%; as of December 31, 2006, the reserves life index stood at 10.0 years (10.8 as at December 31, 2005).
  In 2006, natural gas sales (97.48 BCM) were up 3.5% due to increased demand for power generation in Italy and to the addition of new customers combined with growth in markets in the rest of Europe as a result of the expansion strategy pursued by Eni.
  In 2006, Eni invested euro 1,348 million in exploratory activities, up 106% from 2005, carrying out a large exploration campaign leading to the completion of 68 exploratory wells (35.9% net to Eni) with a commercial rate of success of 43% (49% net to Eni). A further 26 wells were in progress as of the year-end. Eni enhanced its exploration portfolio by acquiring assets in core areas such as North Africa, West Africa, Brazil, Norway and the United States, and in new high-potential basins such as Mali, Mozambique and East Timor. New acreage covers 152,000 square kilometers (99% operated by Eni).
  In November 2006, Eni and Gazprom signed a broad strategic agreement which strengthens a long-term partnership between the two companies. Key features of this deal are the extension of the duration of Gazprom gas supply contracts to Eni until 2035, further strengthening Eni’s supply portfolio, and the intention of the two partners to pursue joint initiatives in the upstream sector in and outside Russia.
  In April 2007, Eni agreed to acquire interests in exploration and production activities owned by Dominion Resources in the Gulf of Mexico for a total cash consideration of U.S. $4,757 million. Following this deal, Eni expects a 75,000 BOE/d additional oil and gas production in the period 2007-2010 on average, starting from July 1, 2007. Eni will retain operatorship of most of the exploration and production assets acquired.
  In April 2007, as part of the liquidation procedure of the Russian company Yukos, Eni in partnership with Enel (60% Eni, 40% Enel) was awarded 100% of OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia which own large hydrocarbon reserves, mostly gas reserves. Eni also acquired 20% of OAO Gazprom Neft. Cash consideration for this transaction amounted to U.S. $5 billion net to Eni. Gazprom has an option to acquire a 51% interest in these three acquired companies and the entire 20% interest in OAO Gazprom Neft, as this deal is part of Eni’s strategic alliance with Gazprom signed in November 2006.
  In February 2007, Eni agreed to acquire interests in exploration and production onshore activities operated by Maurel & Prom in Congo for a cash consideration of U.S. $1,434 million. Additional hydrocarbon production of approximately 28,000 BOE/d is expected in 2010. This transaction was finalized at the end of May 2007.

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  In April 2007, Eni agreed to purchase 102 retail fuel stations from ExxonMobil Central Europe located in Czechia, Slovakia and Hungary and related additional marketing activities.
  In April 2007, Eni acquired an additional interest in the Nikaitchuq field in Alaska thus achieving a 100% interest.
  In April 2007, Eni signed a Memorandum of Understanding with Sonangol for the acquisition of a 13.6% interest in the Angola LNG Ltd Consortium (A-LNG) committed to build an LNG plant with a capacity of 5 mmtonnes.
  In May 2007, Eni agreed to purchase a 16.11% interest held by ConocoPhillips Central and Eastern Europe Holdings BV in the Ceska Rafinerska Co. When this transaction is finalized, Eni will increase its stake in this refinery from 16.3% to 32.4%, corresponding to a refinery capacity of 2.6 mmtonnes/y.

In 2006, capital expenditure 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 Division (euro 591 million).

In 2005, capital expenditure 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 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).

In 2004, capital expenditure amounted to euro 7.5 billion (of which 94% related to the Exploration & Production, Gas & Power and Refining & Marketing segments) and concerned: (i) development of hydrocarbon fields (euro 4,369 million) in particular in Libya, Iran, Angola, Italy, Kazakhstan, Egypt, Nigeria and Norway, and exploration (euro 499 million); (ii) upgrading of Eni’s natural gas transmission and distribution network in Italy (euro 721 million); (iii) the construction of the tar gasification plant at the Sannazzaro refinery, actions on refineries for the adjustment of automotive fuel characteristics to new European specifications and the upgrade of the refined product distribution network in Italy and in the rest of Europe (for a total of euro 669 million); and (iv) the continuation of construction of electricity generation plants (euro 451 million) and the completion of the GreenStream underwater pipeline project (euro 159 million).

 

BUSINESS OVERVIEW

Exploration & Production

Eni operates in the exploration and production of hydrocarbons in Italy, North Africa, West Africa, the North Sea, the Gulf of Mexico, Australia and South America. It also operates in areas such as the Caspian Sea, the Middle and Far East, India and Alaska where management believes a great mineral potential exists. In 2006, Eni produced 1,720 KBOE/d; as of December 31, 2006, Eni’s proved reserves totaled 6,436 mmBOE. Eni plans to grow production of oil and natural gas through organic growth and leveraging the contribution of recently acquired assets in the Gulf of Mexico and onshore Congo, targeting a compound average production growth rate of approximately 4% over the 2007-2010 period, under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). Organic 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, Algeria, Norway, Italy and Egypt. 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. Management expects additions to reserve to fully replace produced reserves under certain trading environment assumptions (See "Item 5 – Management Expectations of Operations"). 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 through the purchase of interests in liquefaction plants in order to better exploit its natural gas reserves in North and West Africa.

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In exploration activities Eni intends to concentrate resources in such core areas where availability of production facilities and existing competencies will enable Eni to readily put in production the reserves that are eventually discovered, reducing the time to market and achieving synergies. Approximately 70% of planned capital expenditure will be directed to such core areas (located mainly in Egypt, Nigeria, the United States, Libya, Italy and Angola). Further resources will be deployed to ascertain reserves in recently acquired areas (in particular Mozambique, East Timor and Mali). Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic ones.

Eni plans to improve its performance by searching for operating solutions with lower operating costs and synergies.

In order to carry out these strategies, Eni intends to invest approximately euro 30.6 billion on exploration initiatives and reserve development over the next four-year period.

 

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 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 engineers 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.

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 responsibilities to ensure the periodic certification process of reserves, to perform economic evaluation of reserves and to continuously update the Company guidelines on reserves evaluation and classification. All personnel involved in the process of reserve evaluation are knowledgeable on SEC rules and guidelines for proved reserves classification and have professional abilities adequate to the complexity of the task, express their judgment independently and are respectful of professional ethics.

Beginning in 1991 Eni has retained qualified independent petroleum engineering companies to carry out an independent evaluation2 of its proved reserves on a rotating basis. In particular, in 2006 a total of 1.4 BBOE of proved reserves, or about 21% of Eni’s total proved reserves at December 31, 2006, have been evaluated. The results of this independent evaluation confirmed Eni’s evaluations, as they did in past years. In the 2004-2006 three-year period independent evaluations concerned 76% of Eni’s total proved reserves; in particular evaluations concerned all the new development projects, including Kashagan, and most large-sized mature fields.

Eni’s proved reserves of oil and natural gas at December 31, 2006 totaled 6,436 mmBOE (oil and condensates 3,481 mmBBL; natural gas 16,965 BCF) representing a decrease of 401 mmBOE, or 5.9%, from December 31, 2005. The reserve replacement ratio was 38% in 2006; the average reserve replacement ratio for the last three years was 55%. The average reserve life index is 10.0 years at December 31, 2006 (10.8 at December 31, 2005). The reserve replacement ratio was calculated 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 presented in Note 38 to the Consolidated Financial Statements. The Reserve Replacement Ratio is a measure used by management to indicate the extent to which production is replaced by proved oil and gas reserves booked according with the Securities Exchange Commission (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.

_______________

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

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Additions to proved reserves booked in 2006 were 417 mmBOE derived from: (i) extensions and discoveries (161 mmBOE), in particular in Kazakhstan, Algeria, Egypt, Trinidad & Tobago and Libya; (ii) improved recovery (105 mmBOE), in particular in Egypt, Angola, Algeria, Kazakhstan and Nigeria; (iii) revisions of previous estimates (up 151 mmBOE) related to upward revisions registered in Kazakhstan, Libya and Egypt, offset in part by downward revisions in Nigeria and Ecuador. The increase offset in part the decline related to production for the year (646 mmBOE) and the unilateral cancellation of the service contract for the Dación oilfield by the Venezuelan state oil company PDVSA (170 mmBBL). 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 developed reserves at December 31, 2006 amounted to 4,059 mmBOE (2,144 mmBBL of oil and condensates and 10,997 BCF of natural gas), representing 63% of total estimated proved reserves (63% and 60% at December 31, 2005 and 2004, respectively).

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

The table below sets 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.

 

Proved reserves

Eni’s proved reserves of hydrocarbons by geographic area

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(mmBOE)

Italy  

1,199

 

996

 

890

 

868

 

805

North Africa  

2,033

 

2,024

 

2,117

 

2,026

 

2,018

West Africa  

1,287

 

1,324

 

1,357

 

1,279

 

1,122

North Sea  

825

 

912

 

807

 

758

 

682

Rest of the World  

1,686

 

2,016

 

2,047

 

1,865

 

1,773

Total consolidated subsidiaries  

7,030

 

7,272

 

7,218

 

6,796

 

6,400

Unconsolidated entities              

41

 

36

   

7,030

 

7,272

 

7,218

 

6,837

 

6,436

 
 
 
 
 

Eni’s proved reserves of oil by geographic area

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(mmBBL)

Italy  

255

 

252

 

225

 

228

 

215

North Africa  

1,072

 

1,080

 

993

 

961

 

982

West Africa  

1,022

 

1,038

 

1,056

 

936

 

786

North Sea  

498

 

529

 

450

 

433

 

386

Rest of the World  

936

 

1,239

 

1,284

 

1,190

 

1,088

Total consolidated subsidiaries  

3,783

 

4,138

 

4,008

 

3,748

 

3,457

Unconsolidated entities              

25

 

24

   

3,783

 

4,138

 

4,008

 

3,773

 

3,481

 
 
 
 
 

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Eni’s proved reserves of natural gas by geographic area

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(BCF)

Italy  

5,295

 

4,166

 

3,818

 

3,676

 

3,391

North Africa  

5,563

 

5,467

 

6,453

 

6,117

 

5,946

West Africa  

1,533

 

1,656

 

1,729

 

1,965

 

1,927

North Sea  

1,899

 

2,223

 

2,051

 

1,864

 

1,697

Rest of the World  

4,339

 

4,496

 

4,384

 

3,879

 

3,936

Total consolidated subsidiaries  

18,629

 

18,008

 

18,435

 

17,501

 

16,897

Unconsolidated entities              

90

 

68

   

18,629

 

18,008

 

18,435

 

17,591

 

16,965

 
 
 
 
 

Eni’s proved developed reserves of hydrocarbons by geographic area

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(mmBOE)

Italy  

774

 

702

 

671

 

620

 

562

North Africa  

797

 

806

 

961

 

1,230

 

1,242

West Africa  

703

 

710

 

749

 

793

 

798

North Sea  

724

 

822

 

707

 

611

 

571

Rest of the World  

705

 

1,190

 

1,212

 

1,021

 

859

Total consolidated subsidiaries  

3,703

 

4,230

 

4,300

 

4,275

 

4,032

Unconsolidated entities              

31

 

27

   

3,703

 

4,230

 

4,300

 

4,306

 

4,059

 
 
 
 
 

Eni’s proved developed reserves of oil by geographic area

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(mmBBL)

Italy  

168

 

173

 

174

 

149

 

136

North Africa  

610

 

640

 

655

 

697

 

713

West Africa  

554

 

560

 

588

 

568

 

546

North Sea  

426

 

464

 

386

 

353

 

329

Rest of the World  

483

 

610

 

668

 

564

 

402

Total consolidated subsidiaries  

2,241

 

2,447

 

2,471

 

2,331

 

2,126

Unconsolidated entities              

19

 

18

   

2,241

 

2,447

 

2,471

 

2,350

 

2,144

 
 
 
 
 

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

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(BCF)

Italy  

3,397

 

2,966

 

2,850

 

2,704

 

2,449

North Africa  

1,084

 

962

 

1,760

 

3,060

 

3,042

West Africa  

863

 

866

 

924

 

1,289

 

1,447

North Sea  

1,727

 

2,075

 

1,845

 

1,484

 

1,395

Rest of the World  

1,283

 

3,355

 

3,122

 

2,622

 

2,616

Total consolidated subsidiaries  

8,354

 

10,224

 

10,501

 

11,159

 

10,949

Unconsolidated entities              

70

 

48

   

8,354

 

10,224

 

10,501

 

11,229

 

10,997

 
 
 
 
 

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Mineral Right Portfolio and Exploration Activity

As of December 31, 2006, Eni’s portfolio of mineral rights consisted of 1,029 exclusive or shared rights for exploration and development in 36 countries on five continents, for a total net acreage of 385,219 square kilometers (266,002 at December 31, 2005). Of these, 48,273 square kilometers concerned production and development (55,098 at December 31, 2005). Outside Italy net acreage increased by 120,775 square kilometers due to the acquisition of assets after international bid procedures in Angola, Australia, Brazil, Congo, Egypt, Morocco, Nigeria, Norway, Pakistan and the United States, as well as in the new countries/areas of Mali, Mozambique and East Timor. In Italy, net acreage declined by 1,557 square kilometers due to releases.

A total of 68 new exploratory wells were drilled (35.9 of which represented Eni’s share on the basis of its working interest in relevant properties), as compared to 52 exploratory wells completed in 2005 (21.8 of which represented Eni’s share). Overall success rate was 43% in 2006, as compared to 39.3% in 2005; the success rate of Eni’s share of exploratory wells was 49% in 2006, as compared to 47.4% in 2005. In 2004, 66 exploratory wells were completed (29.5 of which represented Eni’s share), with an overall success rate of 52.1% (the success rate of Eni’s share of exploratory wells was 57.3%).

 

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 2006 oil and natural gas production available for sale averaged 1,720 KBOE/d (oil and condensates 1,079 KBBL/d; natural gas 3,679 mmCF/d) increasing by 27 KBOE/d compared to 2005, up 1.6%, despite the impact of the production loss in the Dación oil field in Venezuela (down 46 KBOE/d) and of adverse entitlement effects (down 21 KBOE/d) in PSAs and buy-back contracts due to higher oil prices. Libya, Egypt, Nigeria, Australia and Croatia were the main growth areas in natural gas, while oil production increased in Angola and Libya. Declines in production were attributable to mature field declines and disruptions in Nigeria due to social unrest. Production outside Italy covered 87% of the total (85% in 2005).

Production of oil and condensates (1,079 KBBL/d) increased mainly in: (i) Angola due to the production ramp-up at the Kissanje and Dikanza fields in Phase B of the development of Kizomba in Block 15 (Eni’s interest 20%) and North Sanha/Bomboco in Block 0 (Eni’s interest 9.8%), as well as the start up of the Benguela/Belize/Lobito/Tomboco fields in Block 14 (Eni’s interest 20%); and (ii) Libya, due to the ramp-up of the Bahr Essalam offshore field (Eni’s interest 50%) as part of the Western Libyan Gas Project and the el Feel field (Eni’s interest 23.3%). Production decreased in Venezuela, Nigeria, despite obtaining full production at the Bonga field in OML 118 permit (Eni’s interest 12.5%) and Italy due to technical problems occurred at the FPSO unit in the Aquila field and to production declines of mature fields.

Production of natural gas available for sale (3,679 mmCF/d) increased mainly in: (i) Libya, due to the reaching of full production at the Bahr Essalam offshore field (Eni’s interest 50%); (ii) Egypt, for full production/start up of the Barboni, Baltim North and Anshuga fields and the increase in the number of production wells at the el Temsah 4 platform in the offshore of the Nile Delta and increased supplies to the Damietta liquefaction plant (Eni’s interest 40%); (iii) Nigeria, due to increased supplies to the Bonny LNG plant (Eni’s interest 10.4%) related to the start up of trains 4 and 5; (iv) Australia, due to the start up of supplies to the Darwin liquefaction plant linked to the Bayu Undan liquid and gas field (Eni’s interest 12.04%); and (v) Croatia, due to the start up of the Ika, Ida and Ivana C-K fields (Eni’s interest 50%) in the Adriatic offshore. These increases were offset in part by a decline registered in Italy resulting from the production decline of mature fields.

Hydrocarbon production sold amounted to 625.1 mmBOE. Approximately 68% of oil and condensate production sold (391.1 mmBBL) was ultimately sold to Eni’s Refining & Marketing segment; 40% of natural gas production sold (1,343 BCF) was ultimately sold to Eni’s Gas & Power segment.

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The tables below set forth Eni’s production of oil and condensates and natural gas for the periods indicated.

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(KBBL/d)

Production of oil and condensates (1)                    
Italy  

86

 

84

 

80

 

86

 

79

North Africa  

252

 

250

 

261

 

308

 

329

West Africa  

222

 

236

 

285

 

310

 

322

North Sea  

213

 

235

 

203

 

179

 

178

Rest of the World  

148

 

176

 

205

 

228

 

171

Total  

921

 

981

 

1,034

 

1,111

 

1,079

 
 
 
 
 

(1)   Data includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method of accounting.

 

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(mmCF/d)

Natural gas production available for sale (1) (2)                    
Italy  

1,260

 

1,181

 

1,067

 

972

 

883

North Africa  

560

 

559

 

619

 

900

 

1,187

West Africa  

87

 

128

 

143

 

151

 

232

North Sea  

516

 

596

 

560

 

563

 

557

Rest of the World  

592

 

710

 

782

 

758

 

820

Total  

3,015

 

3,174

 

3,171

 

3,344

 

3,679

 
 
 
 
 

(1)   Data includes Eni’s share of production of affiliates and joint ventures accounted for under the equity method of accounting.
(2)   It excludes production volumes of natural gas consumed in operations. Said volumes were 132, 151, 220, 250 and 286 mmCF/d in 2002, 2003, 2004, 2005 and 2006, 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 57 KBOE/d and 20.5 KBOE/d in 2006 and 2005, respectively.

 

Portfolio Developments

In February 2007, Eni acquired certain onshore exploration and production assets operated by Maurel & Prom, entailing a cash consideration of U.S. $1,434 million. This transaction includes the producing fields of M’Boundi (48.6%) and Kouakouala A (66.7%), and the exploration permit Le Kouilou (50%). Such assets were subject to a pre-emption right in favor of Burren Energy, partner of Maurel & Prom. Subsequently, Eni and Burren Energy reached an agreement providing for Burren Energy’s waiver of the exercise of its pre-emption right and Eni’s sale to Burren Energy of a 5.5% interest in the M’Boundi concession and a 2% stake in the Le Kouilou exploration permit under the same economic terms as the acquisition from Maurel & Prom, entailing cash proceeds of $154 million. Eni retains the operatorship and participating interests of 43.1% and 48% in the M’Boundi concession and Le Kouilou exploration permit, respectively. This operation was finalized at the end of May 2007 following approval by the relevant Congolese authorities. Eni expects an additional production of approximately 28 KBOE/d in 2010.

On April 2, 2007, Eni and Sonangol signed a Memorandum of Understanding for the acquisition of a 13.6% stake in Angola LNG Ltd Consortium (A-LNG). This company is responsible for the construction of an LNG plant in Soyo, 300 km North of Luanda, with a yearly capacity of 5 mmtonnes. The project has been approved by the Angolan Government and Parliament. The LNG will be directed to the United States market and will be delivered to the re-gasification plant of Pascagoula, in the Gulf of Mexico, in which Eni, following this agreement, will acquire re-gasification capacity of 5 BCM/y.

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On April 4, 2007, Eni, through the partnership in EniNeftegaz (60% Eni, 40% Enel SpA) acquired Lot 2 in the Yukos liquidation procedure for a total price of U.S. $5.83 billion (Eni’s share being $5 billion). Lot 2 includes: 100% of OAO Arctic Gas Co, 100% of ZAO Urengoil Inc and 100% of OAO Neftegaztechnologia. These three companies own 5 gas and condensate fields and parts of other fields in the Yamal Nenets (YNAO) region, a large gas producing region. Management believes these three companies to have significant oil and gas resources. Eni and Enel have offered Gazprom an option to acquire a 51% interest in these companies within two years. In the event that Gazprom exercises its call option, the assets will be operated through a joint venture between Eni and Gazprom, which will have access to Eni’s technologies. Lot 2 also includes various minor assets that will be sold or liquidated and 20% of OAO Gazprom Neft which will be wholly owned by Eni. Eni offered Gazprom an option to acquire this 20% interest in OAO Gazprom Neft within two years, at a total price of $3.7 billion, in addition to financial expenses related to the acquisition. These agreements are an additional step in implementing the strategic partnership between Eni and Gazprom signed in November 2006, under which the two companies established an alliance to develop upstream, midstream and downstream energy projects inside and outside of Russia.

On April 11, 2007, Eni acquired 70% and the operatorship of the Nikaitchuq field, located on-offshore in the North Slope of Alaska. Eni, which already owned a 30% stake in the field, now retains the 100% working interest. Nikaitchuq would be the first development project operated by Eni in Alaska. Successful appraisal drilling has been completed. Plans for a phased development are currently being evaluated with the target of sanctioning the project by year end, and first oil by the end of 2009. The Nikaitchuq project comprises the drilling of approximately 80 wells, out of which 32 are located onshore and the remaining from an offshore artificial island. All wells will then be tied back to a production facility located at Oliktok Point, which is expected to reach an output of 40 KBOE/d.

On April 30, 2007 Eni agreed to acquire the Gulf of Mexico upstream activity of Dominion Resources at the price of U.S. $4,757 million including exploration assets for U.S. $680 million. The transaction includes production, development and exploration assets located in deepwater Gulf of Mexico. Starting from the second half of 2007 until 2010, production from the acquired assets is expected to average approximately 75 KBOE/d. In addition, Eni will enhance its portfolio in the Gulf of Mexico thanks to new leases with significant exploration potential; approximately 60% of these leases are operated. The transaction is subject to government approvals, expiration of certain preferential purchase rights which apply to a small portion of the acquired assets (less than 5% of total reserves), and to other customary conditions precedent. Closing is expected on July 2, 2007.

 

 

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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, 2006.

 

Principal oil and natural gas interests at December 31, 2006

   

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

 

171

 

28,508

 

22,496

 

12,743

 

Onshore/Offshore

 

90

 

89

                                 
North Africa                                
Algeria  

1981

 

36

 

12,739

 

3,456

 

861

 

Onshore

 

26

 

12

Egypt  

1954

 

53

 

23,214

 

13,901

 

2,401

 

Onshore/Offshore

 

37

 

30

Libya  

1959

 

17

 

39,569

 

34,113

 

12,783

 

Onshore/Offshore

 

11

 

15

Tunisia  

1961

 

14

 

6,464

 

2,274

 

1,223

 

Onshore/Offshore

 

13

 

4

       

120

 

81,986

 

53,744

 

17,268

     

87

 

61

                                 
West Africa                                
Angola  

1980

 

49

 

18,776

 

3,275

 

1,099

 

Offshore

 

39

 

30

Congo  

1968

 

20

 

9,797

 

4,169

 

880

 

Offshore

 

17

 

7

Nigeria  

1962

 

49

 

43,215

 

7,356

 

5,715

 

Onshore/Offshore

 

122

 

23

       

118

 

71,788

 

14,800

 

7,694

     

178

 

60

                                 
North Sea                                
Norway  

1965

 

47

 

18,851

 

7,077

 

123

 

Offshore

 

9

 

6

The United Kingdom  

1964

 

75

 

5,860

 

1,328

 

688

 

Offshore

 

33

 

13

       

122

 

24,711

 

8,405

 

811

     

42

 

19

                                 
Rest of world                                
Australia  

2001

 

13

 

24,143

 

19,910

 

2,279

 

Offshore

 

2

 

1

Brazil  

1999

 

3

 

2,948

 

2,802

     

Offshore

       
China  

1983

 

4

 

866

 

181

 

103

 

Offshore

 

9

 

4

Croatia  

1996

 

3

 

6,056

 

3,028

 

987

 

Offshore

 

5

 

5

Ecuador  

1988

 

1

 

2,000

 

2,000

 

2,000

 

Onshore

 

1

 

1

East Timor  

2006

 

5

 

12,224

 

12,224

     

Offshore

       
India  

2005

 

2

 

14,445

 

5,698

     

Onshore/Offshore

       
Indonesia  

2001

 

13

 

28,438

 

16,301

 

656

 

Onshore/Offshore

 

7

 

8

Iran  

1957

 

4

 

1,456

 

820

 

820

 

Onshore/Offshore

 

4

   
Kazakhstan  

1995

 

6

 

4,934

 

960

 

489

 

Onshore/Offshore

 

1

 

5

Pakistan  

2000

 

18

 

29,790

 

20,965

 

615

 

Onshore/Offshore

 

6

 

1

Saudi Arabia  

2004

 

1

 

51,687

 

25,844

     

Onshore

       
Trinidad & Tobago  

1970

 

1

 

382

 

66

 

66

 

Offshore

 

3

 

2

United States  

1968

 

391

 

7,803

 

3,758

 

560

 

Onshore/Offshore

 

20

 

5

Venezuela  

1998

 

4

 

1,958

 

790

 

66

 

Offshore

     

1

       

469

 

189,130

 

115,347

 

8,641

     

58

 

33

Other      

9

 

6,311

 

1,240

 

1,116

 

Offshore

     

1

Other countries with only exploration activity      

20

 

299,705

 

169,187

     

Onshore/Offshore

       
Outside Italy      

858

 

673,631

 

362,723

 

35,530

     

365

 

174

Total      

1,029

 

702,139

 

385,219

 

48,273

     

455

 

263

   
 
 
 
 
 
 
 

(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 2006 Eni’s oil and gas production amounted to 233 KBOE/d. Eni’s activities in Italy are concentrated in the Adriatic Sea, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley. Eni’s exploration and development activities in Italy are regulated by concession contracts.

The Adriatic Sea represents Eni’s main production area in Italy, accounting for 49% of Eni’s domestic production in 2006. Production is composed mainly of natural gas. Main operated fields are Barbara (177 mmCF/d net to Eni), Angela-Angelina (71 mmCF/d), Porto Garibaldi (71 mmCF/d) and Cervia (57 mmCF/d).

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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 is supplied from the Monte Alpi, Monte Enoc and Cerro Falcone fields through 22 production wells of the 36 foreseen by the sanctioned development plan and is supported by the Viggiano oil center, containing 6 trains with a treatment capacity of 104 KBBL/d of oil and 99 mmCF/d of natural gas. Oil produced is delivered to Eni’s refinery in Taranto via a 136-kilometer long pipeline. In 2006 the Val d’Agri concession produced 104 KBOE/d (68 net to Eni), corresponding to 29% of Eni’s production in Italy.

Eni is operator of 13 production concessions onshore and offshore Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2006 accounted for 6% of Eni’s production in Italy. In the second half of 2006, the Samperi well was started up with full production of approximately 2,871 CF/d to be reached in 2007.

In 2006 development activities concerned in particular: (i) optimization of production from mature fields by means of sidetracking and infilling operations (Barbara A/H, Daria, Basil and Anemone for gas and Rospo for oil); and (ii) continuation of drilling and upgrading of producing facilities in the Val d’Agri.

The main ongoing development project is Miglianico, located onshore in the Abruzzi Region, Central Italy. Production is expected to start in the second half of 2008. This project provides for the construction of facilities intended to treat production volumes of oil, to be delivered to logistic structures of the Refining & Marketing Division, and to desulfurize production volumes of gas to be input into the Italian natural gas transportation network.

Development of gas fields is nearing completion at: (i) Tea, Arnica, Lavanda in the Adriatic offshore where start up of production is expected in 2007 after a production platform and linkage facilities were installed in 2006; (ii) Candela, where start up is expected in 2007; and (iii) certain gas fields in Sicily: Pizzo Tamburino, scheduled for the second half of 2007 with expected production of 1,000 BOE/d, and recovery of additional reserves of Fiumetto concession, where start up is expected in the first half of 2007 peaking at 600 BOE/d.

The main gas discoveries for the year were made in: (a) the onshore San Potito concession, in Emilia the Longanesi 1 well, at a depth of 2,540 meters; (b) the offshore of Sicily (GR.13.AG permit, Argo 1 well, Eni’s interest 60%) at a depth between 1,350 and 1,520 meters; (c) the Adriatic Sea (AR.95.EA permit, Benedetta 1 well) at a depth of 2,090 meters which yielded 145 KCM/d of gas in test production; and (d) the onshore of Sicily (San Teodoro permit, Borgo Giuliano 1 well) at a depth of about 2,000 meters.

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2006, North Africa accounted for 31% of Eni’s total worldwide production of hydrocarbons.

Algeria Eni has been present in Algeria since 1981. In 2006, Eni’s oil production averaged 88 KBBL/d. Operating activities accounting for 53% of Eni’s production in Algeria 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) Block 403 (Eni’s interest 50%); (d) Blocks 212 (Eni’s interest 22.38%) and 208 (Eni’s interest 12.25%); and (e) exploration Blocks 404a (Eni’s interest 25%) and 403 c/e (Eni’s interest 33.33%). Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSA) and concession contracts.

Production in the Block 403 a/d is supplied mainly by the HBN and ROM and satellite fields. Blocks 403 a/d accounted for approximately 41% of Eni’s production in Algeria in 2006. The main project underway is ROM/ZEA Integrated Development for the production of reserves ascertained by the recent appraisal activity conducted in the area, leading to a revaluation of the resources of this area. Current production is collected at ROM’s Central Production Facility and delivered to the treatment center in Bir Rebaa North in Block 403. The project provides for the upgrade of production facilities and the injection into the field of water and gas currently flared at the ROM satellite center. As a result, flared gas is expected to be reduced by approximately 90%, as required by applicable Algerian laws. Production is expected to peak at 21 KBBL/d (12 net to Eni) in 2010.

Daily production from the Blocks 401a/402a is supplied mainly by the ROD and satellite fields and accounted for approximately 27% of Eni’s production in Algeria in 2006. Infilling activities are being performed on producing fields in order to maintain the current production plateau. The drilling of a further 6 wells (4 production and 2 water injection wells) is planned for the recovery of recently ascertained reserves.

The main fields in Block 403 are BRN, BRW and BRSW and the block accounted for approximately 13% of Eni’s production in Algeria in 2006. In June 2007, the BRN field permit expired. The field was producing 3 KBOE/d.

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 (212 and 405a and 404, operated by other companies) is the main project underway in Algeria. In Block 208 the EKT, EMK, EMN and EME oil and gas fields, discovered between 1993 and 1998, are expected to be developed.

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The working plan provides for the drilling of 145 wells that are expected to be linked to a Central Production Facility with a treatment capacity of 150 KBBL/d of oil and approximately 1 BCF/d of associated wet gas for the extraction of liquids (approximately 50 KBBL/d) and the subsequent gas cycling (reinjection in the field). Marketing of associated gas is envisaged 8 years after the production start up. Production is expected to start in 2010, peaking at 141 KBOE/d (18 net to Eni) in the same year. About 85% of basic engineering was completed in 2006.

The main discoveries for the year were: (a) in onshore Block 403a the appraisal wells ROM N2 and N3 found oil at a depth of about 3,300 meters; and (b) in onshore Block 404a, the BBKS-1 discovery well showed the presence of oil at a depth of 3,160 meters which yielded 700 BBL/d in test production; the appraisal well BBKSE-1 showed the presence of oil at a depth of about 3,200 meters and confirmed the eastward extension of the BBKS structure.

Algeria is currently reviewing the fiscal regime applicable to foreign oil companies. With regard to the legislative text already enacted, fiscal terms applicable to existing PSAs to which foreign oil companies are parties have not been modified. Nevertheless, Sonatrach, the state oil company, is currently bearing higher taxation on behalf of foreign oil companies. On this basis, Sonatrach intends to renegotiate the economic terms of certain PSAs to which Eni or other Eni co-venture partners are party. According to Sonatrach, renegotiation of contractual terms is necessary 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 addition, the Algerian parliament with the Decree No. 06-440 of December 2, 2006 enacted the procedure, the application framework and the calculation methodology of a windfall tax levied to foreign oil companies as approved by the Government. Effective August 1, 2006, said windfall tax applies to the extent that oil prices exceed $30 per barrel and foresees rates ranging from 5 to 50% depending on the share of production to which a foreign company is entitled and the contractual scheme in force with Sonatrach. In 2006, the application of such tax entailed higher current taxation and a deferred tax charge for a total impact on Eni of euro 328 million.

In the medium-term, management expects production in Algeria to increase reflecting ongoing development activities, targeting a 100 KBOE/d level by 2010.

Egypt Eni has been present in Egypt since 1954. In 2006, Eni’s share of production in this country amounting to 221 KBOE/d accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing activities are located in the Belayim concession (Eni’s interest 100%) located in the Gulf of Suez which contains oil and condensates and in the North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (Eni operator with a 50% interest), Ras el Barr (Eni’s interest 50%) and el Temsah (Eni operator with a 50% interest), predominantly gas concessions located offshore in the Nile Delta. In 2006 production from these concessions accounted for 90% of Eni’s production in Egypt. Exploration and production activities in Egypt are regulated by concession contracts and PSAs.

Development activities are underway in the offshore area of the Nile Delta: (i) in the North Port Said concession (Eni’s interest 100%), the Anshuga gas field was linked to the production facilities of the nearby Nouras field by means of a sea line, starting production in October 2006. Production is expected to peak at 17.3 mmCF/d net to Eni. This and other ongoing development activities aim at maintaining the current gas production level of 406 mmCF/d net to Eni; (ii) in the Ras el Barr concession (Eni’s interest 50%), engineering activities are underway for the development of gas reserves in the offshore Taurt field. This project provides for the drilling of seven wells which are expected to be linked to existing onshore treatment facilities. Production is expected to start in 2008. A second development step of the Ha’py field was completed. Ongoing development activities aim at maintaining the current gas production level of 168 mmCF/d net to Eni; and (iii) in the el Temsah concession (Eni operator with a 50% interest), gas and condensates production started at the Temsah NW 2 platform. Main projects include the development of reserves at the Denise field and its satellites through existing facilities at Denise A installed on the TNW 2 platform. Ongoing development activities aim at reaching a peak production of 137 KBOE/d (41 net to Eni) in 2008.

As part of the expansion plan of the Damietta LNG plant, Eni and its partners signed a framework agreement in June 2006 for doubling the capacity of the Damietta liquefaction plant by means of the construction of a second train with a treatment capacity of 268 BCF/y of gas corresponding to approximately 5 mmtonnes/y of LNG for a twenty-year period starting in 2010. This project is expected to support the ramp-up of Eni’s natural gas production in the Nile Delta, targeting supplies of 88 BCF/y. Eni is currently supplying 53 BCF/y to the first train for a twenty-year period.

Main discoveries for the year were in: (a) offshore Abu Rudeis permit (Eni’s interest 100%) the Abu Rudeis Marine 4 discovery well showing the presence of liquids at a depth of over 3,000 meters; the well was linked to existing production facilities; (b) onshore West Razzak permit (Eni’s interest 80%), the Aghar SW-1X discovery well showed the presence of high quality liquids at various levels at a depth between 1,800 and 2,300 meters; (c) offshore West Baltim permit (Eni’s interest 100%), the Meret 1 and 2 discovery wells showed the presence of natural gas and condensates at various levels at depth between 1,500 and over 3,000 meters; (d) offshore Thekah permit (Eni’s interest 50%), the Thekah North 1 discovery well showed the presence of natural gas at a depth between 1,350 and 1,650 meters; the well was linked to existing production facilities; and (e) onshore Meleiha permit (Eni’s interest 56%) the Lotus North 1-X discovery well showed the presence of oil at a depth of over 2,000 meters and has started to produce. The Nada Ne 1-X discovery well showed the presence of oil and natural gas at a depth of 1,900 meters in the same area and has started to produce.

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In the medium-term, management expects to increase Eni’s production in Egypt to approximately 250 KBOE/d reflecting ongoing development of gas reserves, despite expected production decline of mature oil fields.

Libya Eni started operations in Libya in 1959. In 2006 Eni’s oil and gas production averaged 213 KBOE/d, the portion of liquids was 65%. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan Desert. The main production blocks in which Eni holds interests are: (i) Block NC169A onshore (Eni’s interest 50%) and Block NC41 offshore (Eni’s interest 30% for oil and 50% for gas); (ii) Block NC174 onshore (Eni’s interest 33.3%, for development phase); and (iii) onshore concessions 82 and 100 (Eni’s interest 50%). Eni also holds a 50% interest for development phase, in the Block NC118 where, after a declaration of commercial discovery, it is developing the A-NC118 field. In the exploration phase, Eni is operator of four onshore blocks in the Muzurk basin (161/1, 161/2 & 4, 176/3) and in the Kufra area (186/1, 2, 3 & 4). Eni’s exploration and production activities in Libya are regulated by concessions and PSAs.

Block NC169 located onshore in the Western Libyan Desert near the Algerian borderline includes the liquids and gas Wafa field; Block NC41 located off Libya's Northern Mediterranean coastline includes the liquids and gas Bahr Essalam field. These two fields have been developed as part of the upstream-midstream integrated Western Libyan Gas Project (WLGP) aimed also at exporting natural gas to Europe through the underwater GreenStream pipeline. In 2006 volumes delivered through this pipeline were 240 BCF and are expected to target 283 BCF (equal approximately to an average of 777 mmCF/d) when operations are fully on line. Said volumes are supplied to third parties on the Italian natural gas market under long-term contracts. Further 71 BCF of gas will be delivered to the Libyan market. Production from these two fields is supported by the Mellitah plant on the Libyan coast, made up of three trains for the treatment of gas volumes from Bahr Essalam. Gas volumes produced at Wafa are treated at Wafa facilities. Mellitah also includes facilities for the compression of natural gas that is delivered to Sicily, as well as facilities for the storage and loading of oil and LPG. Block NC41 also includes the Bouri oil field. As part of development activities in the Bouri Est Area, four producing subsea wells were successfully drilled and linked to the existing facilities. In 2006 the field yielded 55 KBBL/d (16 net to Eni).

Block NC174 is located in the Southwestern Libyan desert about 800 kilometers from of Tripoli. Daily production is provided by the el Feel field. In 2006 the field yielded 124 KBBL/d (24 net to Eni) treated at the field’s facilities and then delivered via pipeline to the Mellitah plant for storage and loading. This field has already reached the planned production peak of 150 KBBL/d (35 net to Eni).

Concessions 82 and 100 are located in the Eastern Central Libyan desert. Oil production is provided by the Bu Attifel oil field as well as by minor fields in concession 82. In 2006 they yielded 58 KBBL/d net to Eni. Development activities concerned the drilling of some infilling wells.

Main discoveries for the year were in: (a) offshore Block NC 41, the T1 discovery well showed the presence of oil at a depth of 2,800 meters; and (b) onshore concession 82-10 (Eni’s interest 50%), the KK4-82/ST3 discovery well showed the presence of oil at a depth of 5,000 meters.

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

Mali In November 2006, Eni purchased five onshore exploration licenses (Eni operator with a 50% interest) from Baraka Mali Operations Ltd and Baraka Mali Ventures Ltd, covering a gross acreage of approximately 193,200 square kilometers (96,600 net to Eni). Blocks are located in the central part of the Taodueni Basin at the border with Algeria, a completely unexplored and high potential basin according to recent studies. The life span of this exploration license was fixed at four years. In March 2007, this operation was approved by the Malian Authorities.

Tunisia Eni has been present in Tunisia since 1961. Its main producing interests are in the el Borma oil field and in the oil and gas Hammouda and Oued Zar fields, operated by Eni with a 50% interest. In 2006 Eni produced 14 KBOE/day.

Main discoveries for the year were in: (a) Larish concession (Eni’s interest 50%), the Larish SE-1 well found oil at a depth of about 3,000 meters and was linked to existing production facilities; (b) Adam concession (Eni operator with a 25% interest), the Karma-1 well showed an oil formation at a depth of 3,617 meters, which confirmed it as a high potential basin; and (c) in Bordj el Kadra concession (Eni operator with a 50% interest), the Nakhil-1 discovery well showed the presence of high quality oil at a depth of approximately 4,000 meters.

In the medium-term production is expected to increase above 20 KBOE/d with the start up of the offshore fields Maamoura and Baraka.

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West Africa

Eni’s operations in West Africa are conducted in Angola, Congo and Nigeria. In 2006, West Africa accounted for 21% of Eni’s total worldwide production of hydrocarbons.

Angola Eni has been present in Angola since 1980. In 2006 Eni’s oil production averaged 151 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

The main blocks in which Eni holds an interest are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) West of the Angolan coast; (ii) Block 14 (Eni’s interest 20%) in the deep offshore West of Block 0; and (iii) 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%). In the exploration phase, Eni holds interests in the 14K/A IMI Unit Area and in Block 3/05-A with an 11.5% and a 12% interest, respectively. In May 2006, following an international bid procedure, Eni was awarded the role of operator in the exploration license of offshore Block 15/06 (Eni’s interest 35%). This Block covers a gross acreage of approximately 3,000 square kilometers. The exploration plan envisages drilling of eight wells during a five-year period and an option for extending the license period over a further three-year period and the drilling of three additional wells. In November 2006, Eni signed the relevant Production Sharing Contract (PSC) with the State oil company Sonangol. Exploration and production activities in Angola are regulated by concessions and PSAs.

On April 2, 2007 Eni and Sonangol signed a Memorandum of Understanding for the acquisition of a 13.6% stake in Angola LNG Ltd Consortium (A-LNG). This company is responsible for the construction of an LNG plant in Soyo, 300 km North Luanda, with a yearly capacity of 5 mmtonnes. This project has been approved by the Angolan Government and Parliament. It envisages the development of 7,770 BCF of gas, the production of 128 mmtonnes of LNG, 104 mmBBL of condensate and 257 mmBBL of LPG along a 28-year period. The LNG is planned to be re-gasified at the Pascagoula plant on the coast of the Gulf of Mexico for delivery to the United States market. Following this agreement, Eni plans to acquire a share of the re-gasification capacity of this plant corresponding to 177 BCF/y.

In 2006, production started at Benguela/Belize and Lobito/Tomboco fields in Block 14 (Eni’s interest 20%), in January and June, respectively. Joint development of these fields was carried out by installing a compliant piled tower provided with treatment facilities for Benguela/Belize and an underwater connection to this tower for Lobito/Tomboco. Production is expected to peak at 158 KBBL/d (20 net to Eni) in 2009 upon completion of the drilling program.

Development of the Banzala oil field in Block 0 in Cabinda (Eni’s interest 9.8%) moved forward with the installation of a production platform and drilling of producing and water injection wells. Production is expected to start in the first quarter of 2007 and to peak at 27 KBBL/d (3 net to Eni) in 2009.

An intense campaign to develop reserves in Block 15 (Eni’s interest 20%) is underway: (i) in March 2006, development of the Mondo and Saxi/Batuque oil fields started as part of Phase C of the development of reserves in the Kizomba deep offshore area. A common development strategy is expected to be deployed in both projects, envisaging the installation of an FPSO vessel. Production is expected to start in the first quarter and in second quarter of 2008, respectively. Peak production at 100 KBBL/d (18 net to Eni) is expected in both projects in 2009; and (ii) in December 2006, development of the Marimba oil field started with the drilling of producing wells which will be connected to existing facilities in Kizomba A. Peak production is expected in 2008 at 39 KBOE/d (7 net to Eni).

Development activities at the Landana and Tombua oil fields in Block 14 offshore (Eni’s interest 20%) progressed with the drilling of producing wells, one of which has already been started up in June 2006. A few production wells, one of which was started up in June 2006 shall be linked to existing facilities at Benguele/Belize-Lobito/Tomboco. Peak production at 130 KBBL/d (22 net to Eni) is expected in 2010.

Main discoveries for the year were: (a) the development concessions deriving from former Block 15 (Eni’s interest 20%), the Tchihumba 2 appraisal well confirmed the presence of oil at a depth of about 3,000 meters; (b) Block 14K/A IMI unit (Eni’s interest 11.5%), where the Lianzi discovery was made, appraisal activities conducted in the area confirmed the presence of hydrocarbon layers at a depth over 3,000 meters; and (c) offshore Block 14 (Eni’s interest 20%), the Lucapa 1 discovery well found oil and natural gas at a depth of about 1,200 meters.

In the medium-term, management expects to increase Eni’s production to approximately 160 KBBL/d reflecting contributions from ongoing development projects, despite the production decline of mature fields.

Congo Eni has been present in Congo since 1968 and its activities are concentrated in the conventional and deep offshore facing Pointe Noire. In 2006 production averaged 65 KBOE/d net to Eni, mainly comprised of oil production. Exploration and production activities in Congo are regulated by PSA.

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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%). Eni holds a 35% interest in the Pointe Noire Grand Fonde and Pex permits. Eni also holds interests in the two deep offshore blocks Mer Très Profonde Nord (Eni operator with a 40% interest) and Mer Très Profonde Sud (Eni’s interest 30%), and in the Block Marine X (Eni operator with a 90% interest).

In May 2006 Eni signed a Protocole d’accord aimed at exploiting the gas mineral potential of the Marine XII permit for feeding a high yield power station. In April 2007 the Assignment Agreement for the exploration license Marine XII has attributed Eni the role of operator with a 90% interest.

In February 2007 Eni concluded an agreement with the Indian company ONGC Videsh whereby exploration interests in India and Congo were exchanged. Following this transaction Eni acquired a 34% interest in block MN-DWN-2002/1 with high mineral potential in the Indian offshore at a water depth of 2,000 meters with a total acreage of 10,000 square kilometers and will give to its partner a 20% interest in the Mer Très Profonde Nord permit (Eni operator with a 40% interest) offshore Congo.

In June 2006, the offshore Litanzi field in the Pex permit started production, peaking at 4 KBOE/d (1.4 net to Eni). Development activities at the Awa Palouku and Ikalou-Ikalou Sud field are underway. Production is expected to start in 2008 peaking at 12 KBOE/d net to Eni in 2009.

Exploration yielded positive results in the Mer Très Profonde Sud permit with the Aurige Nord Marine discovery that yielded approximately 5 KBOE/d in test production.

In the medium-term, management expects to increase Eni’s production to approximately 100 KBBL/d due to the contribution from recently acquired assets.

Nigeria Eni has been present in Nigeria since 1962 and its activities are concentrated in the onshore and offshore of the Niger Delta. In 2006, Eni’s oil and gas production averaged 147 KBOE/d. In the development/production phase Eni is operator in 4 onshore Oil Mining Leases (OMLs) 60, 61, 62 and 63 (Eni’s interest 20%) and in OML 125 (Eni’s interest 50.19%), OMLs 120-121 (Eni’s interest 40%) and OML 118 (Eni’s interest 12.5%) offshore. It also holds a service contract for the offshore OMLs 119 and 116. Through the SPDC oil joint venture, Eni 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 the offshore Oil Prospecting License (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 50.19%) and OML 135 (former OPL 219 - Eni’s interest 12.5%) and the onshore OPL 282 (Eni’s interest 90%).

In March 2007, Eni obtained the role of operator with a 48% interest in the onshore OPL 135. The exploration plan envisages research for and development of oil and natural gas reserves in the proximity of existing facilities at the Kwale/Okpai power station where Eni is operator.

Exploration and production activities in Nigeria are regulated by service contracts and PSCs.

The Forcados/Yokri oil and gas fields (Eni’s interest 5%) are currently under development offshore and onshore in the Niger Delta. Development is expected to be completed in 2007 as a 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 Okri and North/South Bank flowstations and the construction of a gas compressor plant.

Eni holds a 10.4% interest in Nigeria LNG Ltd which manages the liquefaction plant located on Bonny Island, in the Eastern part of the Niger Delta, with a treatment capacity of approximately 812 BCF/y of feed gas corresponding to a production of 17 mmtonnes/y of LNG on 5 trains. A sixth train is under construction with a treatment capacity of 4.1 mmtonnes/y, expected to start operations by the end 2007. Engineering activities of a seventh train are underway. When fully operational, this plant is expected to have a capacity of 30 mmtonnes/y of LNG corresponding to about 1,448 BCF/y of feed gas. Natural gas supplies to the plant (first six trains) will be provided under a gas supply agreement with a 20 year term. Production volumes will come from the SPDC joint venture and OMLs 60, 61, 62 and 63. When fully operational, supplies will total approximately 3,461 mmCF/d (268 net to Eni, corresponding to approximately 46 KBOE). LNG production is sold under long-term contracts and exported by the Bonny Gas transport fleet, wholly owned by the Nigeria LNG Co. This fleet is composed of 18 tanker ships and will be upgraded with 5 new units for the transport of production from train 6.

Front end engineering activities to build a new LNG plant at Brass, with liquefaction capacity of 10 mmtonnes/y on two trains, are underway. Project sanction is expected in 2008, with start up expected in 2011. Approximately 50% of feed gas to this plant is expected to be secured from developing certain nearby fields.

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Several successful appraisal wells were drilled in the year: (a) in OML 118 offshore block (Eni’s interest 12.5%) with the Bonga North 2 well, drilled at a depth of 3,560 meters; (b) in OML 120 offshore block (Eni’s interest 40%) with the Oyo 2 Dir well, drilled at a depth of 1,700 meters; (c) in OPL 219 block (Eni’s interest 12.5%), with the Bolia 4 well drilled at a depth of 3,600 meters; and (d) in the OML 28 (Eni’s interest 5%) with the Kolo Creek 39 well.

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

North Sea

Eni’s operations in the North Sea area are conducted in Norway and the United Kingdom. In 2006, the North Sea accounted for 16% of Eni’s total worldwide production of hydrocarbons.

Norway Eni has been operating in Norway since 1965. Eni’s activities are conducted in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 138 KBOE/d in 2006.

Eni holds interests in 4 production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL018 containing mainly oil, which in 2006 accounted for 37% of Eni’s production in Norway. In 2006 initiatives were executed to support and optimize production, in particular two further stretches of pipes were laid that will start operations in 2007.

Eni holds interests in 6 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 accounted for 63% of Eni’s production in Norway. Drilling program of Kristin field is ongoing and, after this intervention, production is expected to reach 218 KBOE/d (18 net to Eni) in 2007.

Currently Eni is only performing exploration activities in the 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 aimed at its commercial development.

In February 2006, following an international bid procedure, Eni was awarded offshore Block 6607/11-122D (Eni’s interest 20%) in the Halten Terrace basin, near the Marulk discovery which is operated by Eni with 20% interest.

In March 2006, following an international bid procedure, Eni was awarded offshore Blocks 7124/6, 7125/4 and 7125/5 in the Prospecting License 393 (Eni’s interest 30%), covering a gross acreage of 525 square kilometers, in the Barents Sea. Exploration plans envisage the drilling of a well in the first three years of the license.

In September 2006, Eni purchased further interests in two exploration licenses off the coast of Norway: (i) in the Prospecting License 221 (Eni’s interest 30%) where the Victoria gas discovery is located, representing a technological challenge due to the high pressure and high temperature conditions of the reservoir; and (ii) in the Prospecting License 264 (Eni’s interest 40%) where the Hvitveis gas discovery is located.

In January 2007, following an international bid procedure, Eni was awarded offshore Block 6506/9-6507/7 (Eni’s interest 30%).

Ongoing development activities are focused primarily on hydrocarbon bearing structures located near the Kristin field (Eni’s interest 8.25%). Development of the Tyrihans field (Eni’s interest 6.23%) is expected to be profitable through synergies with the Kristin production facilities. In July, the development plan was sanctioned; relevant contracts for building infrastructure and production facilities are being awarded. Production is expected to start in 2009, in coincidence with the expected production decline of Kristin which will make spare capacity available to process production from Tyrihans.

Main discoveries for the year were: (a) in the Prospecting License 229 (Eni operator with a 65% interest), three appraisal wells of the Goliath discovery confirmed the presence of hydrocarbons at a depth between 1,000 and 1,850 meters; (b) in the Prospecting License 128 (Eni’s interest 11.5%), a gas formation was discovered at a depth of 3,000 meters; and (c) in the Prospecting License 134 (Eni’s interest 30%), an appraisal well of the Morvin discovery confirmed the presence of oil at a depth between 4,600 and 4,900 meters.

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 2006 Eni’s net production of hydrocarbons averaged 137 KBOE/d. Exploration and production activities in the United Kingdom are regulated by concession contracts.

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Eni holds interests in 12 production areas in the British section of the North Sea. The main fields are Elgin/Franklin (21.87%), the J-Block (33%), the Flotta Catchment Area (20%), Andrew (16.2%) and Farragon (30%) which in 2006 accounted for 57% of Eni’s production in the United Kingdom. In March 2006, production started at the offshore gas and condensate Glenelg field (Eni’s interest 8%), developed by means of the facilities of the nearby Elgin/Franklin production platform. Glenelg 2006 production has been 12 KBOE/d (1 net to Eni). Other actions in the year concerned optimization of producing fields, in particular MacCulloch, Elgin/Franklin and J-Block through the drilling of additional wells and work over actions for supporting production levels.

Eni holds interests in 5 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, which in 2006 accounted for 25% of Eni’s production in this country.

Eni holds interests 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 2006 accounted for 4% of Eni’s production in the United Kingdom. In 2006 maintenance and optimization actions were performed with the upgrade of the Ninian facility and the drilling of additional wells on Magnus.

The main project underway concerns the development of the reserves in the Blane field in Block 30/3a (Eni’s interest 18%). This project contemplates the drilling of 3 sub sea wells (2 production and 1 water injection) and a linkage to existing treatment facilities. Associated gas will be reinjected in the nearby Ula field reservoir. Start up is expected in the third quarter of 2007 with an initial flow of 12 KBOE/d (2.2 net to Eni).

Main discoveries for the year were in: (a) the P/011 permit in Block 30/06a (Eni’s interest 33%) in the central section of the North Sea, where an appraisal well was drilled at a depth between 4,500 and 5,100 meters confirming the presence of hydrocarbons; and (b) the P/672 permit in Block 30/02c (Eni’s interest 7%) in the central section of the North Sea, where a discovery of a natural gas and condensate bearing layer was made at a depth of 5,000 meters; this well has been linked to the production facilities of the nearby Jade field (Eni’s interest 7%).

Rest of the World

In 2006, Eni’s operations in the rest of the world accounted for 18% of its total worldwide production of hydrocarbons.

Australia Eni has been present in Australia since 2001. In 2006 Eni’s net production of oil and natural gas averaged 26 KBOE/d. Activities are focused on fields located in conventional offshore. 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 12.04%), after unitization with JPDA/02-12. Eni is operator with a 100% interest in permits WA-279 P and WA-313-P in the offshore Bonaparte basin, where the Blacktip and Penguin fields are located. In the exploration phase Eni is operator with a 67% interest of BlockWA-328-P and with a 100% interest of blocks TP-22, WA-280-P and WA-326-P. 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 June 2006, development started at the offshore Blacktip gas and liquids field (Eni’s interest 100%) located in the WA-279-P Block at a water depth of 50 meters in the Bonaparte basin, South of the Australian coast. This project envisages the installation of a production platform approximately 100 kilometers from the mainland and construction of an onshore treatment plant with a capacity of 46 BCF/y. Start up is expected in January 2009. Under a 25-year agreement signed with the Darwin Power & Water Utility Co, a total amount of 706 BCF of natural gas is expected to be supplied with an option for further volume increases.

In February 2006, the first shipment of LNG was delivered to two Japanese operators from the Darwin liquefaction plant with a capacity of 3.5 mmtonnes/y of LNG (equivalent to approximately 173 BCF/y of natural gas). This plant is linked by means of a 500-kilometer long pipeline to the Bayu Undan gas and condensates field located at a water depth of 80 meters in permits JPDA 03-12 and JPDA 03-13 within the cooperation zone between Australia and East Timor (Eni’s interest 12.04%).

Exploration yielded positive results in the offshore Block WA-25-L with the Woollybutt-5 appraisal well confirmed the presence of oil at a depth of 2,865 meters.

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

Brazil In January 2006, following an international bid procedure, Eni was awarded a six-year exploration license in Block BM Cal-14, acting as operator. Gross acreage extends over approximately 700 square kilometers in the deep waters of the Camamu-Almada basin.

In November 2006, following an international bid, Eni was awarded offshore Block S-M-857 (Eni’s interest 100%), covering a gross acreage of 700 square kilometers, in the deep waters of the Santos basin. Formal assignation of this block has not yet been completed.

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Croatia Eni has been present in Croatia since 1999. In 2006 Eni’s net production of natural gas averaged 64 mmCF/d. Activities are deployed in the Adriatic offshore facing the city of Pula. Exploration and production activities in Croatia are regulated by PSA.

Ivana C/K platforms and Ika and Ida fields started production as part of the development of the natural gas reserves of the Ivana concession (Eni’s interest 50%). Production from these fields is gathered at the Ivana K platform from which is sent to the Garibaldi K platform to be sold on the Italian market, through a 67-kilometer long pipeline. Production from these four fields is currently flowing at 152 mmCF/d (49 net to Eni). At the end of 2006, production at the Katarina field started by means of two platforms linked to existing transport facilities.

In the offshore Ivana concession the Ana 1 and Vesna 1 discovery wells identified the presence of natural gas at a depth between 650 and 1,200 meters.

East Timor In May 2006 following an international bid procedure Eni was awarded the operatorship of five exploration licenses (Eni’s interest 100%) covering contract areas A, B, C, E and H with a gross acreage of about 12,224 square kilometers located in the deep offshore between the Timor island and the international cooperation zone between East Timor and Australia. Relevant Production Sharing contracts were signed.

India Following an international bid procedure Eni obtained an exploration license as operator in Block RJ-ONN-2003/1 (Eni’s interest 34%) and Block AN-DWN-2003/2 (Eni’s interest 40%) located in onshore in Rajasthan in the North-West of India and in the Indian Ocean, near the Andaman Islands, respectively. The exploration program for Block RJ-ONN-2003/1 provides for the drilling of 4 wells in the first 4 years of the license. Any hydrocarbons discovered will be sold locally. The exploration program for Block AN-DWN-2003/2 provides for the drilling of 3 wells in the first 4 years of the license. The development of any reserves found provides for the installation of an FPSO unit for liquid production and of facilities for gas treatment.

In February 2007 Eni concluded an agreement with a partner whereby interests in India and Congo were exchanged. Following this transaction Eni acquired a 34% interest in block MN-DWN-2002/1 with high mineral potential in the Indian offshore at a water depth of 2,000 meters with a total acreage of 10,000 square kilometers and will give to its partner a 20% interest in the Mer Très Profonde Nord permit (Eni operator with a 40% interest) offshore Congo.

Indonesia Eni has been present in Indonesia since 2000. Eni’s production in 2006 amounted to 19 KBOE/d. Production is concentrated in the Western offshore and onshore of Borneo and offshore Sumatra. Exploration and production activities in Indonesia are regulated by PSA.

Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%). 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. Activities are underway for mitigating the natural decline of production by means of infilling wells.

Eni holds interest in 11 exploration blocks, 6 as operator with interests ranging from 20% to 100%. An exploration campaign is underway in the Tarakan basin offshore Borneo. In May 2007, Eni successfully completed drilling of the Tulip 1 explorative well (Eni’s interest 100%), located in water depths of up to 800 meters Northeast of Kalimantan Island. This well revealed the presence of significant oil and gas deposits.

In the same area, Eni (operator with a 66.25% interest) and a partner have also successfully completed an appraisal test of the Aster field, previously discovered by the two companies. The test has shown oil flowing at a maximum rate of over 5 KBBL/d. Eni plans to submit a development plan for the Aster field and start appraising the Tulip discovery. Eni will also assess potential synergies that might support a joint development of the two discoveries.

Iran Eni has been present in Iran since 1957. In 2006 production net to Eni averaged 29 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 operated by Eni are South Pars phases 4 and 5 (Eni’s interest 60%) in the offshore of the Persian Gulf and Darquain (Eni’s interest 60%) located onshore which accounted for 89% of Eni’s production in Iran in 2006. In 2006 the onshore gas treatment plant of South Pars was completed with a current production of 609 BCF/y of natural gas, 1 mmtonnes/y of LPG and 30 mmBBL/y of condensates. Production platforms are linked to the Assaluyeh treatment center by means of two 105-kilometer long pipelines. Eni also holds interests in the Dorood (45%) and Balal (45%) oil fields.

The development activities in 2006 concerned the second development phase of the Darquain field mainly related to the drilling of additional wells, the increase of the existing treatment capacity and the injection of gas in the field. These actions aim at increasing production from the present 50 KBBL/d to over 160 KBBL/d (14 net to Eni).

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Kazakhstan Eni has been present in Kazakhstan since 1992. Eni is the single operator of the North Caspian Sea PSA with a participating interest equal to 18.52%. Such contract regulates activity in the relevant contractual area where the Kashagan field was discovered in year 2000. Management believes this field to contain large amount of hydrocarbons. The development plan of this field was sanctioned in February 2004, entailing a three-phase development scheme which includes partial gas re-injection in the reservoir to support the recovery factor of the oil.

The first development phase is progressing and is leveraging on the use of the most advanced techniques in order to cope with high pressures in the reservoir, high concentrations of hydrogen sulfide in the hydrocarbons and harsh environmental conditions in the offshore of the Caspian Sea. By the end of 2006, the total amount of contracts awarded stood at $10.6 billion. Drilling and completion activities of development wells have been progressing from the two artificial islands already built and where three rigs, two of which being of the most advanced class, are installed. Three development wells were completed in 2006 yielding high productivity rates during the test phase.

Production start up is currently scheduled for the third quarter of 2010, as compared to the previous forecast indicating a start up in 2008. This re-scheduling is also due to studies performed by the Operator aimed at identifying measures to enhance operability and safety standards of the facilities. These studies, which were completed by year-end, have confirmed the original development concept and identified scope for enhancement to the design of the offshore facilities. These enhancements will be included in the development plan and implemented. The capital expenditures necessary to arrive at the 300 KBBL/d production target for this phase of the project, are estimated to be $19 billion. The increase over the approved budget of $10.3 billion (real terms 2007) is driven by: (i) the cost pressure the oil industry is facing worldwide (i.e. the cost escalation of materials and service and the negative impact of changes to the exchange rate); (ii) an original underestimation of the costs to conduct offshore operations in the North Caspian Sea due to the absence of a reliable benchmark for a frontier project having the complexity, the technical challenges and the environmental constraints of Kashagan; and (iii) the enhancements to the original layout of the offshore facilities. The high productivity tested on the first three development wells, as well as other data gathered since the beginning of the project, justify expectations for a full field production plateau of 1.5 mmBBL/d, representing a 25% increase above the original plateau as presented in the sanctioned development plan.

The capital expenditures indicated above do not include the costs related to the infrastructures needed for exporting the production to international markets, for which various options are under scrutiny 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; 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’s holds an interest of 5% corresponding to the right to transport 50 KBBL/d) and the construction of a pipeline to bypass the Turkish Straits of the Bosphorus and Dardanelles, enabling the delivery of the oil produced in the Caspian region into the Ceyhan commercial hub on the Mediterranean coast (see Turkey below).

Evaluation activities of the discoveries made in the contract area of the North Caspian Sea PSA made some good progress. A first appraisal well on the Kairan discovery was successfully drilled. Drilling of a second appraisal well on the Kalamkas discovery yielded results that underline the good productivity of the reservoir and indicate that the size of the discovery is larger than previously estimated.

At the Karachaganak field (Eni co-operator with a 32.5% participating interest), the good well productivity and the high plant performance allowed to produce an average of 64 KBBL/d of liquids (of which some 44.3 KBBL/d were transported to the Western markets via the CPC pipeline and the Atyrau-Samara) and sell approximately 78 BCF/y of natural gas, net to Eni, for a total of 103 KBOE/d, net to Eni.

The main activities carried out in 2006 were: (i) the sanction of an expansion in the processing capacity (a fourth train) which will enable to increase the volumes of stabilized liquids exported to Western markets; and (ii) the continuation of those activities (mainly drilling of additional wells) which are necessary to maintain the production plateau.

Studies are ongoing to implement a further development phase of the Karachaganak field, Phase 3, aimed at producing additional volumes of gas and associated liquids. In this context, on June 1, 2007, the Karachaganak Petroleum Operating BV (KPO) and KazRosGaz, a joint company established by KazMunaiGaz and Gazprom, signed a gas sale contract. According to the terms of this agreement, which is subject to approvals of the Karachaganak Shareholders, the consortium will deliver, from 2012, about 16 BCM/y (565 BCF/y) of raw gas to the Orenburg plant, in Russia, where it will be further processed and sweetened. This agreement creates the conditions for the start up of Phase 3 of the project.

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In the medium-term, Eni’s production in Kazakhstan is expected to increase due to the contribution of the incremental gas volumes produced at Karachaganak and the start up of Kashagan.

Mozambique In March 2006, following an international bid tender, Eni obtained the exploration license for Area 4, located in the deep offshore of the Rovum Basin 2,000 kilometers North of Maputo. The block covers an area of 17,646 square kilometers in an unexplored geological basin which we believe has significant mineral potential, according to surveys performed.

Pakistan Eni has been present in Pakistan since 2000. In 2006 production net to Eni averaged 50 KBOE/d. Eni’s main permits are Bhit (Eni operator wit a 40% interest), Sawan (23.68%) and Zamzama (17.75%), which in 2006 accounted for 86% of Eni’s production in Pakistan.

In February 2006 following an international bid procedure, Eni was awarded the operatorship of four exploration licenses relating to Block Rjar/Mithi - zone I and Thar/Umarkot - zone III. These blocks are located in the East Sindh near the border with India and cover a gross area of about 9,900 square kilometers.

In March 2006, an expansion plan of the Bhit and Badhra operated permits was sanctioned, envisaging the construction of a third train for increasing treatment capacity of the Bhit plant also enabling to process Badhra field gas production. In the Zamzama field construction of a new treatment plant is underway.

Up to June 2007, three gas discoveries were made in: (i) the exploration permit Gambat (Eni’s interest 30%) with the Tajial 1 exploration well, at a depth of 3,845 meters; (ii) the production permit Kadanwari (Eni operator with a 18.42% interest) with the Kadanwari 18 well, at a depth of 3,400 meters in a rock formation independent from the main field; and (iii) the Latif field (Eni’s interst 33.3%) with the Latif 1 exploration well, at a depth of 3,520 meters. Eni plans to develop these discoveries leveraging on the existing facilities in place.

Saudi Arabia Eni has been present in Saudi Arabia since 2004. Ongoing activities concern exploration of the C area in order to discover and develop gas reserves. This license covering 51,687 square kilometers (25,844 net to Eni) 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 4 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 first commitment well is underway.

Turkey The construction license for the Samsun-Ceyhan pipeline was granted to the Turkish company Çalik Enerji, partner of Eni in this initiative with a 50% stake in June 2006. The pipeline, the engineering activities of which started in second half of 2006, will allow to bypass the Turkish Straits of Bosphorus and Dardanelles, thus enabling the oil produced in the Caspian region to be delivered to the Ceyhan commercial hub, located on the Mediterranean coast, in a more efficient and environmentally friendly fashion. This new infrastructure, with a length of 550 kilometers, will have an initial transportation capacity equal to 1 mmBBL/d of oil, expandable up to 1.5 mmBBL/d.

United States Eni has been present in the United States since 1966. In 2006 Eni’s oil production averaged 32 KBOE/d. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and onshore and offshore Alaska. Exploration and production activities in the United States are regulated by concessions.

Eni holds interests in 24 production blocks in the Gulf of Mexico. The main fields are Allegheny (Eni operator with an 86% interest), Medusa (Eni’s interest 22%), Europa (Eni’s interest 28%), King Kong (Eni operator with a 49% interest), East Breaks (Eni operator with an 84% interest) and Morphet (Eni operator with an 84% interest). These fields accounted for 81% of Eni’s 2006 production in the country. In 2006 the Allegheny South (Eni’s interest 100%) and North Black Widow (Eni’s interest 25.19%) fields have been started-up.

Eni’s activities in Alaska are currently in the exploration and development phase. In November 2006, Eni started an exploration campaign in the onshore Rock Flour area (Eni’s interest 100%). The approved plan provides for the drilling of three wells.

In March 2006, following an international bid procedure, Eni was awarded 11 exploration blocks near Rock Flour.

Eni signed an agreement with a partner for a swap of interests in 64 exploration blocks (Eni’s interest 60%) located in the Beaufort Sea, offshore North Alaska. Based on this agreement, Eni is entitled to 140 exploration blocks (50% of which operated). Exploration plans provide for 3D seismic surveys and drilling of an exploration well by 2010.

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In January 2006, the development plan of the offshore Oooguruk field in the Beaufort Sea started. Production is expected to start at the end of 2007 with production peaking at 17 KBOE/d (over 5 net to Eni) in 2010. Drilling activities are underway in Nikaitchuq field (Eni’s interest 100%), located in the Beaufort Sea.

Main discoveries for the year were: (a) in Mississippi Canyon Block 546 (Eni’s interest 50%), the Longhorn appraisal well confirmed the presence of natural gas at a depth of about 3,900 meters; and (b) in Mississippi Canyon Block 502 (Eni’s interest 100%), the Longhorn North discovery well showed the presence of natural gas at a depth of 3,400 meters. A feasibility study to develop this discovery is underway.

Management expects production in the United States to grow significantly from current levels due to the contribution of recently acquired assets in the Gulf of Mexico and Alaska and ongoing development activities.

Venezuela Eni has been present in Venezuela since 1998. In January 2006, following an international bid procedure, Eni was awarded a thirty year long exploration license for the Cardon IV Block (Eni’s interest 50%) in joint venture with an international oil company. This Block is part of the Rafael Urdaneta project for the development of natural gas reserves in an area of about 30,000 square kilometers in the Gulf of Venezuela.

With effective date April 1, 2006, the Venezuelan State oil company Petróleos de Venezuela SA (PDVSA) unilaterally terminated the Operating Service Agreement (OSA) governing activities at the Dación oil field where Eni acted as a contractor, holding a 100% working interest. As a consequence, starting on the same day, operations at the Dación oil field are conducted by PDVSA. Eni proposed to PDVSA to agree on terms in order to recover the fair value of its Dación assets. In the lack of any agreement between the parties, in November 2006, Eni commenced an arbitration proceeding before an International Centre for Settlement of Investment Disputes (ICSID) Tribunal (i.e. a tribunal acting under the auspices of the ICSID Convention and being competent pursuant to the Netherlands-Venezuela bilateral investments treaty) to claim its rights. Despite this action, Eni would continue to consider a negotiated solution with PDVSA to obtain a fair compensation for its assets. Based on the opinion of its legal consultants, Eni believes to be entitled to a compensation for such expropriation in an amount equal to the market value of the OSA before the expropriation took place. The market value of the OSA depends upon its expected profits. In accordance with established international practice, Eni has calculated the OSA’s market value using the discounted cash flow method, based on Eni’s interest in the expected future hydrocarbon production and associated capital expenditures and operating costs, and applying to the projected cash flow a discount rate reflecting Eni’s cost of capital as well as the specific risk of concerned activities. Independent evaluations carried out by a primary petroleum consulting firm fully support Eni’s internal evaluation. The estimated net present value of Eni’s interest in the Dación field, as calculated by Eni, would not be lower than the net book value of the Dación assets which consequently have not been impaired. In accordance with the ICSID Convention, a judgment by the ICSID Tribunal awarding compensation to Eni would be binding upon the parties and immediately enforceable as if it were a final judgment of a court of each of the States that have ratified the ICSID Convention. The ICSID Convention was ratified in 143 States. Accordingly, if Venezuela fails to comply with the award and to pay the compensation, Eni could take steps to enforce the award against commercial assets of the Venezuelan Government almost anywhere those may be located (subject to national law provisions on sovereign immunity). In 2005 and in the first quarter of 2006, oil production from the Dación field averaged approximately 60 KBBL/d and booked reserves at December 31, 2005 amounted to 175 mmBBL.

On February 26, 2007, the President of Venezuela enacted a decree providing for the transformation of certain strategic partnerships operating in the petroleum region of Orinoco (Faja) and certain agreements to conduct risk shared exploration activities into a regime of "empresa mixta" within six months from publication of said decree. Under the new regime, a company incorporated under the law of Venezuela is expected to be entitled to relevant mineral rights and to conduct petroleum operations. A stake of at least 60% in the capital of such company is expected to be held by an affiliate of PDVSA, preferably Corporación Venezuelana de Petróleo. Such decree could impact Eni’s activities in Venezuela, as Eni’s subsidiary Eni Venezuela BV holds a 26% stake in a joint venture in the Gulf of Paria West Block, located in the Orinoco delta. This joint venture is currently developing the Corocoro field with expected start up in 2007.

 

Capital Expenditure

See "Item 5 – Liquidity and Capital Resources – Capital Expenditure 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 provided for the separation of storage from other activities in the field of natural gas.

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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 2006, the share of storage capacity used by third parties was 46%. 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 an insignificant value, passed to 42%.

Storage

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
Available capacity:                        
- modulation and mineral  

(BCM)

 

7.1

 

7.1

 

7.5

 

7.5

 

8.4

  . share utilized by Eni  

(%)

 

66

 

53

 

47

 

44

 

54

- strategic  

(BCM)

 

5.1

 

5.1

 

5.1

 

5.1

 

5.1

Total customers  

(No.)

 

20

 

30

 

39

 

44

 

38

. modulation and upstream storage customers  

(No.)

 

14

 

24

 

29

 

35

 

38

 
 
 
 
 

 

Gas & Power

Eni Gas & Power segment is engaged in all phases of the gas business: supply, transport, distribution and marketing, resulting in a fully integrated business model. A significant installed power generation capacity enables Eni to extract further value from gas, diversifying its commercial outlets.

Eni’s strategy in its Gas & Power segment is to increase natural gas sales in the main European markets, safeguard its domestic natural gas business, and effectively manage regulated businesses (transport and distribution activities in Italy).

Management expects European natural gas demand to increase steadily in the future, resulting in a cumulative increase of around 45% by 2020 (2.4% per annum). This trend, coupled with an expected decline in Europe’s gas production due to mature field declines, will make Europe increasingly reliant on gas imports to fulfil its gas needs. Against this backdrop, management plans to grow natural gas sales leveraging on Eni’s gas availability under long-term supply contracts and equity gas, access to infrastructure, long-term relationships with key producing countries, market knowledge and a wide portfolio of clients. Eni intends to strengthen its presence in markets where its presence is already established – such as the Iberian Peninsula, Germany and Turkey – and to develop sales in markets with significant growth and profitability prospects (in particular France and the United Kingdom).

In Italy, in an increasingly competitive market, Eni intends to safeguard selling margins and sales volumes by leveraging on the expected growth of gas demand, maximizing the value of the gas chain by focusing in particular on the most profitable clients, deploying a commercial offer tailored on client needs in terms of pricing and quality of services, and boosted by the expected development of the combined offer of gas and electricity ("dual offer").

In the medium-term, Eni plans to increase worldwide sales targeting a volume of 105 BCM by 2010, corresponding to a 2.5% average growth rate over the 2007-2010 four-year period.

Eni also intends to increase efficiency and effectiveness of its operations, particularly in the regulated business and to develop marketing of LNG aiming also at monetizing equity reserves.

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.

 

Demand for Natural Gas in Italy

In 2006 natural gas demand in Italy totaled 84.4 BCM (down 2.2 % from 2005). In 2006, about 13% of natural gas requirements were met through domestic production, while imports covered 87%. Eni expects natural gas consumption in Italy to increase with a compound average growth rate of about 2.5% over the next ten years, hitting approximately 106 BCM in 2015, mainly driven by an increased use in power generation, the demand growth of which is expected to outpace demand growth in other sectors, such as large industrial users, residential space heating in households and services, commercial and small businesses needs. Expected increased consumption in the electricity generation sector derives from the significant advantages of the use of natural gas in firing combined cycle plants as compared to other fuels, due to its lower investment cost, higher yields and reduced polluting emissions.

_______________

(3)   Two of these are not yet operational.

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Supply of natural gas

In 2006 Eni’s Gas & Power segment purchased 89.27 BCM of natural gas, with a 6.71 BCM increase over 2005, or 8.1%. Natural gas volumes purchased outside Italy (79.06 BCM) represented 89% of total purchases made by fully consolidated subsidiaries (87% in 2005) with a 7.23 BCM increase from 2005 (up 10.1%).

Major increases in purchased volumes regarded: (i) Libya, reflecting higher volumes of gas from Libyan fields delivered to Italy via the GreenStream gasline (up 2.79 BCM); (ii) the Netherlands (up 1.99 BCM); (iii) volumes purchased in Russia to be sold on the Turkish market (up 1.21 BCM); and (iv) purchases of LNG (up 1.01 BCM). In addition, supplies from Croatia increased (up 0.43 BCM) due to the ramp-up of new production from Eni-operated natural gas fields in the Adriatic offshore.

Main declines concerned purchases from Algeria (down 0.74 BCM) and extra Europe supplies. Volumes purchased in Italy from both Eni’s Exploration & Production segment and third parties (10.21 BCM) declined by 0.52 BCM, down 4.8%, from 2005 due to a production decline of Eni’s natural gas fields.

In 2006, natural gas volumes input to the storage deposits owned by Stoccaggi Gas in Italy and Gaz de France in the French territory and in Austria were 3.01 BCM, compared to net offtakes of 0.84 BCM in 2005.

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

Natural gas supplies

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
   

(BCM)

Italy  

12.67

   

12.16

   

11.30

   

10.73

   

10.21

 
Russia for Italy  

18.62

   

18.92

   

20.62

   

21.03

   

21.30

 
Russia for Turkey        

0.63

   

1.60

   

2.47

   

3.68

 
Algeria  

16.35

   

16.53

   

18.86

   

19.58

   

18.84

 
the Netherlands  

7.55

   

7.41

   

8.45

   

8.29

   

10.28

 
Norway  

4.83

   

5.44

   

5.74

   

5.78

   

5.92

 
Hungary  

3.05

   

3.56

   

3.56

   

3.63

   

3.28

 
Libya              

0.55

   

3.84

   

6.63

 
Croatia  

0.31

   

0.65

   

0.35

   

0.43

   

0.86

 
the United Kingdom  

1.48

   

1.98

   

1.76

   

2.28

   

2.50

 
Algeria (LNG)  

1.92

   

1.98

   

1.27

   

1.45

   

1.58

 
Others (LNG)  

0.3

   

0.72

   

0.70

   

0.69

   

1.57

 
Other supplies Europe  

0.03

   

0.04

   

0.12

   

1.18

   

1.85

 
Outside Europe  

0.96

   

1.14

   

1.21

   

1.18

   

0.77

 
Outside Italy  

55.40

   

59.00

   

64.79

   

71.83

   

79.06

 
Total supplies  

68.07

   

71.16

   

76.09

   

82.56

   

89.27

 
Withdrawals from (input to) storage  

(1.43

)  

0.84

   

0.93

   

0.84

   

(3.01

)
Network losses and measurement differences  

(0.50

)  

(0.61

)  

(0.53

)  

(0.78

)  

(0.50

)
Available for sale of Eni’s own companies  

66.14

   

71.39

   

76.49

   

82.62

   

85.76

 
Available for sale of Eni’s affiliates  

2.40

   

6.94

   

5.84

   

7.08

   

7.65

 
Total available for sale  

68.54

   

78.33

   

82.33

   

89.70

   

93.41

 
 
 
 
 
 

In order to meet the medium and long-term demand for natural gas, in particular in the Italian market, Eni entered into long-term purchase contracts with producing countries. Following the strategic agreement with Gazprom signed on November 14, 2006, effective from February 1, 2007 (see below), Eni extended the duration of its gas supply contracts with Gazprom until 2035, bringing the residual average life of its supply portfolio to approximately 23 years. Existing contracts, which in general contain take-or-pay clauses, will ensure a total of approximately 62.4 BCM/y (Russia 23.5, Algeria 21.5, the Netherlands 9.8, Norway 6 and Nigeria LNG 1.6) of natural gas by 2010. Despite the fact that an increasing portion of natural gas volumes purchased under said contracts will 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 infrastructure, and the evolution of the Italian regulations for 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 2006 Eni purchases under its take-or-pay contracts were about 8 BCM more than its minimum off-take obligation, this figure refers to off-take in respect of contractual year (October to end of September, rather than January to end of December, for a sizeable part of Eni Gas & Power long-term supply contracts).

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Agreement between Eni and Gazprom

On November 14, 2006, Eni and Gazprom signed a broad strategic agreement. This agreement sets up an international alliance enabling the two companies to launch joint projects in the mid and downstream gas, in the upstream and technological cooperation. This agreement is a major step towards the security of energy supply to Italy.

(i)   Midstream and downstream gas The duration of Russian gas supply contracts to Eni is extended until 2035, confirming that Eni is presently the world’s single largest customer of Gazprom. Through this agreement, starting from 2007, Gazprom is expected to sell increasing volumes of gas directly in the Italian market, building up to some 3 BCM in 2010 and to maintain such level in subsequent years for the duration of said long-term supply contract. Volumes expected to be sold by Gazprom will be subtracted from volumes supplied to Eni under the fourth long-term supply contract. In 2007, Eni expects to reduce its supplies from Gazprom by 1 BCM, and Gazprom to sell approximately 1 BCM under this scheme.
(ii)   Upstream Eni and Gazprom have identified major projects (companies and assets) in Russia and outside Russia that will be jointly pursued by the two partners.
Eni and Gazprom have agreed to work with each other on an exclusive basis on these projects, which are expected to be finalized by the end of 2007.
(iii)   Technological cooperation and development Eni and Gazprom will sign specific agreements in the following areas:
    -   long-distance gas transportation. In this sector Eni and Snam Rete Gas will provide their know-how and expertise, including proprietary transport technology TAP (high pressure transmission) for the development of Russia’s gas transportation system;
    -   evelopment of LNG projects for the global gas market.

 

Marketing

Natural Gas Sales for the Year

In 2006 Eni’s worldwide gas sales (97.48 BCM, including own consumption, Eni’s share of sales of affiliates and upstream sales) were up 3.27 BCM from 2005, or approximately 4%, mainly reflecting higher sales in the rest of Europe (up 4.9 BCM, up approximately 16%), higher supplies of natural gas (up 0.59 BCM, or 10.6%) to Eni’s wholly-owned subsidiary EniPower for power generation, offset in part by lower sales by fully consolidated subsidiaries in Italy (down 1.53 BCM, or 2.9%).

In an increasingly competitive market, natural gas sales of fully consolidated subsidiaries in Italy (50.94 BCM) declined by 1.53 BCM from 2005, due mainly to lower sales in the fourth quarter in connection with mild weather conditions.

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) the retail market which is composed of residential and commercial clients (households, commercial users, hospital, schools, etc.), and small businesses located in urban centers supplied by wholesalers through low pressure distribution networks; and (iii) wholesalers, mainly local selling companies and distributors of natural gas for automotive use purchasing natural gas to sell it to final clients.

In 2006, major declines were registered in the power generation segment (down 0.93 BCM), in sales to wholesalers (down 0.51 BCM) and residential and commercial users (down 0.4 BCM). These declines were offset in part by higher sales to the industrial sector (up 0.26 BCM).

Own consumption4 was 6.13 BCM, up 0.59 BCM or 10.6%, reflecting primarily higher supplies to EniPower due to the coming onstream of new generation capacity.

In 2006 natural gas sales of fully consolidated subsidiaries in the rest of Europe increased by 4.49 BCM to 27.93, or 19.2%, reflecting a growth in: (i) sales under long-term supply contracts to Italian importers (up 2.57 BCM) for the progressive reaching of full supplies from the Libyan fields operated by Eni; (ii) sales to the Turkish market (up 1.22 BCM); (iii) sales to Germany and Austria (up 0.84 BCM), mainly due to higher volumes to industrial operators and wholesalers; and (iv) sales to France (up 0.42 BCM) relating to higher volumes to industrial operators. These increases were partly offset by a decrease in sales to Hungary (down 0.29 BCM) and Northern Europe (down 0.1 BCM).

______________

(4)   In accordance with Article 19, paragraph 4 of Legislative Decree No. 164/2000, the volumes of natural gas consumed in operations by a company or its subsidiaries are excluded from the calculation of ceilings for sales to end customers and from volumes input into the Italian network to be sold in Italy.

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Sales of natural gas by Eni’s affiliates in the rest of Europe, net to Eni and net of Eni’s supplies, amounted to 6.88 BCM, up 0.4 BCM, with Unión Fenosa Gas posting the major increase, and concerned: (i) GVS (Eni’s interest 50%) with 2.94 BCM; (ii) Unión Fenosa Gas (Eni’s interest 50%) with 2.17 BCM; and (iii) Galp Energia (Eni’s interest 33.34%) with 1.65 BCM.

Unión Fenosa Gas sold also 0.45 BCM on international markets, in particular Japan (0.27 BCM) and South Korea (0.09 BCM), as new market opportunities were captured.

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

Natural gas sales

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
   

(BCM)

Italy (*)  

50.43

 

50.86

 

50.08

 

52.47

 

50.94

Wholesalers (distribution companies)  

17.02

 

15.36

 

13.87

 

12.05

 

11.54

Gas release          

0.54

 

1.95

 

2.00

End customers  

33.41

 

35.50

 

35.67

 

38.47

 

37.40

Industries  

14.43

 

13.17

 

12.39

 

13.07

 

13.33

Power generation  

12.48

 

15.03

 

15.92

 

17.6

 

16.67

Residential  

6.50

 

7.30

 

7.36

 

7.80

 

7.40

Own consumption (*)  

2.02

 

1.90

 

3.70

 

5.54

 

6.13

Rest of Europe (*)  

12.77

 

17.54

 

21.54

 

23.44

 

27.93

Outside Europe  

0.92

 

1.09

 

1.17

 

1.17

 

0.76

Total sales to third parties and own consumption  

66.14

 

71.39

 

76.49

 

82.62

 

85.76

Sales of natural gas of Eni’s affiliates (net to Eni)  

2.40

 

6.94

 

5.84

 

7.08

 

7.65

Italy (*)              

0.07

 

0.02

Rest of Europe (*)  

1.93

 

6.23

 

5.30

 

6.47

 

6.88

Outside Europe  

0.47

 

0.71

 

0.54

 

0.54

 

0.75

Total sales and own consumption of G&P  

68.54

 

78.33

 

82.33

 

89.70

 

93.41

Upstream in Europe (a)  

4.49

 

5.03

 

4.70

 

4.51

 

4.07

Worldwide natural gas sales  

73.03

 

83.36

 

87.03

 

94.21

 

97.48

Natural gas sales in Europe  

71.64

 

81.56

 

85.32

 

92.50

 

95.97

G&P in Europe (*)  

67.15

 

76.53

 

80.62

 

87.99

 

91.90

Upstream in Europe (a)  

4.49

 

5.03

 

4.70

 

4.51

 

4.07

 
 
 
 
 

(*)   Market sectors denoted with an asterisk are included within "G&P in Europe".
(a)   Does not include Eni’s share of sales made by Nigeria LNG (Eni’s share 10.4%) in Europe amounting to 1.30, 1.31 and 1.55 BCM in 2004, 2005 and 2006, respectively.

 

Planned Actions and Sales Target

In the medium-term Eni plans to grow its sales volumes of natural gas in European markets 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 the access to a wide-reaching transport network, regasification terminals and logistic assets, a large portfolio of clients and market knowledge.

 

(i) Italy

In the medium-term management will attain compliance with market limits imposed by sector-specific regulation, in terms of both volumes intake into the national network and sales volumes, through an optimal allocation of Eni’s gas availability 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 domestic demand. Eni targets sales volumes of at least 50 BCM in 2010. This target takes account of the expected increase in competitive pressure due to new supplies coming on stream on the Italian gas market in view of the implementation of ongoing upgrading plans of the import infrastructure to Italy.

In order to support sales in Italy, Eni intends to implement a marketing policy more focused on value creation for its clients than in previous years, leveraging on its established know-how on pricing, personalization of services, and brand awareness. In future years, Eni’s marketing effort will be supported by developing an integrated offer of gas and electricity ("dual offer"), targeting mainly the middle and retail markets. The dual offer is expected to achieve significant synergies from the integration of processes to acquire and manage clients.

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Eni will devote particular attention to retain clients and increase their number in the retail market. At the end of 2006 Eni had 6.5 million of retailing clients, mainly located in the most important urban centers in Italy. Eni intends to strengthen customer loyalty in this market segment through value creation in terms of excellence of the service offered and the development of the dual offer. At the same time, Eni expects to preserve its selling margins by means of reducing the cost to serve leveraging on the rationalization of its contact channels, streamlining administrative processes and exploiting economies of scale.

In addition Eni plans to support sales to the Italian retail market leveraging on the development of regional alliances with local partners as in the case of the project described below.

Toscana project

On January 24, 2006, Eni, Italgas (Eni’s interest 100%) and the local authorities partners of Fiorentina Gas SpA (Eni’s interest 51.03%) and Toscana Gas SpA (Eni’s interest 46.1%) signed a framework agreement for developing an alliance in the field of natural gas distribution and sale in the Toscana Region.

As a part of the agreement, Toscana Energia SpA (Eni’s interest 48.72%) was established upon contribution in-kind of the partners’ stakes in the distribution companies Fiorentina Gas and Toscana Gas. The local authorities partners of Toscana Energia SpA hold the responsibility for strategic decisions and control, while Eni maintains operating and management responsibilities, being the industrial partner of the initiative. In addition, this agreement provides for Fiorentina Gas Clienti SpA (Eni’s interest 100%) to be merged into Toscana Gas Clienti SpA (Eni’s interest 46.1%, Tuscan municipalities 53.9%), resulting in the establishment of a regional selling company under Eni’s control (79.22%), re-named Toscana Energia Clienti and boasting 600,000 clients and sale volumes of 1.1 BCM/y in 147 Tuscan municipalities. The Italian Antitrust Authority authorized this transaction on July 20, 2006. The merger deed was defined on February 22, 2007, effective from March 1, 2007.

 

(ii) European Markets

France Eni sells natural gas to industrial clients and wholesalers. In 2006, Eni started direct sales of natural gas in the French market with a new branch in Paris. New industrial and wholesaler clients were acquired; sales for the year hit the 1 BCM level. Supplies to the French company EDF ramped up, in execution of the long-term supply contract signed in July 2005.

Eni is pursuing an aggressive marketing policy to gain market share, in particular in the segment of small businesses which presents good profitability and development perspectives. In the medium-term, Eni expects to increase its current 1.1 BCM sales level at a 47% annual average growth rate, compared to an expected 3% average growth rate of market consumption, targeting volumes of approximately 5 BCM in 2010, equal to a 9% market share.

Germany Eni is present on the German natural gas market through its affiliate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 6.4 BCM in 2006, and with a direct commercial structure. In the medium-term, Eni plans to significantly increase its sales to the business segment, leveraging on the pursuit of new opportunities arising from the ongoing liberalization process and new marketing initiatives. In 2006, Eni began to supply the German company Wingas under a long-term contract, envisaging 1.2 BCM/y of natural gas. The gas is delivered at Eynatten at the German-Belgian border. The medium-term objective is to sell more than 7.5 BCM in 2010, equal to a 7% market share.

Iberian Peninsula

Management expects gas demand growth in the Iberian Peninsula to outpace the average European demand growth.

Portugal Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 5 BCM in 2006 (1.65 BCM being Eni’s share). In the medium-term, Galp’s sales are expected to grow at an 8% average rate, targeting 6.3 BCM (2.1 Eni’s share) in 2010.

On March 29, 2006, an eight-year agreement among Galp partners became effective addressing the joint management of the company. Galp partners include Eni, Amorim Energia (a privately held Portuguese company in which Sonangol, the national oil company of Angola, holds a minority stake), Rede Electrica Nacional (REN), and Caixa Geral de Depositos (a primary Portuguese financial institution). On September 26, 2006, in accordance with the agreement, Galp’s regulated activities comprising a high pressure network, storage sites and a regasification terminal located in Sines were spun off and divested to REN. REN divested its shareholding in Galp to Amorim Energia, effective on October 18, 2006. On October 24, 2006, the Portuguese State divested part of its stake in Galp through an IPO. At the same time, Galp shares were registered on the national Portuguese stock exchange. The shareholders of Galp post-IPO are: Eni (33.34%), Amorim Energia (33.34%), the Portuguese State (7.00%), Iberdrola (4%), Caixa (1%) and Setgas (0.04%); floating shares represent 21.28% of the share capital.

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Spain Eni operates in the Spanish gas market through Unión Fenosa Gas (Eni’s interest 50%) engaged in natural gas supply and sale to final users and to power generation utilities. In 2006 gas sales of Unión Fenosa Gas in Europe amounted to 4.34 BCM (2.17 BCM Eni’s share). Unión Fenosa Gas is engaged in LNG through an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and through a 7.36% interest in a liquefaction plant in Oman, completed in 2005; in addition, it holds interests in the Sagunto (Valencia) and el Ferrol (Galicia) regasification plants, with a 42.5% (21.25% Eni’s interest) and 18.9% interest (9.45% Eni’s interest), respectively.

Eni targets to increase its sales in the Iberian Peninsula from the current 5.2 BCM level to approximately 8.5 BCM by 2010 (13% average growth rate), as a result of an increase in both sales of Unión Fenosa Gas and in direct sales, in particular to the Spanish power generation segment supplied mainly by LNG from Nigeria.

UK/Northern Europe Eni through North Sea Gas & Power unit of its subsidiary Eni UK Ltd sells 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 UK/North European markets from the current 2.64 BCM level to approximately 8 BCM by 2010, with a 32% average annual growth rate. In particular, a significant increase is expected in spot sales on the Zeebrugge hub (from 0.2 BCM in 2006 to 4.2 BCM in 2010). In the UK, gas sales through North Sea Gas &Power are expected to grow from 2.5 BCM in 2006 to 3.8 BCM in 2010, equal to a 3% market share.

Turkey Eni and Gazprom market jointly natural gas to the Turkish company Botas under a long-term 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 2006 Eni’s share of sales volumes amounted to 3.68 BCM. Leveraging on the expected demand growth in Turkey and existing spare capacity in this pipeline, Eni plans to increase sales up to 6.4 BCM by 2010, equal to an 18% market share. The full transport capacity of this pipeline of 16 BCM/y is expected to be saturated in 2010.

 

Infrastructure

Eni owns a wide, integrated network of infrastructures for transporting, delivering and storing natural gas in Europe which enables Eni to connect major natural gas producing areas (North Africa, Russia and the North Sea) to European markets. In Italy, Eni owns 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 regasification capacity in Italy and the Iberian Peninsula and storage sites guarantees a high level of operating flexibility. In order to increase the diversification and reliability of supplies and to cope with expected European demand growth, Eni defined an important plan for upgrading its import infrastructure from Russia, Algeria and Libya, its regasification capacity and its national transport and distribution networks. This plan envisages a capital expenditure of approximately euro 5.8 billion to be deployed in the next four-year period.

 

International Transport Activities

In order to import natural gas to Italy, Eni owns transportation rights on an international high pressure network of pipelines extending for approximately 4,300 kilometers. These lines are connected with Eni’s natural gas transport system in Italy. A description of the main pipelines is provided below:

  The TAG pipeline importing natural gas from Russia is 1,140-kilometer long and is composed of three lines, each about 380-kilometer long, with a transport of 31 BCM/y following completion of an upgrading project started a few years ago to enable the build-up of Eni’s fourth import contract from Russia. This pipeline has three compression stations and transports natural gas from Russia across Austria from Baumgarten, the delivery point at the border of Austria and Slovakia, to Tarvisio, entry point into the Italian natural gas transport system. This pipeline is currently undergoing an upgrading plan to boost transport capacity by an additional 6.5 BCM/y to 44 BCM/y, starting operations in October 2008. Capital expenditure is estimated at about euro 253 million (94% covered by Eni). A 3.2 BCM portion of this upgrade has been assigned to third parties importing natural gas into Italy in February 2006. Procedures have been started for the assignment of this upgrade to third parties.
  The TTPC pipeline importing natural gas from Algeria is 742-kilometer long and is composed of two lines, each 371-kilometer long, with a transport capacity of 27 BCM/y and three compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. This pipeline is currently undergoing an upgrading plan to boost transport capacity by an additional 6.5 BCM/y to 33.5 BCM/y, of these 3.2 BCM are expected to entry operations in April 2008 and 3.3 BCM in October 2008. Capital expenditure is estimated at euro 450 million. The first portion of this transport upgrade (3.3 BCM) has been assigned to third parties importing natural gas to Italy. The procedure for the assignation of the second portion of this upgrading has finalized in February 2007. The transport capacity of the downstream TMPC pipeline is already adequate to handle the upgrade of the TTPC.

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  The TMPC pipeline importing natural gas from Algeria is 775-kilometer long and is composed of five lines each 155-kilometer long with a transport capacity of 33.5 BCM/y. This pipeline crosses underwater the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the entry point 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 a transport capacity of 15.5 BCM/y and four compression stations. It transports natural gas from the Netherlands through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border.
  The Transitgas pipeline importing natural gas from the Netherlands and Norway is 291-kilometer long, with one compression station. It 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 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 the Norwegian gas.
  The GreenStream pipeline importing natural gas from Libya is 550-kilometer long on a single line. This pipeline has a 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). In 2006 this pipeline transported 7.7 BCM (Eni share’s is 50%), of which 6.6 BCM is sold to Italian importers under long-term supply contracts with a 24-year term, targeting full supplies of 8 BCM/y. The delivery point is Gela in Sicily the Gas & Power segment purchased a 50% share of this volumes from Eni’s Exploration & Production segment and the remaining 50% share from the Libyan partner National Oil Company under a long-term supply contract with a 24 year-term. The remaining 1.1 BCM of natural gas were purchased by the Gas & Power segment on a spot basis. Said volumes available from the Libyan field production could not be absorbed by the local market. Production plateau volumes are expected in 2007 at 10 BCM/y, of which 8 BCM/y will be sold to those Italian third party importers under long-term supply contracts and remaining 2 BCM/y are expected to be sold on the Libyan market by the two partners.
An upgrade of the pipeline’s transport capacity from 8 to 11 BCM is planned with an estimated expenditure of approximately euro 80 million. This new capacity will be available from 2011 and will enable Eni to monetize further volumes of natural gas reserves located in Libya through the sale on the Italian market.

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 totally 774-kilometer long with two lines and has a transport capacity of 16 BCM/y. Eni expects to reach full volumes supplies to the Turkish market by 2010. The pipeline includes a compression station at Dzhubga on the Russian coast of the Black Sea, made up of six turbocompressors and six measurement lines as well as an internally fired power plant.

 

Italian Transport Network

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 regasification terminal operating in Italy. Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed.

Eni’s Italian natural gas transport system is made up of a national pipeline network and a regional pipeline network for a total length of 30,889 kilometers as follows:

(i)   the national transport network portion extends for approximately 8,497 kilometers and consists of high pressure trunklines mainly with a large diameter, which carry natural gas from the entry points to the system – import lines, storage sites and main Italian natural gas fields – to the linking points with the regional transport network. The national network also includes some interregional lines reaching important markets; and
(ii)   the regional transport network portion extends for approximately 22,410 kilometers and consists of smaller lines enabling the delivery of natural gas to large industrial complexes, power stations and local distribution companies of the various local areas served.

In 2006 Eni’s network increased by 177 kilometers due to some changes to existing lines of national network (87 kilometers) and extensions of the regional network (90 kilometers).

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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 48/42-inch diameter, each approximately 1,500-kilometer long, including the smaller pipe that crosses underwater the Messina Strait, which links Mazara del Vallo (on the Southern coast of Sicily) to Minerbio (near Bologna). This pipeline is undergoing an upgrade with the laying of a third line with 48 inch diameter that is 328-kilometer long (of these 272 are already operating). Transport capacity at the Mazara del Vallo entry point is approximately 86 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 import pipeline 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 extending for a total length of approximately 900 kilometers that are linked to the Austrian network in Tarvisio and cross the Po Valley reaching Sergnano (near Cremona) and Minerbio. The pipeline is being upgraded by the laying of a third 264-kilometer long line with diameter from 48 to 56 inches; 232 kilometers were already operating at the end of 2006, from Tarvisio to Zimella (Verona). The pipeline transport capacity at the Tarvisio entry point amounts to approximately 101 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:
    -   a 48-inch diameter, 177-kilometer long extending from the Italian border at Passo Gries (Verbania), point of connection with the Swiss network, to the node of Mortara, in the Po Valley. The pipeline transport capacity amounts to 63 mmCM/d;
  for natural gas coming from the Panigaglia LNG terminal:
    -   one line, with a 30-inch diameter, 170-kilometer long linking the Panigaglia terminal to the national network near Parma. The pipeline transport capacity at the Panigaglia entry point amounts to 13 mmCM/d.

Eni’s system is completed 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. In 2006 the ISO 9001-2000 certification was confirmed. Peripheral units are represented by eight districts monitoring the network through 55 centers that guarantee operation, maintenance and control of the whole system. Each unit is responsible for operations in accordance with technical specifications and applicable laws and regulations.

In the next four years Eni plans to carry out capital expenditure of approximately euro 4.2 billion aimed at the upgrade of its transport network in view of the expected increase in import capacity (in particular from Russia and Algeria).

In 2006 a total of 87.99 BCM of natural gas were input into the national network, 65% of which was owned by Eni.

Gas volumes transported (a)

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
   

(BCM)

Eni  

54.56

 

51.74

 

52.15

 

54.88

 

57.09

On behalf of third parties  

19.84

 

24.63

 

28.26

 

30.22

 

30.90

Enel  

8.28

 

9.18

 

9.25

 

9.90

 

9.67

Edison Gas  

5.34

 

7.49

 

8.00

 

7.78

 

8.80

Others  

6.22

 

7.96

 

11.01

 

12.54

 

12.43

Total  

74.40

 

76.37

 

80.41

 

85.1

 

87.99

 
 
 
 
 

(a)   Include amounts destined to domestic storage.

 

Distribution Activity

Distribution involves the delivery of natural gas to residential and commercial consumers in urban centers through low pressure networks. Eni, through its 100% subsidiary Italgas and other subsidiaries, is engaged in the distribution activity in Italy serving 1,317 municipalities through a low pressure network consisting of approximately 49,000 kilometers of pipelines supplying 5.6 million customers.

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Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, distribution activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This makes distribution a low risk business capable of delivering stable performance in the long period. The management of networks is entrusted to natural gas companies by local Authorities exclusively under bid procedures. Concessions existing at the coming into force of Legislative Decree No. 164/2000 and awarded with a bid procedure expire on December 31, 2012; all other concession expire on December 31, 2007 (with an optional three-year extension under certain conditions). Eni intends to optimize its concession portfolio maintaining its current size in terms of end users served by focusing on development initiatives in core areas and promoting local alliances aimed at supporting sale activities on retail markets.

 

Regasification - LNG

Eni intends to strengthen its integrated LNG business on a global scale, aiming at further diversifying its supply sources, improving operational flexibility, and monetizing its large equity gas reserves. In particular, the development of regasification capacity is aimed at reinforcing and diversifying Eni natural gas supply portfolio. Eni’s main assets in LNG are:

Italy Eni owns the only regasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can input 3.5 BCM/y into the Italian transport network. In 2006 a total of 3.13 BCM of natural gas were input in the national network, of these 48% were owned by Eni. Eni plans to build a new regasification terminal located off the Adriatic coast (with a 50% interest) and to increase the capacity of the Panigaglia plant. These two projects are expected to upgrade the import capacity to Italy by 8 and 4.5 BCM/y, respectively, when fully operational. The planned start up is expected by 2013 and 2014, respectively. The capital expenditure earmarked for the offshore regasification projects amounts to approximately euro 800 million (of these euro 400 million for the 50% interest in the offshore regasification plant and euro 359 million for Panigaglia).

Egypt Eni, through its interest in Unión Fenosa Gas, owns a 40% stake in the Damietta liquefaction plant producing approximately 5 mmtonnes/y of LNG equal to a feedstock of 7.6 BCM/y of natural gas. In June 2006, the partners of the project agreed on terms and conditions for doubling the plant capacity by means of building another treatment train. Expected capital expenditure amounts to approximately $1.5 billion with start up expected between 2010 and 2011. In order to market its share of natural gas, Eni intends also to build two gas tanker ships with a capacity of 155 KCM each.

Spain In April 2006, the Sagunto regasification plant with a capacity of 6.7 BCM/y started operations near Valencia. Eni through Unión Fenosa Gas holds a 21.25% interest in this plant. At present, Eni’s share of regasification capacity amounts to 1.6 BCM/y of gas. An upgrading plan has been sanctioned targeting a 0.8 BCM/y capacity increase by 2009.
Relevant works started in the second half of 2006. Eni through Unión Fenosa Gas also holds a 9.5% interest in the el Ferrol regasification plant, located in Galicia, under construction and expected to be completed by the first half of 2007, targeting a treatment capacity of approximately 3.6 BCM/y, 0.4 BCM/y being Eni’s share.

USA Eni is entitled to a share of the initial planned capacity of the Cameron regasification terminal under construction in Louisiana, and expected to start operations by 2008-2009. The 6 BCM/y capacity represents approximately 40% of the initial capacity of the plant (15.5 BCM/y). This transaction will enable Eni to sell part of its gas reserves in the United States.
In order to provide supplies to this plant, in February 2007 Eni signed an agreement 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 (7 trains) expected for 2012. Negotiations are also progressing with Brass LNG Ltd for the purchase of 1.42 mmtonnes/y of LNG equivalent to 1.96 BCM/y of gas. Eni signed a Memorandum of Understanding with Sonangol to acquire a 13.6% participation in the Angola LNG project and 5 BCM/y of capacity in the Pascagoula regasification terminal to be constructed in Mississippi.

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, through EniPower, is one of the major operators in electricity generation on the Italian market. Operating since 2000, EniPower owns power stations located at Eni’s sites in Brindisi, Ferrera Erbognone, Livorno, Mantova, Ravenna, Ferrara and Taranto with installed capacity in operation of approximately 4.9 GW at December 31, 2006 (4.5 GW in 2005).

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Starting in 2007, the marketing of electricity conducted by EniPower until 2006 is being conducted by the department responsible for natural gas marketing. Under this project, the Gas & Power Division is expected to conduct directly the electricity marketing activity previously conducted by EniPower, starting in 2007. This scheme will allow the integrated management of marketing activities of gas and electricity and the development of a joint-offer of natural gas and electricity to customers. Plans for developing the dual offer will leverage on the opening of the Italian electricity market effective on July 1, 2007.

In 2006, Eni sold 31.03 TWh of electricity, of which about 24.82 TWh were produced by EniPower, corresponding to over 9.2% of the Italian market, and 10.287 mmtonnes of steam. Approximately 55% of sales were directed to end users, 28% to the Electricity Exchange, 8% to GRTN/Terna (under CIP 6/92 contracts and imbalances in input) and 9% to wholesalers. All the steam produced was sold to end users.

Eni is completing a plan for expanding its electricity generation capacity, targeting in 2010 an installed capacity of 5.5 GW with production amounting to 31 TWh when fully operational, corresponding approximately to 8.4% of electricity generated in Italy at that date. Planned expenditure amounts to euro 2.4 billion, of which euro 2 billion is already expensed.

High efficiency, low environmental impact, 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 mode has been acknowledged by the Authority for Electricity and Gas as a production mode that entails priority on the national dispatching network and the exemption from the purchase of "green certificates"5.

New installed generation capacity uses the combined cycle gas turbine fired technology (CCGT), ensuring a high level of efficiency and low environmental impact. In particular, management estimates that for a given amount of energy (electricity and heat) produced, the use of the CCGT technology on a production of 31 TWh reduces emissions of carbon dioxide by approximately 11 mmtonnes, as compared to emissions using conventional power generation technology.

EniPower intends to become a cost leader in the Italian electricity industry thanks to the high technology content and optimal size of the plants it is building. When fully operational in 2010, consumption of natural gas of Eni’s plants is expected to reach over 6 BCM/y, supplied by Eni.

Power Generation

2003

 

2004

 

2005

 

2006

 
 
 
 
Purchases                    
Natural gas  

(mmCM)

 

940

 

2,617

 

4,384

 

4,775

Other fuels  

(KTOE)

 

847

 

784

 

659

 

616

- including cracking steam          

89

 

96

 

136

Sales                    
Electricity production sold  

(TWh)

 

5.55

 

13.85

 

22.77

 

24.82

Electricity trading  

(TWh)

 

3.10

 

3.10

 

4.79

 

6.21

Steam  

(ktonnes)

 

9,303

 

10,040

 

10,660

 

10,287

 
 
 
 

 

The development plan has been completed at all sites except for Ferrara (Eni’s interest 51%), where in partnership with Swiss company EGL AG, construction of two new 390 MW combined cycle units is underway. These new units will increase installed capacity to 840 MW with start up expected in the first quarter of 2008. Moreover, Eni plans the installation of a new 240 MW combined cycle unit located in Taranto (current capacity 75 MW) with expected start up in 2010.

Ferrera Erbognone On May 14, 2004 the combined cycle power station was inaugurated, the first one in Italy after the opening up of the electric market. This power station has an installed capacity of approximately 1,030 MW articulated in 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 tar from visbreaking from Eni’s nearby Sannazzaro de’ Burgondi 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.

_______________

(5)   Article 11 of Legislative Decree No. 79/1999 concerning the opening up of the Italian electricity market obliges importers and 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.

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Brindisi Three new combined cycle 390 MW units, two of which started operations in 2005, the last started operation in the second half of 2006. When fully operational the power station will have a total capacity of approximately 1,320 MW, including already existing amounts.

Mantova Two new combined cycle 390 MW units started operations in 2005 with full operation in early 2006. The power station will have a total installed capacity approximately 840 MW. This power station will provide steam for heating purposes delivered to Mantova’s urban network through a heat exchanger.

 

Capital Expenditure

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

 

 

Refining & Marketing

Eni is leader in the refining business and in the marketing of refined products in Italy and holds important market shares in some European countries. Eni’s refining and marketing operations are efficiently integrated so as to achieve cost efficiencies and deliver good returns on capital employed. The integration with upstream operations represents a further competitive advantage. Eni’s key medium-term objective in its downstream oil business is to enhance profitability. The strategic guidelines to attain this objective are the following:

  to enhance Eni’s refining system by means of a focused investment program;
  to improve profitability and qualitative standards of the Italian retail network;
  to grow retail sales in selected markets in the rest of Europe; and
  to pursue higher levels of operational efficiency.

In the next four years, management plans to implement these strategies by deploying a capital expenditure program of approximately euro 4.3 billion. This capital expenditure is expected to be focused mainly on refinery upgrading. Planned actions are intended to boost refinery conversion rate and flexibility in order to produce higher-value products and to process low-quality crude that is typically discounted in the market-place, and to lower operating costs. Management expects to strengthen integration with Eni’s upstream operations. An important portion of this capital expenditure will be directed to retail networks upgrading in Italy and in the rest of Europe. In addition, in order to increase profitability of retail operations, Eni plans to implement customer-focused marketing initiatives, including effective pricing differentiation and an improved premium-products offer, and to pursue operating efficiencies. In retail activities in the rest of Europe, Eni plans to selectively develop its presence in target European markets, leveraging on synergies deriving from proximity to Eni’s production and logistic facilities.

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 2006, a total of 65.70 mmtonnes of oil were purchased (66.48 mmtonnes in 2005), of which 36.81 mmtonnes were purchased from Eni’s Exploration & Production segment, 18.16 mmtonnes were purchased under long-term contracts with producing countries and 10.73 mmtonnes were purchased on the spot market. Some 21% of oil purchased came from West Africa, 21% from North Africa, 18% from countries of the former Soviet Union, 14% from the Middle East, 14% from the North Sea, 7% from Italy and 5% from other areas. Some 30.66 mmtonnes were traded, down 1.3% from 2005. In addition, 3.18 mmtonnes of intermediate products were purchased (3.58 mmtonnes in 2005) to be used as feedstock in conversion plants and 16 mmtonnes of refined products (16.21 mmtonnes in 2005) were purchased to be sold on markets outside Italy (11.48 mmtonnes) and on the Italian market (4.52 mmtonnes) as a complement to our own production.

 

Refining

Eni owns five refineries in Italy and interests in refineries located in Italy, Germany and the Czech Republic with a total refining capacity (balanced with conversion capacity) of approximately 35.5 mmtonnes (equal to 710 KBBL/d) and a conversion index of 57%. Eni’s wholly owned refineries in Italy have a balanced capacity of 26.7 mmtonnes (equal to 534 KBBL/d), with a 58.9% conversion rate.

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Eni’s refining system in Italy is made up of five wholly owned refineries and a 50% interest in the Milazzo refinery in Sicily. Eni plans to upgrade its refining system with a capital expenditure for the next four years amounting to approximately euro 2.4 billion (including logistics activities).

In the medium-term, management expects the refining environment to be featured by the following trends: (i) global imbalances in the availability of products among macro geographic areas; (ii) a low adequacy of existing refining assets to process heavy and non conventional feedstock against a backdrop of persisting high spreads between light/sweet and heavy/sour crude qualities; (iii) an imbalance of existing refining assets towards higher yields in gasoline and fuel oil in contrast with rising demand for middle distillates; and (iv) increasingly tight environmental and product quality regulations which make the upgrading of existing refining assets a critical issue.

Against this backdrop, Eni plans to enhance the profitability of its refining business, capturing opportunities arising from current market trends by implementing a large investment program of approximately euro 3 billion in the next four years. The main planned actions are: (i) to increase primary and conversion capacity, targeting a complexity index6 higher than 57%, in view of boosting middle distillate yields, including petrochemical feedstock, and extracting value from equity crude, the availability of which is expected to increase in the Mediterranean basin over the medium-term; (ii) to improve refinery flexibility in order to optimize processed feedstock and capture market opportunities arising from an expected increasing availability of heavy/sour crude which can be purchased at a discount in the marketplace; (iii) to achieve high-quality products responsive to expected demand trends and the evolution of product specifications provided for by increasingly tight European standards in term of emissions and environmental preservation; (iv) to strengthen integration with upstream and petrochemical operations; and (v) to enhance operational efficiency of refineries, targeting in particular a higher level of energy efficiency.

The table below sets forth certain statistics regarding Eni’s refineries at December 31, 2006.

   

Location

 

Ownership interest

 

Conversion equivalent (1)

 

Balanced primary distillation capacity (2)

   
 
 
 
Wholly-owned refineries:                
Sannazzaro  

Lombardy

 

100%

 

46.2

 

170,000

Gela  

Sicily

 

100%

 

143.5

 

100,000

Taranto  

Apulia

 

100%

 

61.1

 

110,000

Livorno  

Tuscany

 

100%

 

11.4

 

84,000

Porto Marghera  

Veneto

 

100%

 

22.8

 

70,000

           
 
           

58.9

 

534,000

Partly-owned refineries:                
Milazzo  

Sicily

 

50%

 

72.3

 

80,000

Ingolstadt/Vohburg/Neustadt  

Germany

 

20%

 

32.6

 

52,000

Schwedt  

Germany

 

8.3%

 

41.8

 

19,000

Kralupy/Litvinov  

Czech Rep.

 

16.33%

 

28.8

 

26,000

           
 
           

50.9

 

177,000

           
 
Total Eni          

57.0

 

711,000

           
 

(1)   Stated in fluid catalytic cracking equivalent/topping (% by weight), based on 100% of balanced primary distillation capacity.
(2)   Barrels per calendar day. Based on percentage equity interest ownership in the refinery, not on actual utilization of balanced primary distillation capacity.

Each of Eni’s Italian refineries has an operational and strategic setup adequate to maximizing return on assets and monetizing its geographic location with respect to end markets and integration with other Eni business segments.

 

Italy

Eni’s refining system in Italy is composed of five wholly owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to markets and the integration with Eni’s other activities.

Sannazzaro, with a balanced primary refining capacity of 170 KBBL/d and an equivalent conversion index of 46.2% is one of the most efficient refineries in Europe. Located in the Po Valley, it supplies mainly markets in North-Western Italy and Switzerland. The high degree of flexibility of this refinery allows it to process a wide range of oils, such as CPC Blend crude oil from the Caspian Sea carried through the CPC pipeline, the Bonga crude from Nigeria and oil from Eni’s Villafortuna field. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genova terminal with French-speaking Switzerland.

_______________

(6)   For a definition, see "Glossary".

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This refinery contains two primary distillation plants and a vacuum unit. Conversion is obtained through a fluid catalytic cracker (FCC7), an HDCK middle distillate conversion unit and a visbreaking thermal conversion unit. Two catalytic reforming plants, an isomerization plant, an alkylation plant, an MTBE plant and three desulfurization plants for middle distillates and one for naphtha from cracking complete the production cycle. In 2006, Eni completed a gasification facility using the heavy residue from visbreaking (tar) to produce syngas to feed the nearby EniPower power station at Ferrera Erbognone.

Eni plans to upgrade this refinery. In particular, in the next four years, Eni plans to build: (i) a high pressure hydrocracking unit with a capacity of 28 KBBL/d, able to produce over 1 mmtonnes/y of high quality middle distillates, in particular diesel fuel with low sulfur content and kerosene. Start up is planned at 2008 end; and (ii) a PDA deasphalting unit with a 28 KBBL/d capacity for the production of deasphalted oil (without asphaltene and metals) from visbreaking and vacuum unit residues to be used as feedstock for the FCC unit. Further residues will be used as feedstock for the tar gasification plant. The deasphalting plant will enable Eni to increase the refinery’s flexibility thanks to the processing of a higher amount of high sulfur content crude, thus increasing the yield of valuable products (diesel fuel). Start up is planned in 2008.

Eni is currently evaluating the building of a plant employing Eni Slurry Technology (see "Innovative technologies", below) with a 23 KBBL/d capacity for the processing of extra heavy crudes and tar sands producing higher quality products, in particular diesel fuel, and reducing the yield of fuel oil to zero.

Gela, with a balanced primary refining capacity of 100 KBBL/d and an equivalent conversion index of 143.5% represents an upstream integrated pole with the production of heavy crudes obtained from nearby Eni fields offshore and onshore Sicily, while downstream it is integrated with Eni’s nearby petrochemical plants. Located on the Southern coast of Sicily, it manufactures fuels for automotive use and residential heating purposes, as well as petrochemical feedstocks. Its high conversion level allows it to minimize the yield of fuel oil and semi-finished products.

Besides its primary distillation plants, this refinery contains the following plants: an FCC unit with go-finer for the upgrading of feedstocks and two coking plants for the vacuum conversion of heavy residues. All these plants are integrated in order to process heavy residues and feedstocks and manufacture valuable products. It also contains two reforming units, an alkilation unit, an MTBE unit and plants for desulfurization of gas oil and naphtha from cracking. The power plant of this refinery also contains modern residue and exhaust fume treatment plants which allow the complex to comply with the most exacting environmental standards.

An upgrade of the Gela refinery will be implemented by means of an upgrade of topping capacity to enable higher intakes (approximately 1 mmtonnes/y) and of feedstock flexibility.

In addition, actions to improve energy efficiency, renewal of facilities for gasoline production, and the upgrade of utilities and the logistic reorganization of the site are planned.

Taranto, with a balanced primary refining capacity of 110 KBBL/d and an equivalent conversion index of 61.1%, can process a wide range of crudes and semi-finished products with great operational flexibility.

It mainly produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants, this refinery contains a flash vacuum unit, two plants for the desulfurization of middle distillates, a reforming unit, an isomerization unit and conversion plants such as: a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant, that allows to convert high sulfur content residues into valuable products and cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2006 a total of 3.157 mmtonnes of this oil were processed).

Eni plans to develop and upgrade this refinery as well. In particular, two projects are planned: (i) the building of a new high pressure hydrocracking unit with a 17 KBBL/d capacity and the revamping of the hydrogen production unit; these assets will allow to produce approximately 0.6 mmtonnes/y of high quality gasoil when fully operational in 2008; and (ii) the building of a new topping unit with a 4 mmtonnes/y capacity and an associated vacuum unit with a 2.5 mmtonnes/y capacity. Eni also plans to build a new unit for the desulfurization of middle distillates with a 2.3 mmtonnes/y capacity, in addition to utilities and logistic facilities (see "Logistics", below), in particular a pipeline for transporting virgin naphtha to Eni petrochemical plant at Brindisi. The objective is to expand the consumption area covered by the refinery to Campania. Start up is expected in 2009-2010.

_______________

(7)   Conversion plant where vacuum feedstock undergoes cracking at high pressure and moderate temperature thus producing mostly high quality gasoline. This kind of plant guarantees high operating flexibility to the refinery.

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This development and upgrading plan will enable Eni to better employ national and Caspian equity crude and give more flexibility to this refinery, optimizing the use of the conversion plants and increasing throughput from 6 to 10 mmtonnes/y (100-180 KBBL/d).

Livorno, with a balanced primary refining capacity of 84 KBBL/d and an equivalent conversion index of 11.4%, manufactures mainly gasolines, fuel oil for bunkering, specialty products and lubricant bases. Besides its primary distillation plants, this refinery contains a vacuum unit, a reformer unit, an isomerization plant, two desulfurization units for middle distillates and 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 primary refining capacity of 70 KBBL/d and an equivalent conversion index of 22.8%, supplies mainly markets in North-eastern Italy, Austria, Slovenia and, to a lesser extent, Croatia. Besides its primary distillation plants with vacuum plants, this refinery contains a reformer plant, an isomerization plant, two gasoil desulfurization units and a two-stage thermal conversion plants (visbreaking/thermal cracking) for increasing yields of valuable products.

The plant upgrading project, subject to the extension of the refining license, concerns the construction of a new hydrocracker with a 24 KBBL/d capacity and upgrades of utilities. The objective is to increase intake (up 1.4 mmtonnes/y, to approximately 5.5 mmtonnes when fully operational), the improvement of flexibility in processed feedstocks, the increase in middle distillates produced (up 0.7 mmtonnes) in an area characterized by structural diesel fuel deficit, and higher energy efficiency.

 

Rest of Europe

In Germany Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that includes the Ingolstadt, Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 70 KBBL/d. Eni’s share of the production of the three integrated refineries and of the Schwedt refinery is mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. Eni plans to restructure the Bayernoil refining pole, by building a new hydrocracker with a capacity of approximately 2 mmtonnes/y, revamping other assets (in particular a reformer and a hydrofiner) and shutting-down a topping unit.

Eni holds a 16.33% interest in Ceska Rafinerska which owns and manages two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to 27 KBBL/d (corresponding to approximately 1.3 mmtonnes/y). In May 2007, Eni agreed to purchase a 16.11% interest held by ConocoPhillips Central and Eastern Europe Holdings BV in the Ceska Rafinerska Co. When this transaction is finalized, Eni will increase its stake in this refinery from 16.3% to 32.4%, corresponding to a refinery capacity of 2.6 mmtonnes/y.

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

Petroleum products availability

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
   

(mmtonnes)

Italy                              
Refinery throughputs at wholly-owned refineries  

30.09

   

25.09

   

26.75

   

27.34

   

27.17

 
Refinery throughputs on account of third parties  

(1.88

)  

(1.72

)  

(1.50

)  

(1.70

)  

(1.53

)
Refinery throughputs at third party refineries  

6.27

   

8.43

   

8.10

   

8.58

   

7.71

 
Products consumed and lost  

(1.91

)  

(1.64

)  

(1.64

)  

(1.87

)  

(1.45

)
Products available  

32.57

   

30.16

   

31.71

   

32.35

   

31.90

 
Purchases of finished products and change in inventories  

6.27

   

5.86

   

5.07

   

4.85

   

4.45

 
Finished products transferred to foreign cycle  

(5.56

)  

(5.19

)  

(5.03

)  

(5.82

)  

(5.35

)
Consumption for power production  

(1.74

)  

(1.07

)  

(1.06

)  

(1.09

)  

(1.10

)
Sales  

31.54

   

29.76

   

30.69

   

30.29

   

29.90

 
Outside Italy                              
Products available  

2.98

   

3.36

   

4.04

   

4.33

   

4.37

 
Purchases and change in inventories  

12.16

   

12.12

   

13.78

   

11.19

   

11.51

 
Finished products transferred from Italian cycle  

5.56

   

5.19

   

5.03

   

5.82

   

5.35

 
Sales  

20.70

   

20.67

   

22.85

   

21.34

   

21.23

 
Sales in Italy and outside Italy  

52.24

   

50.43

   

53.54

   

51.63

   

51.13

 
 
 
 
 
 

In 2006, refinery throughputs on own account in Italy and outside Italy were 38.04 mmtonnes, down 0.75 mmtonnes from 2005, or 1.9%, owing to lower throughputs on third party refineries as a consequence of an accident that occurred at the Priolo (third party) refinery and a maintenance standstill at the Milazzo refinery (Eni’s interest 50%).

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Refining throughputs on own account were stable. In particular, refining throughputs increased at the Venice, Gela and Taranto refineries and decreased at the Sannazzaro refinery due to a maintenance standstill of the catalytic cracking unit and the visbreaking unit, and at the Livorno refinery due to general maintenance activity. In April, a new unit for heavy residue gasification started operating at the Sannazzaro refinery.

Total throughputs on wholly-owned refineries (27.17 mmtonnes) decreased 0.17 mmtonnes from 2005, down 0.6%; balanced capacity of refineries was fully utilized. Approximately 35.9% of volumes of processed oil were supplied by Eni’s Exploration & Production segment (32.3% in 2005), representing a three percentage point increase from 2005. Incremental volumes of some 1.1 mmtonnes of equity oil processed related to higher supplies of heavy oil from Nigeria (due to the start up of the Bonga field) and from Sicily, against a reduction of supplies of the Libyan Bu-Attifel oil processed at Priolo.

 

Logistics

Eni is engaged in storage and transport of petroleum products in Italy. Its integrated logistics infrastructure consists of 12 directly managed 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 - Genova (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 3,210 kilometers (1,513 kilometers are wholly owned by Eni); and (ii) by sea through spot and long-term lease contracts of tanker ships. For the distribution of refined products to retail and wholesale markets, Eni owns a fleet of tanker trucks and manages third-party owned vehicles.

In the medium-term, management plans to enhance the relationship between its logistic and refining operations by implementing an integrated logistic model ("hub" model) designed to centralize handling of product flows on a single platform enabling real time monitoring. This new setup is expected to deliver significant cost savings and efficiency improvements. In the next four years, Eni plans to invest approximately euro 0.6 billion directed in particular to the implementation of the Taranto logistic project intended to support the refinery’s development plan: a new diesel fuel and gasoline storage site will be built in Campania and three pipelines will be laid, two of which will link the refinery to the storage site and the other one will transport virgin naphtha to Eni’s petrochemical complex in Brindisi. The objective of this plan is to eliminate the transport of refined products by sea to Naples.

 

Marketing

Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive direct sales network, 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

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
   

(mmtonnes)

Italy                    
Retail sales  

11.14

 

10.99

 

10.93

 

10.05

 

8.66

Wholesale sales  

10.64

 

10.35

 

10.70

 

10.48

 

10.06

   

21.78

 

21.34

 

21.63

 

20.53

 

18.72

Petrochemicals  

3.82

 

2.79

 

3.05

 

3.07

 

2.61

Other sales (1)  

5.94

 

5.63

 

6.01

 

6.69

 

8.57

Sales in Italy  

31.54

 

29.76

 

30.69

 

30.29

 

29.90

Outside Italy                    
Retail sales rest of Europe  

2.57

 

3.02

 

3.47

 

3.67

 

3.82

Retail sales Africa and Brazil  

1.44

 

1.18

 

0.57

       
   

4.01

 

4.20

 

4.04

 

3.67

 

3.82

Wholesale sales  

5.65

 

6.01

 

5.30

 

4.50

 

4.60

   

9.66

 

10.21

 

9.34

 

8.17

 

8.42

Other sales (1)  

11.04

 

10.46

 

13.51

 

13.17

 

12.81

Sales outside Italy  

20.70

 

20.67

 

22.85

 

21.34

 

21.23

   

52.24

 

50.43

 

53.54

 

51.63

 

51.13

 
 
 
 
 

(1)   Includes bunkering, consumption for power production (until 2001) and sales to oil companies. From 2002, also includes sales of MTBE.

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In 2006, sales volumes of refined products (51.13 mmtonnes) were down 500 ktonnes from 2005, or 1%, mainly due to lower wholesale volumes (down 320 ktonnes) as a consequence of mild weather conditions in the last part of the year adversely affecting heating products sales. In addition, lower volumes were supplied to the petrochemical sector (down 460 ktonnes) owing to the technical accident that occurred at the Priolo refinery. These declines were offset in part by higher sales to oil companies and traders and by a growth in retail sales on the Agip branded network in Italy and outside Italy (up 60 ktonnes).

The impact of the Italiana Petroli (IP) divestment, effective September 1, 2005 (1.3 mmtonnes), was partly offset by supply of fuels to the same company under a five-year contract signed concurrently with the divestment.

In retail distribution Eni intends to enhance its leadership in the Italian retail market, improving outlets and service quality standards and targeting a strong product differentiation and customer-oriented promotional initiatives.

In the rest of Europe, Eni will selectively grow its market share, targeting a strengthening of its competitive position in selected markets, leveraging on synergies achievable thanks to the geographic location of its production and logistic assets and on strong brand awareness.

 

Retail Sales in Italy

Retail volumes of refined products marketed on the Italian network (8.66 mmtonnes) were down 1.39 mmtonnes from 2005, or 13.8% mainly due to the IP divestment as outlined above. Retail volumes marketed on the Agip branded network (8.66 mmtonnes) decreased of some 90 ktonnes, down 1%, due to a higher competitive pressure. This decline essentially concerned gasoline and BluDiesel, following a pattern aligned with national consumption trends. Market share of the Agip branded network was down 0.4 percentage points from 29.7% to 29.3% in 2006; average throughput in terms of gasoline and diesel fuel was 2,463 kliters, down 1.8% from 2005.

At December 31, 2006, Eni’s retail distribution network in Italy consisted of 4,356 service stations, seven more than at December 31, 2005 (4,349 units), resulting from the opening of new service stations (20 units) and the positive balance of acquisitions/releases of lease concessions (11 units), offset in part by the closing of service stations with low throughput (21 units) and the release of 3 service stations under highway concessions.

Retail volumes of BluDiesel – a high performance and low environmental impact diesel fuel – amounted to about 726 ktonnes (840 mmliters), down 14.8% from 2005, mainly due to an increasingly high sensitivity of consumers to retail prices of fuels in light of their escalation that pushed prices to historical peaks. At year-end, virtually all Agip branded service stations marketed BluDiesel (about 4,061 equal to 93%).

Retail volumes of BluSuper – a high performance and low environmental impact gasoline – amounted to about 98 ktonnes (114 mmliters), down 9% from 2005, showing a trend similar to the one of BluDiesel. At year-end, service stations marketing BluSuper totaled 2,316 (1,719 at December 31, 2005) corresponding to approximately 53% of Eni’s network.

In 2006, Eni continued its Do-It-Yourself campaign which allows participating customers to obtain discounts or gifts (under agreements with Vodafone and Coop) in proportion to volumes of fuel purchased at self-service outlets, charged on an electronic card. Further bonuses are offered to the most faithful customers. At year-end, the number of active cards was approximately 3.9 million; turnover on cards increased by 3% from 2005. Volumes of fuel marketed under this initiative represented some 39% of total volumes marketed on the Agip branded outlets joining the campaign, and some 31% of overall volumes marketed on the Agip network. In March 2007, Eni launched its new You&Agip promotional initiative designed to boost customer loyalty to the Agip brand. The main features of this initiative are: (i) its time span which is longer than usual initiatives of this kind (until December 31, 2009); and (ii) the freedom of customers on how to accumulate points and when to spend them. Furthermore, the list of prizes will be kept constantly updated thanks to the high numbers of partners joining the initiative. Points can be accumulated not only by buying fuels, but also by buying all the other services and wares sold at Eni’s outlets.

Eni intends to strengthen its competitive positioning in Italy by introducing new outlet formats in line with European standards of quality and services, increasing premium products sales and differentiating promotional offers in order to retain the various segments of clients. Management expects also to boost the profitability of its retail operations in Italy by developing the offer on non-oil products by means of building convenience stores, cafés and fast food outlets and other innovative commercial outlets. A strong focus will be devoted to pursue high levels of operating efficiency. In the next four years, Eni plans to invest approximately euro 0.75 billion in the upgrading of its network, targeting to build and acquire new service stations, upgrade/restructure existing ones, and to adequate them to applicable environmental standards and regulations. By 2010, Eni expects to have a retail network composed of approximately 4,360 service stations with an average throughput of approximately 2.7 Bliters per station. Marketed volumes are expected to grow by an approximately 1.8% on average over the next four years.

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Retail Sales in the Rest of Europe

In recent years, Eni’s strategy in the rest of Europe focused on selectively growing its market share, by means of acquisition of assets in European areas with interesting profitability perspectives, mainly in Central-Eastern Europe (in particular Southern Germany, Austria, the Czech Republic and Hungary) in South-Eastern France and the Iberian Peninsula. In pursuing such growth, Eni has been able to reap synergies in these areas facilitated by their proximity to Eni’s production and logistic facilities.

Over the last five years, retail volumes of refined products marketed in the rest of Europe have grown more than 50% (equal to a compound average growth rate of 9%). In 2006, retail sales were 3.82 mmtonnes, up 150 ktonnes from 2005, or 4.1%, particularly in Germany, Spain and Austria due to the ramp-up of new stations purchased or built with higher throughput than the average level of Eni’s network, while a few less efficient outlets were dismissed. Volume growth was driven primarily by increased sales of diesel fuel and LPG, while gasoline volumes declined.

At December 31, 2006, Eni’s retail distribution network in the rest of Europe consisted of 1,938 units, an increase of five units from December 31, 2005. The network’s evolution was as follows: (i) 31 service stations were acquired in Austria and France; (ii) 24 new outlets were opened in Spain and Austria; (iii) 46 low throughput service stations were closed in Spain and France; and (iv) a negative balance of acquisitions/releases of lease concessions (down four units) was recorded, with negative changes in Portugal and Germany, positive ones in France and Spain. Average throughput (2,486 kliters) was up 2.4%.

In the next four-year period, Eni expects to increase marketed volumes by approximately 3.9% per year on average. Growth in marketed volumes will be achieved through acquisitions, leasing and construction of new service stations with high quality standards, automation and throughput, also leveraging on marketing campaigns aimed at enhancing the Agip brand perception on markets. By 2010 Eni plans to have a network of approximately 2,180 service stations with an average throughput of 2.6 Bliters.

 

Wholesale Marketing and Other Sales

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 2006, volumes marketed on wholesale markets in Italy, which excludes the Avio and Bunker businesses, were 8.22 mmtonnes down 610 ktonnes from 2005, or 7%, due mainly to a decline in domestic consumption related to mild weather conditions in the fourth quarter of the year.

Sales volumes on wholesale markets outside Italy were 4.27 mmtonnes, up approximately 100 ktonnes from 2005, or 2.6%, reflecting mainly higher sales in Germany and Spain.

Eni also markets jet fuel directly at 38 airports, of which 27 are in Italy. In 2006, these sales amounted to 2.18 mmtonnes (of which 1.84 mmtonnes were sold in Italy) up approximately 200 ktonnes. Eni is active also in the international market of bunkering, marketing marine fuel in 38 ports, of which 23 are in Italy. In 2006 marine fuel sales were 1.9 mmtonnes (1.24 in Italy) increasing 100 ktonnes.

Other sales were 22.09 mmtonnes of which 19.48 mmtonnes referred to sales to oil companies and traders, and 2.61 mmtonnes supplies to the petrochemical sector.

LPG

In Italy Eni is the market leader in LPG production, marketing and sale with 589 ktonnes sold for heating and automotive use (under the Agip brand and wholesale) equal to an 18% market share. Additional 350 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.

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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 masters international state-of-the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing).

In Italy Eni is a leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at its refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero.

In 2006, retail and wholesale sales in Italy amounted to 136 ktonnes with a 24.9% 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 102 ktonnes, of these about 50% were registered in Europe (mainly Germany, the Netherlands and Spain).

Oxygenates

Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sells about 2 mmtonnes/y of oxygenates, mainly MTBE (9% of world demand) and methanol. About 67% of products are manufactured in Eni’s plants in Ravenna, Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic), while the remaining 33% is bought from third parties. In Venezuela, Eni plans to convert its MTBE plants to the manufacture of isoethane, due to the environmental problems posed by MTBE.

 

Capital Expenditure

See "Item 5 – Liquidity and Capital Resources – Capital Expenditure 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.

In 2006, sales of petrochemical products (5,276 ktonnes) decreased by 100 ktonnes from 2005, down 1.9%. The main factors for the decline concerned: (i) basic petrochemicals (down 4.6%), due to lower product availability as a consequence of the outage of the Priolo cracker due to an accident occurred at the nearby refinery; (ii) elastomers (down 2.3%), due to a slow recovery of the Ferrara and Ravenna plant performance after maintenance activities carried out in the first half of the year; and (iii) intermediates (down 10.4%), due to weak demand. These negatives were offset in part by increased sales of polyethylene (up 3.2%) and aromatics (in particular, xylenes up 4.8%), reflecting good market conditions.

Production (7,072 ktonnes) declined by 209 ktonnes from 2005, down 2.9%, in particular in elastomers, polyethylene and basic petrochemicals, where lower production due to the standstill of the Priolo cracker was offset in part by higher production at the Porto Marghera, Sarroch and Dunkerque plants. Styrene production also increased, reflecting poor performance in 2005 from plant outages and technical issues.

Nominal production capacity was in line with 2005. Rising nominal capacity in a few crackers was offset in part by the outage of the Priolo cracker and related plants. Average plant utilization rate calculated on nominal capacity declined by 2 percentage points from 78.4% to 76.4%, mainly due to lower production volumes.

Approximately 35.2% of total production was directed to Eni’s own productions cycle (35.8% in 2005). Oil-based feedstock supplied by Eni’s Refining & Marketing Division covered 10% of requirements (23% in 2005).

Prices of Eni’s main petrochemical products increased on average by 12%; all business areas posted increases. The most relevant increases were registered in: (i) olefins (up 16.5%), in particular ethylene and propylene; (ii) aromatics (up 19.6%), in particular xylenes; (iii) polyethylene (up 12%) with increases in all products; (iv) styrenes (up 8.2%), in particular styrene and polystyrenes; and (v) elastomers (up 4.2%), in particular BR and TPR rubbers.

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

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(ktonnes)

Basic petrochemicals  

4,304

   

4,013

   

4,236

   

4,450

   

4,275

 
Styrene and elastomers  

1,538

   

1,635

   

1,606

   

1,523

   

1,545

 
Polyethylene  

1,274

   

1,259

   

1,276

   

1,309

   

1,252

 
   

 

 

 

 

   

7,116

   

6,907

   

7,118

   

7,282

   

7,072

 
   

 

 

 

 

Internal consumption  

(2,607

)  

(2,651

)  

(2,616

)  

(2,606

)  

(2,488

)
Purchases and change in inventories  

984

   

1,010

   

685

   

700

   

692

 
   

 

 

 

 

Total products  

5,493

   

5,266

   

5,187

   

5,376

   

5,276

 
 
 
 
 
 

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

 

Year ended December 31,

 
 

2002

 

2003

 

2004

 

2005

 

2006

 
 
 
 
 
 

(ktonnes)

Basic petrochemicals  

2,894

 

2,704

 

2,766

 

3,022

 

2,882

Styrene and elastomers  

1,151

 

1,171

 

1,038

 

1,003

 

1,000

Polyethylene  

1,448

 

1,391

 

1,383

 

1,351

 

1,394

   
 
 
 
 
Total sales  

5,493

 

5,266

 

5,187

 

5,376

 

5,276

   
 
 
 
 

 

Basic petrochemicals

Sales of basic petrochemicals of 2,882 ktonnes declined by 256 ktonnes from 2005, down 4.6%, mainly due to the outage of the Priolo cracker. Declines were registered in olefins (down 1.5%), intermediates (down 10.4%) and benzene (down 23%). Increasing sales in xylene (up 4.8%) and ethylene (up 3.2%) reflected higher product availability at other plants.

Basic petrochemical production (4,275 ktonnes) decreased by 175 ktonnes, down 3.9%. Lower production resulting from the Priolo cracker outage was offset in part by higher production at the Porto Marghera and Dunkerque.

Styrene and elastomers

Styrene sales (587 ktonnes) were slightly higher from 2005 (up 1.1%). Increasing sales in styrene reflected higher production availability. Declines were registered in compact polystyrene (down 1.5%) due to a lack of feedstock owing to the outage of the Priolo cracker and in ABS/SAN due to the outage of the EniPower power station with a negative impact on the Mantova plant.

Elastomers sales (413 ktonnes) increased by 1.2% from 2005 excluding the impact of the shutdown of the Champagnier plant in the second half of 2005. Increases concerned all products, with the exception of BR rubbers (down 8%) due to a maintenance standstill of the Ravenna Neocis plant.

Styrene production (1,088 ktonnes) increased by 3.8% reflecting mainly technical issues and a maintenance standstill that occurred at the Mantova plant in 2005.

Elastomer production (457 ktonnes) decreased by 1.3% excluding the impact of the shutdown of the Champagnier plant, due to a weak demand in BR (down 8.5%) and SBR (down 3.6%) rubbers. Production volumes of other rubbers increased in line with trends in demand.

Polyethylene

Polyethylene sales (1,394 ktonnes) were up 43 ktonnes or 3.2%, from 2005, reflecting positive market conditions for LLPDE (up 9.3%) and HPDE (up 1.5%). These increases were offset by a decline in EVA (down 3.7%) due to certain technical issues at the Oberhausen plant.

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Production (1,252 ktonnes) declined by 57 ktonnes, or 4.4%, mainly due to the standstill of the Priolo cracker and related plants.

 

Capital Expenditure

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

 

Engineering & Construction

Eni operates in engineering, oilfield services and construction both offshore and onshore through Saipem, a company listed on the Italian Stock Exchange (Eni’s interest 43%). Saipem boasts solid competitive positions in the relevant markets thanks to technological and operational skills, engineering and project management capabilities and ability to operate in complex environments, owing also to the integration with Snamprogetti. Leveraging on these strengths and rising demand for drilling equipment and oilfield services, Saipem intends to carry out the following fundamental strategies: (i) gain market share in the field of large offshore and onshore projects for the development of hydrocarbon fields; (ii) develop its presence in the strategic field of gas monetization and heavy crude upgrading, including expansion in floating LNG treatment systems for liquefaction and regasification of LNG; (iii) intensify efficiency improvement actions in all its activities, in particular by reducing supply 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; and (iv) support Eni’s investment plans.

Orders acquired in 2006 amounted to euro 11,172 million. Approximately 91% of new orders acquired were represented by work to be performed outside Italy, and 24% by work originated by Eni companies. Order backlog was euro 13,191 million at December 31, 2006 (euro 10,122 million at December 31, 2005). Projects to be carried out outside Italy represented 90% of the total order backlog, while orders from Eni companies amounted to 20% of the total.

     

2004

 

2005

 

2006

     
 
 
Orders acquired  

(million euro)

 

5,784

 

8,395

 

11,172

Offshore construction      

2,867

 

3,096

 

3,681

Onshore construction      

2,535

 

4,720

 

4,923

Offshore drilling      

107

 

367

 

2,230

Onshore drilling      

275

 

212

 

338

Originated by Eni companies  

(%)

 

14

 

11

 

24

To be carried out outside Italy  

(%)

 

90

 

90

 

91

Order backlog  

(million euro)

 

8,521

 

10,122

 

13,191

Offshore construction      

3,420

 

3,721

 

4,283

Onshore construction      

4,488

 

5,721

 

6,285

Offshore drilling      

317

 

382

 

2,247

Onshore drilling      

296

 

298

 

376

Originated by Eni companies  

(%)

 

8

 

7

 

20

To be carried out outside Italy  

(%)

 

84

 

88

 

90

     
 
 

 

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 world-class fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the market over recent years. Saipem intends to enhance its market share by means of strengthening its EPIC oriented business model and its relationships with major oil companies and NOCs. Higher levels of profitability are expected to be achieved through outsourcing certain engineering and building activities to low cost centers. Investments will be focused on constantly upgrading and improving technical characteristics and capabilities of Saipem’s world-class fleet, and to build local construction centers.

Its offshore construction fleet is made up of 25 vessels and 45 robotized vehicles able to perform advanced subsea operations. Among its major vessels are: (i) Saipem 7000, a semi-submersible vessel with dynamic positioning system, with 14 ktonnes of lift capacity (the highest of this kind in the world), capable to lay pipelines using the J-lay technique to the maximum depth of 3,000 meters.

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This vessel has been used to lay the Blue Stream pipeline in the waters of the Black Sea at the record depth of 2,150 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, derived from the transformation of the Maxita that can lay rigid and flexible pipes and is 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.

In February 2007, a contract for the construction of a new pipe layer has been signed. The unit, with a carrying capacity of 25 ktonnes and a lifting capacity of 600 tonnes by means of crane, will be manufactured in China.

The most significant orders won in 2006 in Offshore construction were: (i) a contract for the conversion of an oil tanker into an FPSO unit with production capacity of 1.8 mmBBL for the development of the offshore Gimboa field in Angola for Sonangol P&P; an EPIC contract for Burullus Gas Co for the construction of underwater systems for the development of eight new wells within the expansion plan of the Scarab/Saffron and Simian fields offshore in the Nile Delta; an EPIC contract for CNR International Ltd for the construction of three wellhead towers, a support platform, and interconnecting pipelines and umbilicals within the development of the offshore Olowi field in Gabon.

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 sulfur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem intends to capture opportunities arising from expected increasing demand from oil majors, by leveraging on its solid competitive position and integration with Snamprogetti engineering capabilities.

The main operation areas are 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 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 won in 2006 in Onshore construction were: (i) an EPC contract for Saudi Aramco for the construction of four trains for gas and crude separation with a total capacity of 1.2 mmBBL/d and production facilities within the development of the onshore Khursaniyah field in Saudi Arabia; (ii) an EPC contract for Shell Petroleum Development Co of Nigeria for the laying of pipelines, flowlines and composite fiber optic and high voltage electrical cables within the development Gbaran project. The contract was won in consortium with Desicon Engineering Ltd; and (iii) an EPC contract for Canaport LNG for the construction of a regasification terminal, inclusive of auxiliary facilities for gas offloading, pumping, vaporization and transmission, in addition to two storage tanks. The contract was won in consortium with the Canadian company SNC - Lavalin.

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 holes at a maximum depth of 9,200 meters. Demand for drilling services is expected to increase in future years reflecting exploratory and development plans of oil majors, leading to a substantial rise in tariffs due to current equipment shortage. In view of this, Saipem is planning to build a new drilling rig capable of reaching a 10,000 meter drilling depth.

Its offshore drilling fleet consists of 10 vessels properly 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 can 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.

The most significant contracts awarded in Offshore drilling during the period include: (i) a 16-month long contract for the use of the semi-submersible drilling platform Scarabeo 7 in Nigeria for ExxonMobil; (ii) a 49-month long contract for the use of the semi-submersible drilling platform Scarabeo 5 in Norway for Statoil; and (iii) a 27-month long contract for the use of the semi-submersible drilling platform Scarabeo 3 in Nigeria for Addax Petroleum.

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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 Peru, where it can leverage on its knowledge of markets, long-term relations with customers and integration with other business areas. Onshore drilling is conducted through 23 drilling platforms and 15 workover plants that can drill to 10,000-meter depths in high pressure and high temperature environments.

The most significant orders won in 2006 in Onshore drilling were: (i) the first one for PDVSA the charter of a rig in Venezuela for five years; and (ii) the second one for EniRepsa, the charter of a rig in Saudi Arabia, due to perform the drilling of four wells, plus the option of a further two wells. The duration of this contract is estimated at approximately two years.

 

Capital Expenditure

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

 

Other activities

Eni’s other activities are organized as follows:

  "Other activities" include only Syndial SpA (former EniChem) which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni divested in past years.
  "Corporate and financial companies", including Eni Corporate and some of Eni’s subsidiaries engaged in treasury and other services. Eni Corporate is the department of parent company Eni SpA performing Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Enifin SpA, Società Finanziamenti Idrocarburi - Sofid SpA, Eni International BV and Eni Insurance Ltd, Eni carries out lending, factoring, leasing and insurance activities, principally on an intercompany basis. It also encompasses Eni Corporate University, AGI and other subsidiaries engaged in diversified activities (mainly services to Eni business segments, such as real estate services, general purposes services, corporate research and training). Enifin was incorporated into the parent company Eni SpA effective January 1, 2007.

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.

 

Research and Development

Eni’s commitment to technological research and innovation underscores a fundamental belief that technology is key to increase our competitive advantage over the long-term and to promote sustainable growth. Future global challenges require ingenuity and commitment: from the environmental and climate issues to the increasingly difficult access to hydrocarbon reserves large, but mainly controlled by producing countries; from the identification of relevant discontinuities in the production of energy from renewable sources to the optimization of production processes up to the resolution of problems existing in countries where Eni has been present for a long time or where it recently entered.

Eni is conducting research 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 intends to invest euro 1.5 billion to support its research and development (R&D) strategy. More specifically, Eni’s main R&D fields regard:

  reserve replacement and reduction of mineral risk;
  production and monetization of non-conventional hydrocarbon reserves and optimal management of reserves with high hydrogen sulfide and sulfur content;
  delivering more gas to market, monetizing associated gas and stranded gas;
  improvement of fuel quality and performance in light of the evolution of engines to increasingly perfected and efficient systems with lower impact on the environment; and

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  efficient use of fossil fuels through an improvement in refining yields and an optimal use of each fuel entailing a lower environmental impact.

With regard 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. 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 2006 Eni invested euro 222 million (euro 204 million in 2005), of these 39% were directed to the Exploration & Production segment, 32% to the Refining & Marketing segment, 22% to the Petrochemicals segment and 7% to the Engineering & Construction segment.

At December 31, 2006, a total of 1,160 persons were employed in research and development activities. In 2006 a total of 39 applications for patents were filed.

A description of the main technologies under development or currently applied is provided below.

ADVANCED DRILLING SYSTEMS AND WELL TESTING
Eni developed significant industrial applications of innovative technologies enabling to drill highly complex wells with greater operating efficiency.

The "Geosteering" project developed by Eni in joint venture with Shell aims at the development of technologies capable of providing geological information on not yet drilled layers (around the scalpel up to the surface) while drilling.

In 2006, various downhole prototypes have been made and in the second half of the year the technology was tested in a well. Testing is expected to continue until the first half of 2007.

Referring to drilling activities, some new technologies have been tested:

  Extreme Lean Profile, development of "slim" well techniques applicable to narrow wells;
  Eni Circulation Device, avoids the danger of "keep of the bars" during the drilling activity;
  Light Drill Pipe, based on the use of aluminum bars in strongly deviated wells; and
  Zero Emission Well Testing, a field evaluation methodology by fluid injection (with no emissions) based on know-how and Eni’s software, as opposed to conventional pre-production tests.

NUMERIC AND HIGH RESOLUTION GEOPHYSICAL PROSPECTING TECHNIQUES
Development of the "Steam 3D" oil system simulator, able to represent the evolution of complex geological structures over time, has been completed. Development continues on the proprietary CRS technology (3D Common Reflection Surface Stack) which aims to allow prospecting in areas characterized by low seismic response.

First application of the following technologies has been done:

  CSEM (Controlled Source ElectroMagnetic), which enables Eni to collect data prior to drilling with regard to the presence of hydrocarbons, reducing exploration risk and increasing the reliability of reservoir measurements through electric resistivity of the seabed;
  "Multipoint Statistic" and "Process Oriented Modeling" which help identify and locate producible reserves in a specific reservoir;
  "Integrated Asset Modeling", which optimizes the development and the production of a field through the integration of oilfield models and onshore facilities;
  First application of a proprietary technology specifically aimed at "tight reservoirs" which assists in foreseeing the productivity increase achievable through operations on induced fractures.

SULFUR MANAGEMENT
In 2006 the integrated research program Sulfur and H2S management in E&P operations related to the handling of gas with high H2S content has been completed. An innovative proprietary system called Concrete Wall for the massive storage of sulfur and a bulk removal technology of H2S have been developed. In 2007 demonstration facilities for the handling and storage of sulfur are expected to be developed along with a study regarding the behavior of materials in very acidic environments and under extreme pressure and temperature conditions.

GAS TO LIQUIDS (GTL)
The conversion of gas to liquids is a key technology for the use of natural gas on a large scale for the production of high quality fuels, in particular diesel fuel, and therefore it receives special attention by all oil majors due to its strategic value.

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In 2006 in cooperation with IFP/Axens, Eni completed the technology handbook for this proprietary technology for the conversion of gas to liquids via Fischer-Tropsch synthesis and the basic engineering of a 37 KBBL/d industrial unit.

In 2007 some issues will be addressed regarding the risks of the transition to the subsequent industrial scale:

  mechanic validation on the maximum industrial scale of the catalyst for the FT synthesis;
  validation by qualified builders of the mechanic design of the reactor to be applied to the maximum industrial scale; and
  tweak of a water treatment scheme produced in the synthesis process.

CONVERSION OF HEAVY CRUDE AND FRACTIONS INTO LIGHT PRODUCTS
Testing continued at the Taranto demonstration plant of Eni’s proprietary technology EST, a process of catalytic hydroconversion in the slurry phase of non conventional crude, extra heavy crude and refining residues that allows the refinery to convert asphaltenes (the hard fraction of heavy crude) totally into naphtha, kerosene, diesel fuel. In particular, a four-month test period has been carried out using a residue from a Canadian tar sand, confirming expected conversion yields and performance stability. In 2007 Eni plans to complete the collection of information for designing and building its first industrial plant.

SCT-CPO PROJECT (SHORT CONTACT TIME - CATALYTIC PARTIAL OXIDATION)
At the Milazzo research center the SCT-CPO (partial catalytic oxidation with short contact time of liquid and gaseous hydrocarbons) technology has been validated on the pilot scale for producing hydrogen at competitive costs, also in medium to small sized plants with higher flexibility as compared to refinery feedstocks. In 2007 Eni plans to complete the collection of information for designing and building its first industrial plant.

NATURAL GAS HIGH PRESSURE TRANSPORT (TAP)
The goal of the TAP project is to develop Long Distance - High Capacity - High Pressure - High Grade technology with the following features:

  transportation on distances greater than 3,000 kilometers;
  20-30 BCM of natural gas conveyable per year;
  pressure equal to or greater than 15 MPa; and
  use of high and very high grade steel.

This technology allows Eni to greatly reduce natural gas consumption for the operation of compressor stations. In 2006 testing continued on two existing infrastructures:

  a 10-km (6-mile) long, high-resistance X80, steel line integrated in the Snam Rete Gas system; and
  two pilot high-resistance X100 steel lines (a total length of 750 meters) able to support fluctuating pressure in a range of 135 to 150 bar.

After completing the pressure test on these two pilot lines, a crack propagation test has been scheduled for one of the two.

In 2006 the first version of the Technology Handbook has been published and a hypothetical 3,400-kilometer long gas pipeline in X100 steel has been designed connecting Karachaganak oilfield (Western Kazakhstan) with Central Europe.

ENVIRONMENTAL PROTECTION
Development of technological solutions aimed at minimizing the environmental impact of exploration, refining and utilization of hydrocarbons continued throughout 2006.

The opportunity to test the conversion of CO2 in energy vectors via biofixation on a demonstrative scale will be evaluated in 2007.

Main activities carried out or undertaken in 2006 include the following:

  Green Diesel - the project aims at the production of biodiesel in refineries by means of a new process of hydrocracking of vegetable oils developed in collaboration with an international partner;
  Ensolvex - the project is aimed at the further industrial application of the process for reclaiming soils polluted by organic substances; and
  EWMS (Early Warning Monitoring System) - the activity consist in the application of research findings of an advanced control and remote monitoring project.

GHG PROJECT (GREENHOUSE GASES)
Work continued on the integrated Greenhouse Gases research program, aimed at verifying the industrial feasibility of the geological sequestration of CO2 in depleted fields and salty aquifers. The technical feasibility study of the geological sequestration of CO2 has been completed and in 2007, Eni expects to start testing in the field.

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REFORMULATION OF FUELS AND LUBRICANTS
Eni continued its program to improve its "Blue" fuel line of products (BluDiesel and BluSuper). It also started a new phase of its clean diesel fuel program aiming at identifying the optimal formula for a diesel fuel with high performance and low particulate emissions using as benchmark GTL Fischer-Tropsch diesel oil (obtained from the conversion of natural gas into liquids - GTL project). Research activities will be conducted on the design of refining facilities for producing this product.

A process of hydro-dearomatization of certain refining feedstock with a high content of aromatics (e.g. the light cycle oil produced by fluid catalytic crackers) is being developed. A double-function, proprietary catalyst has been developed able to reduce hydrogen consumption and certain by-products. The project is progressing on a pilot scale.

Monitoring on the mock-up distribution of the "ADBlue" in the Agip corner sale, at Assago Ovest (Milan) continued. The ADBlue (water solution with urea at 32.5%) can be used to remove nitrogen oxide (NOx) from exhaust gas of Diesel commercial motors with catalytic disposal for the selective reduction of NOx (Selective Catalytic Reactor).

BIO FUEL AND HEAVY CRUDE CONVERSION: DEAL WITH PETROBRAS
As part of the development of technologies for fuel quality enhancement and the conversion of heavy crude and fractions into light products, in March 2007 Eni signed an agreement with Petrobras, the world’s leading company in the large-scale production of bio-ethanol. The two partners will combine their proprietary technologies to jointly develop projects for the production of bio-fuels in other countries.

In addition, they will study joint projects to assess the application of the Eni Slurry Technology (EST) in Brazil in the framework of a broader partnership involving both upstream and downstream joint initiatives.

 

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, petrochemicals 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 on Eni’s activity follows.

Decree No. 152/2006 "Environmental legislation" based on the Law No. 308/2004 "Government Delegated law for the reorganization, coordination and integration of legislation on the environment and measures of direct application" was published in Gazzetta Ufficiale No. 88 of April 14, 2006 and came into force on April 29, 2006.

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The Decree No. 152/2006 has reformulated the whole Italian environmental law with the major focus on the environmental impact assessment, strategic environmental assessment, soil protection, water protection, waste management and remediation for contaminated sites, air protection and reduction of emissions into the atmosphere and environmental liability. This Consolidated Act on the Environment introduces important changes and revisions of the previous environmental laws in the field. The most important revisions for Eni’s activities concern waste management, remediation for polluted sites, water protection and environmental liability.

The fourth part of Decree No. 152/2006 relating waste management and remediation of polluted sites introduces a new waste, by products and safety measures (for operational sites) definition, modifies the notion of discharge, soil and rock excavations, responsibility range of willful owner, temporary deposit (for hazardous and non hazardous products, with or without quantitative limits). Also a new approach to site contaminations is implemented based on risk analysis determining the need for remediation and defining specific site objectives and their extent.

These provisions are under review following a proposed decree already approved by the State-Regions Conference, providing for the limits approach for the sites where reclamation and remediation activities have begun under the previous regulatory framework (Decree No. 471/1999). This modification backed by the State-Regions Conference could result in an increase in future environmental expenses that Eni expects to incur for site remediation and reclamation.

The third part of the Decree No. 152/2006 regulates water protection, modifying the previous legislation and implementing the Water Framework Directive (2000/60/CE, so called WFD). The objective of this section of the Decree No. 152/2006 is to enact the requirements of the WFD and to guarantee the achievement of certain water quality objectives by 2015 as foreseen by the WFD. In order to achieve this target, all the water bodies must comply with specified fixed quality standards by December 31, 2008 ensuring the achievement on an intermediate water quality objective in view of the 2015 deadline. The legislator introduces a new definition of the discharge according to which every direct discharge to soil, subsoil and groundwater containing pollutants is prohibited. All discharges of industrial waste water to superficial waters must comply with defined limits and must be previously authorized. The authorization must be renovated every four years and requested one year in advance.

However, there can be no assurance that there will not be a material adverse impact on Eni’s operations due to measures adopted by local authorities whenever the quality of a certain water source does not comply with set standards due to the industrial activity of all plants located above that water source. Moreover, there is the risk of mandatory closure for industrial plants, in case a request for the authorization of discharge of dangerous substances is filed with a public administration with no response within a set deadline (up to six months).

The sixth part of the Decree No. 152/2006 concerns the overall regulation of the environmental liability and implements the Directive 2004/35/CE. The Decree introduces a new definition of environmental damage and indicates specified cases of its application. According to the legislation the environmental damage is any significant and measurable deterioration, direct or indirect, of the natural resources or of its utility. The principal objective is prevention and remediation of environmental damage and restoration to the previous condition. The eventual impact on Eni’s activities might be significant in the case of the recognized responsibility for environmental damage. In this situation, Eni could be obliged to remediate to the previous condition or provide compensation.

Directive 96/61/CE: the purpose of the Integrated Pollution Prevention and Control (IPPC) is to ensure a high level of protection of the environment taken as a whole, covering emissions into air, water and land, generation of waste, use of raw materials, energy efficiency, noise, prevention of accidents, and restoration of the site upon closure. According to this Directive, operators of industrial installations, covered by Annex I of the IPPC Directive, are required to obtain an authorization (environmental permit) from the authorities in the EU countries. New installations, and existing installations which are subject to "substantial changes", have been required to meet the requirements of the IPPC Directive since October 30, 1999. Other existing installations must be brought into compliance by October 30, 2007. This is the key deadline for the full implementation of the Directive.

On May 7, 2005, Italian Legislative Decree No. 59/2005 (Gazzetta Ufficiale No. 93 - April 22, 2005) entered into force in complete accordance with the European Directive (IPPC), abrogating definitively the Legislative Decree No. 372/1999. In compliance with the calendars published by the competent authority, local and/or National, all Eni installations under the IPPC Directive, have presented the requested authorizations in accordance with the format and criteria published in the DEC February 7, 2007.

According to the IPPC Directive, the Member States of the EU had to communicate their national values of emissions into the atmosphere, wastes produced and managed and, finally, discharges into water of certain compounds specified in the annexes of the directive related to EPER (European Pollutant Emission Register). Eni plants under the Directive have reported their data to the authority in charge of preparing the Italian national communication.

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Regulation No. CE/166: in January 2006 the EC was issued the Pollutant Releases and Transfers Register (PRTR), which is an extension of the previous EPER registers and deals with all the emissions and transfers of 91 pollutants to air, water, soil and transfer off-site of hazardous and non hazardous wastes. Recently the European Commission has been published in GUEE May 16, 2007 (2007/C 110/01) the definitive replacement of the EPER Register by the European Pollutant Release and Transfer Register (E-PRTR).

The PRTR registers will be operational in the year 2009, with respect to 2007 environmental data. To comply with the obligations, Eni is implementing a Group wide Integrated Environmental Information System, able to gather, manage and report all the pollutants requested by PRTR Regulations.

 

HSE Activity for the Year

Eni is committed to continuously improve its model for HSE Integrated Management System and its HSE culture to challenge the best in class among the competitors, to meet the evolving sustainability requirements for the energy industry and to minimize the risk associated with all its activities. This commitment produced a significant renewal of the HSE Corporate organization in 2005 and consequently the related processes have been subjected to a campaign of assessment and improvement; this has led first to the reengineering of the Company guidelines on health, safety, environment and public safety.

In 2006 Eni’s business units continued to obtain certifications of their management systems and operating units according to the most stringent international standards. As of December 31, 2006, the total number of certifications obtained was 185 (155 in 2005), of which 90 certifications according to the ISO 14001 standard and 6 certifications according to the EMAS standard. EMAS is the Environmental Management and Audit Scheme recognized by the European Union.

Environment In 2006, Eni incurred a total expenditure of euro 1,160 million for the protection of environment, up 7% from 2005. Current environmental expenditure represented approximately 66% of the whole expenditure and related mainly to costs incurred with respect to remediation and reclamation of certain industrial sites divested in the past, mainly in Italy. Capitalized environmental expenditure related mainly to soil and subsoil protection, water management and air emissions.

Safety Eni considers of capital importance the safety of its workers and contractors, of the people living in the area where its industrial activities are located and of its assets, whether producing now or in the future. Its strategy has been based on:

  the dissemination of a safety culture within its organization; and
  minimization of exposure to risk in all production activities.

The most important instruments for implementing this strategy are: the close contact with the Eni organizations in the field by dedicated assessments and the continuous upgrade of the safety system, technical guidelines and procedures, to meet the evolving international standards.

As of December 2006 a total of forty-eight international subsidiaries have been assessed in twenty-one countries, thirteen of them twice in a three year cycle. These assessments in the field are one of the most important sources for all the improvement of the safety system.

From both the field assessments and the safety data analysis and benchmarking the most important safety technical guideline in year 2006 has been generated; it is the technical guideline on vehicles driving in non-EU countries, where for the first time instruments like risk assessments and dedicated management system have been used in this field.

In 2006, safety indicators improved from 2005. The injury frequency rate was 3.07, down 3%, and the injury severity rate was 0.09, down 10% from 2005. Costs incurred to boost the safety levels of operations and to comply with applicable rules and regulations were euro 394 million.

Health Activities for the protection of health aim at improving general work conditions and are developed according to three main principles:

  protection of employees’ health;
  prevention of accidents and professional diseases; and
  promotion of healthier behaviors and life styles in workplaces.

Eni has a network of 307 health care centers located in its main operating areas, of these 217 centers are outside Italy and are managed by expatriate and local staff (415 doctors and 442 paramedics). A set of international agreements with the best local and international health centers guarantees efficient service and timely reactions to emergencies.

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In 2006, Eni boosted its E-medicine program aimed at increasing the quality of health care provided to employees and to health operators within and outside Italy, that integrates computerized technologies and advanced telecommunication systems.

Eni started a program of prevention for its employees, both through information campaigns and by means of screening procedures and direct actions accessed on a voluntary basis. In the area of prevention of infective diseases, Eni continued its campaign for vaccination against flu that is widely followed by employees.

Outside Italy, Eni promoted specific information campaigns for the protection of its employees, their families and local communities, such as those for the prevention of malaria (in Nigeria) and the prevention of HIV transmission (in Nigeria and Congo).

For employees hired in Italy and working outside Italy, Eni has a specific program that includes training on the specific health risks they might encounter in each country and information on how to cope with them.

Eni also entered an agreement with International SOS that provides qualified health services throughout the world, as well as repatriation in case of serious emergency situations.

In 2006 Eni incurred a total expense of euro 48 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 1990 values. Reductions can be achieved both through internal measures and through a series of instruments supplementary to internal measures. These are the so-called flexible mechanisms, which allow 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 emissions credits and to purchase Assigned Amount Units (AAUs) from other Annex I countries, that have a surplus of these Kyoto units (IET - International Emission Trading).

Italy, as an EU Member State, is participating in the EU Emission Trading Scheme, regulated up by the Directive 2003/87/EC, which established on January 1, 2005 the largest carbon market in the world, setting up a system for emission trading targeted to industrial installations with high carbon dioxide emissions.

As foreseen by the Directive, Italy has issued two National Allocation Plans covering the periods 2005-2007 and 2008-2012, which set out the allowances assigned to each sector and installation. Eni has cooperated with the Italian authorities responsible for the preparation of the National Allocation Plan and is also 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.

Law No. 216 of April 4, 2006 has implemented at national level the European directive 2003/87/EC. In the first period of commitment (2005-2007), emissions not covered by corresponding allowances are subject to a fine amounting to euro 40/tonne of carbon dioxide. All companies are expected to identify and carry out projects for emission reductions. Eni participates in the ETS scheme with 58 plants in Italy and 2 outside Italy, which collectively represent about a third of all greenhouse gas emissions generated by Eni’s plants worldwide. Eni was assigned, for the existing installations, allowances equal to 65.6 mmtonnes of carbon dioxide (of which 22.4 for 2005, 22.4 for 2006 and 20.8 for 2007). Moreover, further allowances will be issued for new entrants during the period 2005-2007 (12.8 mmtonnes of carbon dioxide). Following the implementation of projects for the reduction of emissions, in particular related to the cogeneration of electricity and steam through high efficiency combined cycles in refineries and petrochemical sites, emissions of carbon dioxide from Eni’s plants were lower than permits entitled in both 2006 and 2005.

In order to play an active role in the ETS Eni:

(i)   prepared a methodological and organizational protocol for the accounting of greenhouse gases emissions;
(ii)   implemented a database for a precise evaluation of emissions;
(iii)   evaluated the compliance of existing monitoring and reporting systems in plants in order to identify improvement requirements; and
(iv)   defined a system for balancing emissions from individual plants and business units in order to guarantee the payback of emission rights due.

Eni is also upgrading its ongoing program for the reduction of energy consumption and related CO2 emissions.

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A significant reduction potential can be derived from production activities outside Italy, that in some cases, given the 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 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. 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 a 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.

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In principle, the license holder is entitled to all production minus any royalties that are payable in kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area.

In Product Sharing 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

The right to store natural gas in depleted fields in Italy is exercised pursuant to concessions granted by the Ministry of Productive Activities. The duration of a concession is 20 years, with the possibility for operators of obtaining at most two ten-year extensions if they complied with the storage programs and other obligations deriving from said concession as per Law No. 239/2004. After the expiration of a concession, new storage concessions on the same field may be granted through competitive auctions. Pursuant to Decree No. 625/1996, unused storage capacity can be made available to third parties, subject to the approval of the Ministry, on a negotiated basis. Until December 31, 1996, Eni had the exclusive right to store natural gas in depleted fields located in a predetermined area (the so called Exclusive Area). Decree No. 625 eliminated this exclusive right, while granting Eni the right to obtain upon application the storage concessions effective from January 1, 1997 that would preserve the rights vested with Eni during the regime of exclusivity (based on current storage activities or certain statutory conditions). Eni obtained the ten storage concessions which it had applied for.

Legislative Decree No. 164/2000 ("Decree No. 164"), which enacted the European Directive on Natural Gas 98/30/CE into Italian legislation, regulates the Italian natural gas market. Prior to the implementation of Decree No. 164, the Italian natural gas market lacked a legislative framework.

The most important aspects of Decree No. 164 concerning production and storage activities performed by Eni 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 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.

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Existing storage concessions are subject to the Decree. Their original term was confirmed and includes relevant production concessions; (ii) 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; (iii) 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; (iv) modulation storage costs are charged to shippers which have to provide modulation services adequate to the requirements of their final customers; (v) 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 (vi) the Authority for Electricity and Gas establishes the criteria and priority of access storage operators have to include in their own storage codes.

In compliance with the provisions of Article 21 of Decree No. 164/2000, on October 21, 2001 all storage activities carried out within the Eni Group were conferred to Stoccaggi Gas Italia SpA ("Stogit"), which holds ten storage concessions.

In implementation of Decree No. 164, the Decree of the Minister of Productive Activities of September 26, 2001 defined the criteria for the determination and use of strategic storage. The utilization of natural gas volumes held under strategic storage becomes mandatory in case of interruption or reduction of imports from non-EU countries due to technical and unpredictable causes, in case of emergency on the national gas network, in case of winters colder than those expected by the Authority for Electricity and Gas in its periodic statements concerning the determination of modulation obligations for seasonal consumption peaks.

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.

Storage tariffs are articulated as follows:

(i)   a unit fee for the use of space;
(ii)   a unit fee for the use of injection capacity;
(iii)   a unit fee for the use of off-take capacity;
(iv)   a unit fee for gas volumes handling; and
(v)   a unit fee to remunerate gas availability to enable gas operators to fulfill their strategic storage obligations.

Applicable regulation provides for incentives to capital expenditure 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.

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 disciplines access to and provision of storage services during normal operational conditions, regulates procedures for conferring storage capacities, fulfillment of obligations concerning operating programming and fees to be charged to customers. 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.

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The modulation storage service is finalized to satisfy 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 is finalized 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 is destined 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 assigned 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 off-take capacity is assigned according to the following order of priority to: (i) holders of production concessions requesting mineral storage services; (ii) entities deploying natural gas sale activities who are obliged 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 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. A procedure to be issued by the Authority for Electricity and Gas will establish the criteria for assigning capacity when the requests mentioned in (iv) above exceed availability.

During the storage thermal year, the company makes new assignations when new capacity becomes available. Users are allowed to sell to each other volumes of gas injected or capacity assigned. Users are requested to transmit to the storage company one week in advance of the next, programs for injection or off-take, within the limit of assigned capacity, confirming each day the bookings for the following day.

Fees deriving from balancing activities and restoration of strategic volumes off-taken are regulated by certain prescriptions from the Italian Authority for Electricity and Gas providing for repartition of such fees among customers of storage services until the 2005-2006 thermal year. Resolution No. 50/2006 changed such regime by establishing that such fees cover revenues deriving from new investment.

If the volumes input to storage are higher than the capacity assigned or the input capacity utilized is higher than that conferred than and the user does not purchase additional capacity or sell excess natural gas volumes within 15 days from receiving information on its position, the storage company shall: (i) apply to the maximum exceeding volume or the maximum input capacity utilized in a month a balancing charge depending on the length of the infringing period or the month in which the capacity overuse has occurred; and (ii) sell, on behalf of the user that has not yet done it, the volume of gas injected exceeding the assigned capacity in the day or days of the thermal year of storage in which working gas reached its maximum amount, if the transport company reduced the volumes planned by users of transport at one or more interconnection points at the border and the same transport users also hold storage capacity.

If the user employs an off-take capacity higher than the assigned capacity, the storage company applies, for each month to the maximum difference between peak daily capacity actually used and peak daily capacity entitled, a charge depending on the number of days of exceeding use.

If the volumes of gas off-taken by a user are higher than those held in storage and the user fails to replenish by means of a purchase, charges are applied that relate to replenishment of off-take from strategic storage, including payment of a charge applied to the maximum accumulated volumes of off-taken gas, net of an income proportional to volumes replenished, according to different amounts based on the circumstance that the off-take was authorized or not by the Ministry of Productive Activities.

On the basis of these provisions, Eni may incur material charges for storage services in case of unauthorized off-takes from the strategic reserve. Eni appealed against this decision.

With Resolution No. 266/2005 the Authority for Electricity and Gas started an inquiry leading to a possible administrative sanction (fine under Law No. 481/1995) alleging that Stogit’s behavior does not conform with the discipline contained in Resolution No. 119/2005 concerning access to and provision of storage services.

Eni also 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, 2006 Eni held approximately 180 BCF of strategic reserves of natural gas (180 BCF at year end 2005).

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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) from January 1, 2003 to December 31, 2010 no single operator is allowed to hold a market share higher than 50% of domestic sales to final customers. In addition, no single operator is allowed to supply more than 75% of all natural gas volumes introduced in the domestic transmission network by 2002, decreasing by 2 percentage points per year until it reaches 61%. Compliance with these ceilings is verified annually by comparing the allowed average percentage on a three-year basis for volumes input or sold to the average percentage obtained by each operator in the same three-year period. Allowed percentages are calculated net of losses (in the case of sales) and volumes of natural gas consumed in own operations. In accordance with Article 19, paragraph 4 of Legislative Decree No. 164/2000 the volumes of natural gas consumed in own operations by a company or its subsidiaries are excluded from the calculation of ceilings for sales to end customers and for volumes input into the Italian network to be sold in Italy; (iii) imports from the European Union are free, while natural gas imported from outside the European Union is subject to an authorization of the Ministry of Productive Activities. Subjects importing from countries outside the EU must secure a certain availability of strategic storage. Such constraints apply also to the import contracts entered into before the coming into effect of Decree No. 164, these contracts are automatically considered authorized since this date; (iv) 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 may not perform other gas related activities. Sale activity to final customers is compatible only with import, export and production activities and is subject to an authorization from the Ministry of Productive Activities. Concessions for the distribution of natural gas will be assigned only through an auction procedure; and (v) 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 particular 2006 closes the third three-year regulated period for natural gas volumes input in the domestic transmission network (for which the allowed average percentage is 69% 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). 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 34 prohibits undertakings active in the field of natural gas and electricity with a concession for local public services or for the management of networks (excluding all sale activities) from operating in a competitive market for post-counter services, in the areas where they hold the concession for the duration of the concession, including through subsidiaries or affiliates;
  paragraph 51 cancels paragraph 5 of Article 16 of Legislative Decree No. 164/2000, which obliged distribution companies to ascertain the safety of plants which do not only supply gas to productive units and safety of post-counter services; and
  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 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.

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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 redetermined 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. See below for a discussion of natural gas prices of sales of natural gas to residential and commercial customers which were not eligible customers until December 31, 2002.

The Presidential Decree dated October 31, 2002 conferred to the Authority for Electricity and Gas, also after the opening up of markets set at January 1, 2003 for customers who were not-eligible customers until December 31, 2002, the powers to: (i) define, calculate and update and gas selling prices also after the opening up of markets set at January 1, 2003 for customers who were not-eligible customers until December 31, 2002; (ii) define methods for updating selling prices with reference to variable costs that minimize the impact of inflation; and (iii) define criteria for allocating the costs deriving from social support measures, in order to reduce the aggregate net cost of interventions as much as possible and to ensure neutrality in the application of selling prices to the various groups of users. 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 concern the schedules 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 application quarter (from the preceding six months to the preceding nine months). 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, redefined the tariffs for the period January 1, 2005-March 31, 2007 and established a new indexation mechanism for the raw material cost component in natural gas supplies to customers consuming less than 200,000 CM/y (mainly residential and commercial customers located in urban centers), organizing in a single measure all its resolutions on 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 resolutions); (ii) waiving this provision, it reviewed the updating of the raw material cost component for 2005 reaching incremental values equal to those deriving from the application of the indexation criteria of Resolution No. 195/2002; this cancels 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 valid in the January, 1 2006-June 30, 2006 period, offer their customers new contractual conditions consistent with the new indexation mechanism before June 4, 2007, and inform the Authority, before June 29, 2007, together with their wholesaler that they have complied with this requirement.

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Selling companies complying with this requirement will 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 the first quarter of 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 – Recent Developments".

The mechanism initially implemented by the Authority for Electricity and Gas with Resolution No. 248 of December 29, 2004, had changed the indexing mechanism concerning the raw material component in tariffs paid by end customers consuming less than 200,000 CM/y, who were non-eligible customers until December 31, 2002 according to Resolution No. 195/2002. The decision introduced the following changes: (i) establishment of a cap set at 75% for the changes in the raw material component if Brent prices fall outside the 20-35 $/BBL range; (ii) change of the relative weight of the three products making up the reference index of energy prices whose variations – when higher or lower than 5% as compared to the same index in the preceding period – determine the adjustment of raw material costs; (iii) substitution of one of the three products included in the index (a pool of crudes) with Brent crude; and (iv) reduction in the value of the variable wholesale component of the selling price by 0.26 euro /CM. Eni accrued provisions in its 2005 financial statements and in the accounts of the first half of 2006 with respect to the estimated impact of Resolution No. 248.

Resolution No. 248 was opposed by several Italian natural gas operators, among which Eni, who claimed its legitimacy against the administrative tribunal. In the meantime the administrative proceeding on Resolution No. 248/2004 was running its course, effective July 1, 2006 the Authority implemented Resolution No. 134/2006, which modified Resolution No. 248/2004 as follows: (i) it established a cap set at 75% for the changes in the raw material component if Brent crude prices fall below 20 $/BBL or inside the 35-60 $/BBL range and at 95% if Brent crude prices are higher than 60 $/BBL (in Resolution No. 248/2004 the price cap was set at 75% for the change in the raw material component if Brent crude prices fell below 20 $/BBL or exceeded 35 $/BBL); and (ii) it changed from 5% to 2.5% the limit to variations in the index of energy prices which trigger the adjustment of raw material costs. In addition, it confirmed the obligation already envisaged by Resolution No. 248/2004 on charge of Italian suppliers to wholesalers to renegotiate supply contracts in light of the price revision introduced by same decision in supply contracts between wholesalers and end users. The changes introduced by Resolution No. 134/2006 apply for a two-year period with the option of a one year extension following a decision of the Authority.

According to Resolution No. 134/2006, starting on October 1, 2006, natural gas selling companies shall offer pricing terms consistent with the determination and updating mechanisms established by the Authority for Electricity and Gas only to household customers consuming less than 200,000 CM/y.

Eni started applying the indexation mechanism provided for by Resolution No. 134/2006 in its accounts from the second half of 2006 onwards. In addition, Eni began to renegotiate the terms of supply contracts with its wholesale customers as provided for by Resolution No. 134/2006. On the basis of Resolution No. 134/2006, management assessed that the provision accrued in 2005 financial statements, with respect to the estimated impact of Resolution No. 248/2004 for that year, was partially redundant, and as a result such provision was partially reversed in 2006 accounts.

Finally the Council of State annulled Resolution No. 248/2004 for formal flaws, acknowledging at the same time that the Authority was legitimate in changing pricing mechanisms in the natural gas sector. On this basis, the Authority enacted Resolution No. 79/2007 as discussed above.

Inquiry of the Authority for Electricity and Gas on import purchase prices

With Resolution No. 107/2005 the Authority for Electricity and Gas started a formal inquiry under Law No. 481/1995 against Eni and other gas importers alleging their failure to comply with the Authority information requirements contained in its Resolution No. 188/2004 of October 27, 2004, by which it required natural gas importers, among which Eni, to give information concerning: (i) dates and supplier for each supply contract for the import of natural gas; (ii) FOB purchase prices; (iii) price updating formulas; and (iv) volumes supplied and FOB purchase average prices on a monthly basis for each supplying contract relating to the period October 2002-September 2004. Under Law No. 481/1995, the Authority for Electricity and Gas can impose a fine on Eni. Eni appealed this decision with the Regional Administrative Court of Lombardy that on March 22, 2005 cancelled the obligation for Eni to communicate dates and supplier for each contract and FOB purchase prices. Accordingly, Eni initially gave the Authority for Electricity and Gas only part of the information required. On April 6, 2006 a final hearing was held in front of the Authority Eni confirmed its position that it has provided adequate information, but with the intention of full collaboration it provided the data concerning average monthly FOB prices for the October 2002-September 2004 period.

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With Resolution No. 226/2006 of October 21, 2006, the Italian Authority for Electricity and Gas closed a formal inquiry against Eni that commenced with Resolution No. 107/2005, stating that Eni allegedly failed to comply with an obligation to deliver certain pieces of information regarding Eni’s natural gas import contracts to the Authority. As a result, the Authority fined Eni euro 10 million. In spite of the circumstance that Eni spontaneously delivered the requested pieces of information, the Authority objected to the fact that Eni delayed the fulfillment of its obligation to deliver said information, resulting in a behavior which breaches the rules requiring the establishment of information flows intended to allow the Authority to perform its tasks. Eni filed a claim against the Authority’s decision before the Regional Administrative Court of Lombardy. Eni recorded a provision for this proceeding in its 2006 accounts.

Inquiry of the Authority for Electricity and Gas on behaviors of operators selling natural gas to end customers

With Resolution No. 235/2006 of November 6, 2006, the Italian Authority for Electricity and Gas closed the inquiry that started in October 2005 (with Resolution No. 225) on the commercial behavior of companies selling natural gas to end customers located in urban centers (residential, services, commercial activities and small enterprises) aiming at acquiring new customers or re-acquiring customers transferred to other sellers. The inquiry was conducted with particular reference to hurdles posed by companies to customers wishing to leave one distributor or to the entry of competitors on the market from January 1, 2005 to October 20, 2006. In its final report, enclosed to the Resolution No. 235/2006 the Authority confirmed the existence of certain critical points about the real level of competition within this market segment and proposed different options to complete and adjust the regulatory framework in order to overcome acknowledged deficiencies.

Inquiry of the European Commission

On May 11, 2007 the European Commission has decided to open anti-trust proceedings against Eni based on information obtained during inspections carried out in 2006 at the headquarters of Eni and in certain Eni’s subsidiaries. These proceedings against Eni intend to verify the possible existence of any business conducts breaching European competition rules in the form of preventing access to the Italian natural gas wholesale market and to subdivide the market among few operators in the activity of supply and transport of natural gas.
Particularly, the European Commission alleged that Eni might have: (i) adopted commercial practices that constitute barriers to access to the Italian market for the wholesale supply of natural gas by way of its long-term purchase contracts and by subdividing the market among few operators; and (ii) engaged a majority share of the transport capacity of certain international gas lines, preventing third parties from accessing said infrastructures. Furthermore, the European Commission alleged that Eni might have delayed or annulled certain plans for the upgrading of the international transport infrastructure, despite the significant demand for access by third parties. These suspected practices constitute possible infringements of Article 82 of the EC Treaty. The initiation of proceedings does not imply that the Commission has conclusive proof of an infringement. The Commission will conduct an in-depth investigation of the case as a matter of priority. There is no strict deadline to complete inquiries into anticompetitive conduct.
If the existence of the alleged anti-competitive practices will be confirmed, the European Commission could fine Eni. At present, management is not able to assess the impact on Eni’s results of operations and financial condition that may arise from an unfavorable outcome of this matter.

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.

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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 expenditure 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 expenditure is 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 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.

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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.

Tax criteria for the determination of amortizations for companies operating in transport and distribution of natural gas The criteria for the determination of the annual share of amortizations of natural gas transport and distribution assets deductible in the determination of income taxes have been changed starting in 2005 onwards by Law Decree No. 203 of September 30, 2005, converted into Law No. 248 of December 2, 2005 and Law No. 266 of December 23, 2005 (budget law for 2006). Due to these changes, the share of amortizations that was previously calculated based on rates set by a Decree of the Minister of Finance of December 31, 1988, is now determined by dividing the relevant asset gross book value in accordance with the useful lives determined by the Authority for Electricity and Gas and reducing the amount obtained after tax by 20%. The alignment of the fiscal lives of natural gas transport and distribution assets to their useful lives entails the anticipation of the payment of income taxes given the postponement of the deductibility of amortization without impacting on net profit of companies involved (mainly Snam Rete Gas and Italgas), except for the financial charges related to this cash anticipation.

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.

Preliminary investigation on the management and operation of the Panigaglia LNG regasification terminal The Authority for Electricity and Gas with Decision No. 204 of November 18, 2004, started a preliminary investigation on the management and operation of Eni’s Panigaglia LNG regasification terminal and on LNG supplies to the Italian market in the thermal years from 2001 to 2004 in order to ascertain any behavior infringing the rules of equal access and equal conditions and neutrality in providing the regasification services.

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 assigned a priority access limited to the minimum amount of volumes that have been regasified in the period starting from thermal year 2001-2002. Eni filed a claim against this decision with the Regional Administrative Court of Lombardy.

Regasification tariffs Tariffs for both the continuous and spot regasification services are based on treated volumes of LNG, number of discharges carried out and energy associated to volumes input in the national transport network. Tariffs for the spot service are 30% lower than those for continuous service.

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 with 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 expenditure incurred by distributing companies.

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Distribution network code With Resolution No. 138/2004 the Authority for Electricity and Gas defined a set of rules to ensure free access to the distribution networks and neutrality of the distribution service, as well as criteria for the definition of distribution network codes.

With Resolution No. 108/2006 the Authority for Electricity and Gas approved the Gas Distribution Master Code which will be used as a standard contract between distribution companies and shippers (natural gas selling companies). Within three months from its publication, distribution companies are due to issue their own gas distribution code adopting either the Gas Distribution Master Code or the scheme provided for by the Resolution No. 138/2004.

 

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; (iv) establishment of a fund for the restructuring of the sales network, in part financed through a contribution, in the 1998-2000 period. In 2002 the fund received new financings: the decree of the Minister of Productive Activities of August 7, 2003, implementing Law No. 237 of December 12, 2002, defined the amount of euro 0.0003 and euro 0.0001 for each liter of automotive fuel (gasoline, diesel fuel and LPG) sold in 2002 in the ordinary distribution network to be paid by authorization holders and service station managers, respectively. The latest payment date was set at December 31, 2003; (v) the opening up of the logistics segment by permitting third party access to unused storage capacity for petroleum products; and (vi) measures designed to increase competition on the market for LPG for residential, industrial and agricultural users. 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 and service station operators, and such recommendations are considered by service station operators in establishing retail prices for petroleum products. With Ministerial Decree dated February 16, 2000, an entity was established that supports the Ministry of Productive Activities in monitoring trends in domestic and international prices of oil and oil products. Furthermore, in order to avoid initiatives inhibiting competition, Law No. 57/2001 provides the compliance with EU Regulation No. 2790/1999 concerning "vertical agreements" on economic relations between operators in this area. To date, this regulation has had no significant impact on Eni’s operations.

With Decision of January 18, 2007, the Italian Antitrust Authority opened an inquiry to ascertain the existence of a possible agreement limit competition in the field of pricing of automotive fuels distributed on the retail market in Italy in violation of Article 81 of the EC Treaty. This inquiry concerns eight oil companies, among which Eni. According to the Authority, said companies would have been putting in place collusive mechanisms intended to influence the pricing of automotive fuels distributed on the retail market by way of a continuing exchange of informative flows since 2004.

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.

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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 (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.

Decree No. 32 of February 11, 1998 established an entity responsible for the maintenance and management of this compulsory stock whose main tasks are to: (i) distribute stocks on the national territory according to available storage sites and consumption levels; (ii) meet the demand for refined products in case of crisis; (iii) guarantee storage volumes to operators; and (iv) record demand for refined products in the various areas of Italy. The Agency has been created on June 14, 2001; its By-laws had been approved with a Ministerial Decree of January 29, 2001 and its operating regulation has been approved on May 20, 2003 by the general meeting of the Agency’s members.

At December 31, 2006 Eni owned 8.6 mmtonnes of oil products inventories, of which 5.4 mmtonnes as "compulsory stocks", 1 mmtonnes related to operating inventories in refineries and depots (including 0.2 mmtonnes of oil products contained in facilities and pipelines), 0.7 mmtonnes related to oil products contained in ships and 0.3 mmtonnes related to specialty products.

Eni’s compulsory stocks (at December 31, 2006) were held in term of crude oil (31%), light and medium distillates (45%), 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 70 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.

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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 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 companies. As of December 31, 2006, there were 257 fully consolidated subsidiaries, 94 subsidiaries accounted for under either the equity method or the cost method and 176 affiliates accounted for under either the equity method or the cost method. The significant subsidiaries, associated undertakings and joint ventures of the Eni Group controlled directly or indirectly by Eni at December 31, 2006 and included in the scope of consolidation, as well as Eni’s percentage of equity capital or joint venture interest (rounded to the nearest whole number) are set forth in the table below. The principal country of operation is generally indicated by the company’s country of incorporation or by its name.

Company/Undertaking   Country of Incorporation  

%

Exploration & Production        
Stoccaggi Gas Italia SpA   Italy  

100

Eni Oil Algeria Ltd   the United Kingdom  

100

Eni Angola Exploration BV   the Netherlands  

100

Agip Caspian Sea BV   the Netherlands  

100

Eni Congo SA   the Netherlands  

100

Eni Dación BV   the Netherlands  

100

Lasmo Sanga Sanga Ltd   Bermuda  

100

Eni Iran BV   the Netherlands  

100

Agip Karachaganak BV   the Netherlands  

100

Eni Lasmo Plc   the United Kingdom  

100

Eni LNS Ltd   the United Kingdom  

100

Eni North Africa BV   the Netherlands  

100

Agip Oil Ecuador BV   the Netherlands  

100

Eni Petroleum Co Inc   USA  

100

Eni UK Ltd   the United Kingdom  

100

Ieoc Production BV   the Netherlands  

100

NAOC Nigerian Agip Oil Co Ltd   Nigeria  

100

Eni Norge A/S   Norway  

100

         
Gas & Power        
Snam Rete Gas SpA   Italy  

50

Società Italiana per il Gas pA   Italy  

100

Distribuidora de Gas Cuyana SA   Argentina  

46

Gas Brasiliano Distribuidora SA   Brazil  

100

Greenstream BV   the Netherlands  

75

Inversora de Gas Cuyana SA   Argentina  

76

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Company/Undertaking   Country of Incorporation  

%

Tigáz Rt Tiszántúli Gázszolgáltátó Részvénytársaság   Hungary  

50

EniPower SpA   Italy  

100

         
Refining & Marketing        
AgipFuel SpA   Italy  

100

Ecofuel SpA   Italy  

100

Eni Portugal Investment SpA   Italy  

100

Agip Deutschland GmbH   Germany  

100

Agip España SA   Spain  

100

Agip France Sarl   France  

100

American Agip Co Inc   USA  

100

         
Petrochemicals        
Polimeri Europa SpA   Italy  

100

Dunastyr Polystyrene Manufacturing Co Ltd   Hungary  

100

Polimeri Europa Benelux SA   Belgium  

100

Polimeri Europa Elastomères France SA   France  

100

Polimeri Europa UK Ltd   the United Kingdom  

100

         
Engineering & Construction        
Saipem SpA   Italy  

43

Snamprogetti SpA   Italy  

100

CEPAV (Consorzio Eni per l’Alta Velocità) Uno   Italy  

50

Saipem SA   France  

43

         
Other activities        
Syndial SpA - Attività Diversificate   Italy  

100

         
Corporate and financial companies        
Eni International BV   the Netherlands  

100

Eni Coordination Center SA   Belgium  

100

Società Finanziaria Eni SpA - Enifin   Italy  

100

Società Finanziamenti Idrocarburi - Sofid SpA   Italy  

100

EniServizi SpA   Italy  

100

 

Item 4A. UNRESOLVED STAFF COMMENTS

None.

 

Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The information in this item should be read together with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18.

 

Executive Summary

Eni reported net profit of euro 9.2 billion in 2006, the highest in the Company’s history, representing an increase of 4.9% from 2005. Operating profit in 2006 amounted to euro 19.3 billion, up 14.9% from 2005 reflecting higher operating profit reported by the Exploration & Production, the Gas & Power and the Engineering & Construction segments due to volume growth combined with a favorable trading environment characterized by higher crude oil and natural gas prices and increased natural gas selling margins. In addition, lower restructuring charges were recorded in the Other activities segment. These gains were partly offset by a reduced operating profit recorded by the Refining & Marketing segment due to a decline in refining margins and the impact of lower year-end prices on the evaluation of inventories of 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 operation in particular for the Refining & Marketing segment as inventory evaluation is based on current market prices.

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On the basis of the results achieved, Eni’s management proposed at the Annual General Shareholder Meeting to distribute a dividend of euro 1.25 per share, of which euro 0.60 was already paid as interim dividend in October 2006. This dividend is 13.6% higher than in 2005 (euro 1.10 per share) and was approved by the Annual General Shareholder Meeting on May 24, 2007.

In Exploration & Production, Eni continued to implement its strategy of growing oil and natural gas production leveraging on the development of existing assets. Eni’s production for the year (on an available for sale basis) increased by 1.6% from 2005 to 1,720 KBOE/d. This result was affected by:

(i)   a sizeable loss of production at the Venezuelan Dación oilfield (down 46 KBBL/d) due to the unilateral cancellation of the service contract relating to activities at this field by the Venezuelan state oil company PDVSA effective April 1, 2006;
(ii)   lower entitlements in certain Production Sharing Agreements (PSAs) and buy-back contracts (down 21 KBOE/d) due to higher oil and gas 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; and
(iii)   disruptions in Nigeria due to social unrest.

Exploration & Production’s results for 2006 were bosted also by increased realized prices for oil and gas, partly offset by higher operating costs and higher depreciation and amortization charges.

Net proved reserves of oil and natural gas were 6,436 mmBOE at year end 2006 (54% crude and condensates), down 401 mmBOE from 2005. The unilateral cancellation of the service contract for the Dación oilfield by the Venezuelan state oil company PDVSA determined a decrease in Eni’s proved reserves of 170 mmBBL. In 2006 Eni’s proved reserves replacement ratio was 38% (40% in 2005); as of year-end the reserves life index was 10 years of remaining production at the current rate (10.8 as at December 31, 2005).

Production start up of the Kashagan oilfield project (Eni is the operator and has a 18.52% interest) is currently scheduled for the third quarter of 2010 as compared to an initial forecast indicating a start up in 2008, due to the need to execute certain measures intended to enhance the overall level of safety and operability of offshore facilities. These enhancements coupled with sector-specific inflation and underestimation of costs to conduct offshore operations in shallow/ultra shallow waters where the Kashagan field is located resulted in a significant increase in the expected expenditures to implement phase one of the Kashagan project. At present, the estimated expenditures to reach the 300 KBBL/d production target envisaged by phase one stand at $19 billion, as compared to a budget of $10.3 billion in real terms 2007 as approved by the consortium partners and the relevant Kazakh authorities in 2004. Based on the high level of productivity yielded by the first three development wells drilled to date, management currently expects a full field production plateau of 1.5 mmBBL/d, representing a 25% increase from the original target envisaged by the approved development plan.

In 2006, Eni invested euro 1,348 million in exploratory activities, up 106% from 2005, conducting a very extensive exploration campaign leading to the completion of 68 exploratory wells (35.9 net to Eni) with a commercial rate of success of 43% (49% net to Eni). A further 26 wells were in progress as of the year-end. Eni enhanced its exploration portfolio by acquiring assets in core areas such as Angola, Alaska, Brazil, Congo, Egypt, Nigeria, Norway, Pakistan, the Gulf of Mexico, and in new high-potential basins such as Mali, Mozambique and East Timor.

In Gas & Power, Eni continued to leverage on its consolidated and integrated position in Europe based on access to infrastructure, availability of gas – both from its hydrocarbon production and from long-term purchase contracts – and large customer base, to increase natural gas sales in European gas markets. Overall gas sales in 2006 totaled 97.48 BCM, up approximately 4% from 2005. This growth was driven mainly by:

  a growth in sales in a number of target European markets (up approximately 16% in particular in Turkey, Germany/Austria and France); and
  the build-up of supplies from Libyan-operated gas fields.

These positives were partly offset by a 3% decrease in sales in Italy due to the effect of competition and the mild weather conditions which characterized the fourth quarter of the year. The Gas & Power results for the year were also boosted by: (i) a favorable trading environment for gas selling margins; and (ii) a favorable development in the Italian regulatory framework, deriving from a softer 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.

Electricity sales volumes (24.82 TWh) increased by 9% from 2005 as a result of the ramp-up of new production capacity at the Brindisi and the Mantova plants, which increases were offset in part by the shut-down of the Ravenna power plant due to ordinary maintenance activity.

In Refining & Marketing, Eni is seeking to increase return from its assets by upgrading its refineries in order to achieve higher yields of higher-value products, meet future product quality requirements, process low-quality crude and reduce operating costs. Eni is also pursuing the strengthening of its retail network of service stations in Italy and in selected European countries.

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The Refining & Marketing results for the year were affected by a weak refining margin environment, higher downtime of Eni’s refineries due to planned maintenance activity, the impact of lower year-end prices for oil and products on inventory evaluation, and the appreciation of the euro against the dollar. Overall retail sales in Europe in 2006 amounted to 12.48 mmtonnes, of which 8.66 mmtonnes were in Italy, substantially in line with 2005.

Engineering & Construction segment reported higher operating profit against the backdrop of favorable trends in the demand for oilfield services.

Capital expenditure totaled euro 7.8 billion in 2006, up 5.7% from 2005; approximately 90% of capital expenditure was carried out in oil and gas activities. The principal projects for the year were:

  the development of oil and gas reserves (euro 3,629 million) in particular in Kazakhstan, Angola, Egypt and Italy and exploration activities (euro 1,348 million) particularly in Angola, Egypt, Norway, Nigeria, the Gulf of Mexico and Italy, including also the acquisition of 152,000 square kilometers of new acreage (99% operated by Eni);
  the upgrades of Eni’s natural gas transport and distribution networks in Italy (euro 785 million);
  the construction of a new FPSO unit and upgrades of the fleet and logistic centers in the Engineering & Construction segment (euro 591 million);
  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 upgrades of the refined product distribution network in Italy and in the rest of Europe (euro 223 million);
  ongoing construction of combined cycle power plants (euro 229 million); and
  actions for environmental protection and for complying with safety and environmental regulations in the Petrochemical segment (euro 99 million).

 

Margin8

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 petrochemicals products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.

 

Trading Environment

   

2004

 

2005

 

2006

   
 
 
Average price of Brent dated crude oil in U.S. dollars (1)  

38.22

 

54.38

 

65.14

Average price of Brent dated crude oil in euro (2)  

30.72

 

43.71

 

51.86

Average EUR/USD exchange rate (3)  

1.244

 

1.244

 

1.256

Average European refining margin in U.S. dollars (4)  

4.35

 

5.78

 

3.79

Euribor - three month euro rate % (3)  

2.1

 

2.2

 

3.1

   
 
 

(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 2006 the trading environment was characterized by higher average Brent crude oil prices (up 19.8% from 2005) and higher selling margins on natural gas and on petrochemical products. These positives were partially offset by a decline in refining margins (margin on Brent was down 34.4%) which was mitigated by Eni’s refinery capacity to process heavy crudes which are discounted as compared to the Brent crude market benchmark, thus resulting in a higher profitability of the heavy barrel.

_______________

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

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Natural gas demand in Italy decreased by approximately two percentage points from 2005: in fact 2006 was a normal year based on average temperatures recorded in the coldest months of the year (first and fourth quarters) as compared to lower than average temperatures in the same months of 2005, resulting in lower consumption of heating gas in 2006.

 

Key Consolidated Financial Data

   

2004

 

2005

 

2006

   
 
 
 

(million euro)

Net sales from operations      

57,545

 

73,728

 

86,105

Operating profit      

12,399

 

16,827

 

19,327

Net profit pertaining to Eni      

7,059

 

8,788

 

9,217

Net cash provided by operating activities      

12,500

 

14,936

 

17,001

Capital expenditure      

7,499

 

7,414

 

7,833

Shareholders’ equity including minority interest at year end      

35,540

 

39,217

 

41,199

Net borrowings at year end (1)      

10,443

 

10,475

 

6,767

Net profit pertaining to Eni per share  

(euro per share)

 

1.87

 

2.34

 

2.49

Dividend per share  

(euro per share)

 

0.90

 

1.10

 

1.25

Net borrowings to total shareholders’ equity ratio including minority interests (leverage) (1)      

0.29

 

0.27

 

0.16

   
 
 

(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 see "Liquidity and Capital Resources - Financial Conditions" below.

 

 

Basis of Presentation

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB) and adopted by the European Commission following the procedure contained in Article 6 of the EC Regulation No. 1606/2002 of the European Parliament and Council of July 19, 2002. For hydrocarbon exploration and production, accounting policies generally applied by the oil industry have been adopted, with particular reference to amortization according to the Unit Of Production (UOP) method, buy-back contracts and Production Sharing Agreements. The Consolidated Financial Statements have been prepared by applying the cost method except for items that under IFRS must be recognized at fair value as described in the Notes to the Consolidated Financial Statements under the heading "Evaluation Criteria".

In adopting IFRS, Eni elected to rely upon the following exemptions as permitted under IFRS 1 "First-time Adoption of International Financial Reporting Standards" (IFRS 1):

  no retroactive restatement of business combinations that occurred before January 1, 2004. As a result of this exemption, goodwill was not restated to take into account amortization charges recorded in previous periods before the adoption of IFRS; and
  the election of January 1, 2005 as the transition date for the first application of IAS 32 and IAS 39, related to the evaluation of financial instruments at fair value, including derivatives. As permitted under IFRS 1, Eni has not restated information for the year 2004 which consequently are not comparable with 2005 and 2006 with respect to this matter. In the Consolidated Financial Statements for the year ended December 31, 2005 and 2006, the impact of recording certain derivative financial instruments at fair value was a euro 386 million charge and a euro 383 million gain recognized in the profit and loss account, respectively.


Critical Accounting Estimates

The preparation of these Consolidated Financial Statements in accordance with IFRS requires management to make estimates that are based on complex or subjective judgments which rely upon past experience and assumptions determined to be reasonable and realistic considering the information available at the date of the estimate. The application of these estimates and assumptions affects the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of income and expenses during the reporting period. The main areas affected by estimates include the determination of oil and gas proved reserves and proved developed reserves, accounting for exploratory drilling costs under U.S. GAAP, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, recognition of environmental liabilities and recognition of revenues in the oilfield services construction and engineering businesses. Actual results may differ from these estimates given the uncertainty surrounding the assumptions and conditions upon which the estimates are based.

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Summarized below are the critical accounting estimates that require the more subjective judgment of our management. Such assumptions or estimates regard the effects of matters that are inherently uncertain and for which changes in conditions may significantly affect future results.

 

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 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 categorized as proved undeveloped. Volumes will subsequently be recategorized 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 based on the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves 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 an impairment of a property is to be carried out or not. The larger the volume of estimated reserves, the lower is the likelihood that the property is to be impaired.

 

Accounting for Suspended Well Costs under U.S. GAAP

Under U.S. GAAP costs for exploratory wells are initially capitalized pending the determination of whether the well has found proved reserves. If proved reserves are found, the capitalized costs of drilling the well are reclassified to tangible assets and amortized on a UOP basis. If proved reserves are not found, the capitalized costs of drilling the well are charged to expense. However, successful exploratory efforts are, in many cases, not declared to be proved until after an extensive and lengthy evaluation period has been completed. These issues were addressed by the FASB staff in its FSP FAS 19-1, published in April 2005, amending FAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies". Under the provisions of FSP FAS 19-1, companies in the oil and gas industry are allowed to continue capitalization of an exploratory well after the completion of drilling when: (a) the well has found a sufficient quantity of reserves to justify completion as a producing well; and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. Determination of whether an exploratory well should remain capitalized after completion of drilling requires a high degree of judgment on the part of management in assessing whether the Company is making sufficient progress assessing the reserves and the economic and operating viability of a given project. The company evaluates the progress made on the basis of regular project reviews which take account of the following factors: (i) costs are being incurred to assess the reserves and their potential development; (ii) existence (or active negotiations) of sales contracts with customers for oil and natural gas; and (iii) existence of firm plans, established timetables or contractual commitments, which may include seismic testing and drilling of additional exploratory wells. As of December 31, 2006, an amount of euro 392 million remain capitalized relating to approximately 25 exploratory wells for which drilling activities have been completed for more than one year, of this capitalized amount euro 85 million (or 10 wells) relates to projects progressing towards completion of development activities, and the remaining euro 307 million (or 15 wells) relates to projects for which additional exploratory activity is underway or firmly planned. See Note 38 to the Consolidated Financial Statements.

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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 that 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 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.

Goodwill and other intangible assets with indefinite useful life are not amortized but are reviewed at least annually to determine whether their carrying amount is recoverable and in any case, when trigger events arise that would lead the Company to assume the value of an asset is impaired. 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 capital expenditures. If the fair value 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 related to the removal of tangible equipment and the restoration of land or seabeds require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded in the consolidated financial statements. Estimating future asset removal costs is difficult and requires management to make estimates and judgments due to the fact that most removal obligations will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations. 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 obligations in the period when it is incurred (typically, at the time, the asset is installed at the production location).When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are increased with the passage of time (interest accretion) and any change of the estimates following the modification of future cash flows and discount rate is adopted. The recognized asset retirement obligations are based upon 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 the acquisition of a business requires the allocation of the purchase price to most assets and liabilities acquired based on their fair value. Any positive residual difference between the allocated amount and the purchase price is recognized as "Goodwill". Negative residual differences are charged against 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.

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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, productions 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 performed, the existing insurance policies to cover environmental risks and provision for risks accrued, does not expect any material adverse impact 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:

  the possibility of a yet unknown contamination;
  the results of the ongoing surveys and other possible effects of statements as required by the applicable regulations concerning the remediation of contaminated sites;
  the possible effect of future environmental legislation and rules;
  the effect of possible technological changes relating to future remediation; and
  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.

 

Employees Post Retirement Benefits

Defined benefit plans and other long-term benefits are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trend rates, estimated retirement dates, mortality rates.

The significant assumptions used to account for pensions and other post-retirement benefits are determined as follows:

  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;
  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;
  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;
  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
  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 actuarial gains and losses, unrecognized at the end of the previous reporting period, that exceed 10% of the greater of the present value of the defined benefit obligation and the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan.

Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions; the 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.

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Revenue Recognition in the Engineering & Construction Segment

Revenue recognition in the Engineering & Construction business segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to 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 payments, 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 counterpart will accept them.

 

Results of Operations

Overview of the Profit and Loss Account for Three Years Ended December 31, 2004, 2005 and 2006

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.

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