20-F 1 sj0415eni20f2014.htm sj0415eni20f2014

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

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

(Mark One)

 

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

OR

  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014

OR

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

OR

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

Commission file number: 1-14090
——————————
Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Massimo Mondazzi
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
————————————————————
Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class

  

Name of each exchange on which registered

Shares
American Depositary Shares

  

New York Stock Exchange*
New York Stock Exchange

(Which represent the right to receive two Shares)

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

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

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
                                        Ordinary shares of euro 1.00 each                                                                                                                                                                3,634,185,330

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

Yes 

   

 No 

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

Yes 

   

 No 

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes 

   

 No 

 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes 

   

 No 

 
Indicate by check mark whether the registrant have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes 

   

 No 

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

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

U.S. GAAP

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

Other

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

Item 17

   

 Item 18

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

Yes 

   

 No 


TABLE OF CONTENTS
  I Page
Certain defined terms I ii
Presentation of financial and other information I ii
Statements regarding competitive position I ii
Glossary I iii
Abbreviations and conversion table I vi
II I I III I
PART I I   I  
Item 1. I IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS I 1
Item 2. I OFFER STATISTICS AND EXPECTED TIMETABLE I 1
Item 3. I KEY INFORMATION I 1
I I Selected Financial Information I 1
I I Selected Operating Information I 4
I I Exchange Rates I 5
I I Risk factors I 6
Item 4. I INFORMATION ON THE COMPANY I 28
I I History and development of the Company I 28
I I BUSINESS OVERVIEW I 32
I I Exploration & Production I 32
I I Gas & Power I 61
I I Refining & Marketing I 67
I I Chemicals I 73
I I Engineering & Construction I 75
I I Corporate and Other activities I 77
I I Research and development I 78
I I Insurance I 79
I I Environmental matters I 80
I I Regulation of Eni’s businesses I 86
I I Property, plant and equipment I 91
I I Organizational structure I 91
Item 4A. I UNRESOLVED STAFF COMMENTS I 91
Item 5. I OPERATING AND FINANCIAL REVIEW AND PROSPECTS I 92
I I Executive summary I 92
I I Critical accounting estimates I 95
I I 2012-2014 Group results of operations I 99
I I Liquidity and capital resources I 113
I I Recent developments I 118
I I Management's expectations of operations I 119
Item 6. I DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES I 128
I I Directors and Senior Management I 128
I I Compensation I 135
I I Board practices I 149
I I Employees I 158
I I Share ownership I 160
Item 7. I MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS I 161
I I Major Shareholders I 161
I I Related party transactions I 161
Item 8. I FINANCIAL INFORMATION I 162
I I Consolidated Statements and other financial information I 162
I I Significant changes I 162
Item 9. I THE OFFER AND THE LISTING I 163
I I Offer and listing details I 163
I I Markets I 164
Item 10. I ADDITIONAL INFORMATION I 166
I I Memorandum and Articles of Association I 166
I I Material contracts I 172
I I Exchange controls I 172
I I Taxation I 172
I I Documents on display I 176
Item 11. I QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK I 178
Item 12. I DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES I 181
12A. I Debt securities I 181
12B. I Warrants and rights I 181
12C. I Other securities I 181
12D. I American Depositary Shares I 181
II I I I I
PART II I I I I
Item 13. I DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES I 183
Item 14. I MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS I 183
Item 15. I CONTROLS AND PROCEDURES I 183
Item 16. I I I II
16A. I Board of Statutory Auditors financial expert I 184
16B. I Code of Ethics I 184
16C. I Principal accountant fees and services I 184
16D. I Exemptions from the Listing Standards for Audit Committees I 185
16E. I Purchases of equity securities by the issuer and affiliated purchasers I 185
16F. I Change in Registrant’s Certifying Accountant I 186
16G. I Significant Differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual I 186
16H. I Mine safety disclosure I 189
PART IIII I I I II
Item 17. I FINANCIAL STATEMENTS I 190
Item 18. I FINANCIAL STATEMENTS I 190
Item 19. I EXHIBITS I 190

i


Table of Contents

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

 

CERTAIN DEFINED TERMS

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

 

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB).

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

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

Unless otherwise specified or the context otherwise requires, references herein to "Division" and "segment" are to Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction, Chemicals and Other activities.

References to Versalis or Chemicals are to Eni’s chemical activities engaged through its fully-owned subsidiary Versalis and Versalis’ controlled entities.

 

STATEMENTS REGARDING COMPETITIVE POSITION

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

ii


Table of Contents

GLOSSARY

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

Financial terms

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

Business terms

   
     
AEEGSI (Authority for Electricity Gas and Water) formerly AEEG (Authority for
Electricity and Gas)
  The Regulatory Authority for Electricity Gas and Water is the Italian independent body which regulates, controls and monitors the electricity, gas and water sectors and markets in Italy. The Authority’s role and purpose is to protect the interests of users and consumers, promote competition and ensure efficient, cost-effective and profitable nationwide services with satisfactory quality levels.
     
Associated gas   Associated gas is a natural gas found in contact with or dissolved in crude oil in the reservoir. It can be further categorized as Gas-Cap Gas or Solution Gas.
     
Average reserve life index   Ratio between the amount of reserves at the end of the year and total production for the year.
     
Barrel/BBL   Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
     
BOE   Barrel of Oil Equivalent. It is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a certain coefficient (see "Conversion Table").
     
Concession contracts   Contracts currently applied mainly in Western countries regulating relationships between states and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive on exploration, development and production activities and for this reason it acquires a right to hydrocarbons extracted against the payment of royalties on production and taxes on oil revenues to the state.
     
Condensates   Condensates is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
     
Consob   The National Commission for listed companies and the stock exchange of Italy.
     
Contingent resources   Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
     
Conversion capacity   Maximum amount of feedstock that can be processed in certain dedicated facilities of a refinery to obtain finished products. Conversion facilities include catalytic crackers, hydrocrackers, visbreaking units, and coking units.

iii


Table of Contents
Conversion index   Ratio of capacity of conversion facilities to primary distillation capacity. The higher the ratio, the higher is the capacity of a refinery to obtain high value products from the heavy residue of primary distillation.
     
Deep waters   Waters deeper than 200 meters.
     
Development   Drilling and other post-exploration activities aimed at the production of oil and gas.
     
Enhanced recovery   Techniques used to increase or stretch over time the production of wells.
     
EPC   Engineering, Procurement and Construction.
     
EPCI   Engineering, Procurement, Construction and Installation.
     
Exploration   Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
     
FPSO   Floating Production Storage and Offloading System.
     
FSO   Floating Storage and Offloading System.
     
Infilling wells   Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
     
LNG   Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to 1,400 cubic meters of gas.
     
LPG   Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
     
Margin   The difference between the average selling price and direct acquisition cost of a finished product or raw material excluding other production costs (e.g. refining margin, margin on distribution of natural gas and petroleum products or margin of petrochemical products). Margin trends reflect the trading environment and are, to a certain extent, a gauge of industry profitability.
     
Mineral Potential   (Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.
     
Mineral Storage   According to Legislative Decree No. 164/2000, these are volumes required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. The purpose is to ensure production flexibility as required by long-term purchase contracts as well as to cover technical risks associated with production.
     
Modulation Storage   According to Legislative Decree No. 164/2000, these are volumes required for meeting hourly, daily and seasonal swings in demand.
     
Natural gas liquids (NGL)   Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
     
Network Code   A code containing norms and regulations for access to, management and operation of natural gas pipelines.
     
Over/Under lifting   Agreements stipulated between partners which regulate the right of each to its share in the production for a set period of time. Amounts lifted by a partner different from the agreed amounts determine temporary Over/Under lifting situations.
     
Possible reserves   Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
     
Probable reserves   Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
     
Primary balanced refining capacity   Maximum amount of feedstock that can be processed in a refinery to obtain finished products measured in BBL/d.
     
Production Sharing Agreement (PSA)   Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to

iv


Table of Contents
    perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "cost oil" is used to recover costs borne by the contractor and "profit oil" is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.
     
Proved reserves   Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
     
Reserves   Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
     
Reserve life index   Ratio between the amount of proved reserves at the end of the year and total production for the year.
     
Reserve replacement ratio   Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the amount of reserves – in PSAs – due to changes in international oil prices.
     
Ship-or-pay   Clause included in natural gas transportation contracts according to which the customer is requested to pay for the transportation of gas whether or not the gas is actually transported.
     
Strategic Storage   According to Legislative Decree No. 164/2000, these are volumes required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system.
     
Take-or-pay   Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
     
Upstream/Downstream   The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil and gas sector that are downstream of exploration and production activities.

v


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 Refining & Marketing segment
                           
mmBBL = million barrels   E&C = the Engineering & Construction segment
                           
BBBL = billion barrels        

 

CONVERSION TABLE

1 acre

=

0.405 hectares    
                   
1 barrel

=

42 U.S. gallons    
                   
1 BOE

=

1 barrel of crude oil

=

5,492 cubic feet of natural gas
                   
1 barrel of crude oil per day

=

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

=

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

=

approximately 0.00643 barrels of oil equivalent    
                   
1 kilometer

=

approximately 0.62 miles    
                   
1 short ton

=

0.907 tonnes

=

2,000 pounds
                   
1 long ton

=

1.016 tonnes

=

2,240 pounds
                   
1 tonne

=

1 metric ton

=

1,000 kilograms
     

=

approximately 2,205 pounds
                   
1 tonne of crude oil

=

1 metric ton of crude oil

=

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

 

 

vi


Table of Contents

PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE

 

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE

 

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2010, 2011, 2012, 2013 and 2014.

The selected historical financial data presented herein are derived from Eni’s Consolidated Financial Statements included in Item 18.

All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18.

1


Table of Contents
 

Year ended December 31,

 
 

2010

 

2011

 

2012

 

2013

 

2014

 
 
 
 
 
  (euro million except data per share and per ADR)
CONSOLIDATED PROFIT STATEMENT DATA                              
Net sales from continuing operations   96,617     107,690     127,109     114,697     109,847  
Operating profit by segment from continuing operations                              
Exploration & Production   13,866     15,887     18,470     14,868     10,766  
Gas & Power   896     (326 )   (3,125 )   (2,967 )   186  
Refining & Marketing   149     (273 )   (1,264 )   (1,492 )   (2,229 )
Chemicals   (86 )   (424 )   (681 )   (725 )   (704 )
Engineering & Construction   1,302     1,422     1,453     (98 )   18  
Other activities   (1,384 )   (427 )   (300 )   (337 )   (272 )
Corporate and financial companies   (361 )   (319 )   (341 )   (399 )   (246 )
Impact of unrealized intragroup profit elimination and other consolidation adjustments (1)   1,100     1,263     996     38     398  
Operating profit from continuing operations   15,482     16,803     15,208     8,888     7,917  
Net profit attributable to Eni from continuing operations   6,252     6,902     4,200     5,160     1,291  
Net profit (loss) attributable to Eni from discontinued operations   66     (42 )   3,590              
Net profit attributable to Eni   6,318     6,860     7,790     5,160     1,291  
Data per ordinary share (euro) (2)                              
Operating profit:                              
- basic   4.27     4.64     4.20     2.45     2.19  
- diluted   4.27     4.64     4.20     2.45     2.19  
Net profit attributable to Eni basic and diluted from continuing operations   1.72     1.90     1.16     1.42     0.36  
Net profit attributable to Eni basic and diluted from discontinued operations   0.02     (0.01 )   0.99              
Net profit attributable to Eni basic and diluted   1.74     1.89     2.15     1.42     0.36  
Data per ADR ($) (2) (3)                              
Operating profit:                              
- basic   11.33     12.92     10.79     6.51     5.82  
- diluted   11.33     12.92     10.79     6.51     5.82  
Net profit attributable to Eni basic and diluted from continuing operations   4.56     5.32     2.98     3.77     0.96  
Net profit attributable to Eni basic and diluted from discontinued operations   0.05     (0.03 )   2.54              
Net profit attributable to Eni basic and diluted   4.62     5.26     5.53     3.77     0.96  

(1)    This item pertains to intragroup sales of commodities and capital goods recorded in the assets of the purchasing business segment as of the end of the reporting period.
(2)   Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(3)   Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/US$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2010 through 2013 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively.
    The dividend for 2014 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

2


Table of Contents
 

As of December 31,

 
 

2010

 

2011

 

2012

 

2013

 

2014

 
 
 
 
 
 

(euro million except data per share and per ADR)

CONSOLIDATED BALANCE SHEET DATA                    
Total assets   131,860   142,945   140,192   138,341   146,207
Short-term and long-term debt   27,783   29,597   24,192   25,560   25,891
Capital stock issued   4,005   4,005   4,005   4,005   4,005
Non-controlling interest   4,522   4,921   3,357   2,839   2,455
Shareholders’ equity - Eni share   51,206   55,472   59,060   58,210   59,754
Capital expenditures from continuing operations   12,450   11,909   12,805   12,800   12,240
Weighted average number of ordinary shares outstanding (fully diluted - shares million)   3,622   3,623   3,623   3,623   3,610
Dividend per share (euro) (1)   1.00   1.04   1.08   1.10   1.12
Dividend per ADR ($) (1) (2)   2.64   2.73   2.82   3.00   2.79

(1)   Euro per share or U.S. dollars per American Depositary Receipt (ADR), as the case may be. One ADR represents two Eni shares. The dividend amount for 2014 is based on the proposal of Eni’s management which is submitted to approval at the Annual General Shareholders’ Meeting scheduled on May 13, 2015.
(2)   Eni’s financial statements are stated in euro. The translations of certain euro amounts into U.S. dollars are included solely for the convenience of the reader. The convenient translations should not be construed as representations that the amounts in euro have been, could have been, or could in the future be, converted into U.S. dollars at this or any other rate of exchange. Data per ADR, with the exception of dividends, were translated at the EUR/US$ average exchange rate as recorded by in the Federal Reserve Board official statistics for each year presented (see the table on page 5). Dividends per ADR for the years 2010 through 2013 were translated into U.S. dollars for each year presented using the Noon Buying Rate on payment dates, as recorded on the payment date of the interim dividend and of the balance to the full-year dividend, respectively.
The dividend for 2014 based on the management’s proposal to the General Shareholders’ Meeting and subject to approval was translated as per the portion related to the interim dividend (euro 1.12 per ADR) at the Noon Buying Rate recorded on the payment date on September 22, 2014, while the balance of euro 1.12 per ADR was translated at the Noon Buying Rate as recorded on December 31, 2014. The balance dividend for 2014 once the full-year dividend is approved by the Annual General Shareholders’ Meeting is payable on May 20, 2015 to holders of Eni shares, being the ex-dividend date May 18, 2015, while ADRs holders will be paid on June 5, 2015.

 

3


Table of Contents

Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2010, 2011, 2012, 2013 and 2014.

 

Year ended December 31,

 
 

2010

 

2011

 

2012

 

2013

 

2014

 
 
 
 
 
Proved reserves of liquids of consolidated subsidiaries at period end (mmBBL)   3,415   3,134   3,084   3,079   3,077
of which developed   1,951   1,850   1,762   1,831   1,847
Proved reserves of liquids of equity-accounted entities at period end (mmBBL)   208   300   266   148   149
of which developed   52   45   44   35   46
Proved reserves of natural gas of consolidated subsidiaries at period end (BCF) (1)   16,198   15,582   14,190   14,442   14,808
of which developed   10,965   10,363   8,965   8,542   8,342
Proved reserves of natural gas of equity-accounted entities at period end (BCF)   1,684   4,700   6,767   3,726   3,737
of which developed   246   53   424   34   120
Proved reserves of hydrocarbons of consolidated subsidiaries at period end (mmBOE) (1)   6,332   5,940   5,667   5,708   5,772
of which developed   3,926   3,716   3,394   3,387   3,366
Proved reserves of hydrocarbons of equity-accounted entities at period end (mmBOE)   511   1,146   1,499   827   830
of which developed   96   54   122   40   67
Average daily production of liquids (KBBL/d)   997   845   882   833   828
Average daily production of natural gas available for sale (mmCF/d) (2)   4,222   3,763   4,118   3,868   3,782
Average daily production of hydrocarbons available for sale (KBOE/d) (2)   1,757   1,523   1,631   1,537   1,517
Hydrocarbon production sold (mmBOE)   638.0   548.5   598.7   555.3   549.5
Oil and gas production costs per BOE (3)   8.89   10.86   10.82   12.19   12.00
Profit per barrel of oil equivalent (4)   11.91   16.98   15.95   15.46   9.90

(1)    Includes approximately 767 BCF of natural gas held in storage in Italy as of December 31, 2010 and 2011.
(2)   Referred to Eni’s subsidiaries and its equity-accounted entities. Natural gas production volumes exclude gas consumed in operations (318, 321, 383, 451 and 442 mmCF/d in 2010, 2011, 2012, 2013 and 2014, respectively).
(3)    Expressed in U.S. dollars. Consists of production costs of consolidated subsidiaries (costs incurred to operate and maintain wells and field equipment including also royalties) prepared in accordance with IFRS divided by production on an available-for-sale basis, expressed in barrels of oil equivalent. See the unaudited supplemental oil and gas information in "Item 18 – Notes on Consolidated Financial Statements".
(4)   Expressed in U.S. dollars. Results of operations from oil and gas producing activities of consolidated subsidiaries, divided by actual sold production, in each case prepared in accordance with IFRS to meet ongoing U.S. reporting obligations under Topic 932. See the unaudited supplemental oil and gas information in "Item 18 – Notes on Consolidated Financial Statements" for a calculation of results of operations from oil and gas producing activities.

4


Table of Contents

Selected Operating Information continued

 

Year ended December 31,

 
 

2010

 

2011

 

2012

 

2013

 

2014

 
 
 
 
 
Sales of natural gas to third parties (1)   75.81   77.84   77.87   77.67   76.11
Natural gas consumed by Eni (1)   6.19   6.21   6.43   5.93   5.62
Sales of natural gas of affiliates (Eni’s share) (1)   9.41   9.85   8.29   6.96   4.38
Total sales and own consumption of natural gas of the Gas & Power segment (1)   91.41   93.90   92.59   90.56   86.11
E&P natural gas sales in Europe and in the Gulf of Mexico (1)   5.65   2.86   2.73   2.61   3.06
Worldwide natural gas sales (1)   97.06   96.76   95.32   93.17   89.17
Electricity sold (2)   39.54   40.28   42.58   35.05   33.58
Refinery throughputs (3)   34.80   31.96   30.01   27.38   25.03
Balanced capacity of wholly-owned refineries (4)   564   574   574   574   404
Retail sales (in Italy and rest of Europe) (3)   11.73   11.37   10.87   9.69   9.21
Number of service stations at period end (in Italy and rest of Europe)   6,167   6,287   6,384   6,386   6,220
Average throughput per service station (in Italy and rest of Europe) (5)   2,353   2,206   2,064   1,828   1,725
Chemical production (3)   7.22   6.25   6.09   5.82   5.28
Engineering & Construction order backlog at period end (6)   20,505   20,417   19,739   17,065   22,147
Employees at period end (number) (7)   73,768   72,574   79,405   83,887   84,405

(1) i Expressed in BCM.
(2) i Expressed in TWh.
(3) i Expressed in mmtonnes.
(4) i Expressed in KBBL/d.
(5) i Expressed in thousand liters per day.
(6) i Expressed in euro million.
(7) i Relating to continuing operations for all periods presented.

 

Exchange Rates

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

 

High

 

Low

 

Average (1)

 

At period end

 
 
 
 
 

(U.S. dollars per euro)

Year ended December 31,                
2010   1.46   1.19   1.33   1.34
2011   1.49   1.29   1.39   1.29
2012   1.35   1.21   1.29   1.32
2013   1.38   1.28   1.33   1.38
2014   1.39   1.21   1.33   1.21

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

5


Table of Contents
 

High

 

Low

 

At period end

 
 
 
 

(U.S. dollars per euro)

October 2014   1.28   1.25   1.25
November 2014   1.26   1.24   1.24
December 2014   1.25   1.21   1.21
January 2015   1.20   1.13   1.13
February 2015   1.15   1.12   1.12
March 2015   1.12   1.05   1.08

Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 31, 2015 was $1.08 per euro 1.00.

 

Risk factors

The risks described below may have a material adverse effect on our operational and financial performance. We invite our investors to consider these risks carefully.

Our operating results and cash flow and future rate of growth are exposed to the effects of fluctuating prices of crude oil, natural gas, oil products and chemicals

Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things:
(i)   global and regional dynamics of oil and gas supply and demand. The price of crude oil dropped significantly in the last part of 2014 with oil prices falling from the level of approximately 110 $/BBL by mid-year down to below the 50-dollar mark. This decline was driven by surging crude oil output mainly in non-Opec countries, like the United States, Russia, Brazil and Canada, in the face of a continuing slowdown in global demand. Eni believes that global oil demand will grow at a moderate pace in the short to medium term due to sluggish economic activity in Europe and other macroeconomic uncertainties, and more efficient use of fuels and energy in OECD countries whereas crude oil production is forecast to grow at a higher pace than demand. We currently forecast 55 $/BBL for the full year 2015 which is lower than the average level achieved in 2014 of approximately 100 $/BBL. See "Item 5 – Management’s expectations of operations";
(ii)   global political developments, including sanctions imposed on certain producing countries and conflict situations;
(iii)   global economic and financial market conditions;
(iv)   the influence of the Organization of the Petroleum Exporting Countries ("OPEC") over world supply and therefore oil prices;
(v)   prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables);
(vi)   weather conditions;
(vii)   operational issues;
(viii)   governmental regulations and actions;
(ix)   success in development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption; and
(x)   the effect of worldwide energy conservation and environmental protection efforts.

All these factors can affect the global balance between demand and supply for oil and prices of oil. Price fluctuations may have a material effect on the Group’s results of operations and cash flow. Generally speaking, lower oil prices from one year to another reduce the Group consolidated results of operations and cash flow and vice versa. The effect of changes in oil prices on Eni’s average realization for produced oil and therefore its revenues in the Exploration & Production segment is immediate. We estimate that our consolidated net profit and cash flow vary by approximately euro 0.15 billion for each one-dollar change in the price of the Brent crude oil benchmark with respect to our pricing scenario for the year 2015. See "Item 5 – Management’s expectations of operations – Outlook". In addition to the adverse effect on revenues, profitability and cash flow, lower oil and gas prices could result in debooking of proved reserves, if they become uneconomic in this type of environment, and asset impairments. Depending on the materiality and rapidity of a decrease in crude oil prices, we may also need to review investment decisions and the viability of development projects.

6


Table of Contents

Lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flows and hence the funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues. In addition, they may reduce returns at development projects either planned or being implemented forcing the Company to reschedule, postpone or cancel development projects. Finally, lower oil prices over prolonged periods may trigger a review of the future recoverability of the Company’s carrying amounts of oil and gas properties, resulting in the recognition of significant impairment charges, and may impact shareholders returns, including dividends and share buybacks, or share price.

Eni estimates that movements in oil prices impact approximately 50% of Eni’s current production. A further 35% of Eni’s current production which derives from production sharing contracts is unaffected by crude oil price movements which instead impact the Company’s volume entitlements (see disclosure below). Finally, Eni estimates that exposure to changes in crude oil prices of approximately 5-10% of Eni’s production is offset by equivalent and contrary movements in the procurement costs of gas in Eni’s long-term supply contracts which index the cost of gas to crude oil prices, reflecting Eni’s decision late in 2013 to fully exploit the benefits of the natural hedging occurring between Eni’s Exploration & Production and Gas & Power segments. In previous reporting periods Eni entered into commodity derivatives to protect margins on gas sales in Eni’s gas & power business from exposure to crude oil changes and late in 2013 Eni discontinued this policy with a view to exploiting the natural hedge provided by Eni’s production of crude oil. This development influenced Eni’s results of operations in 2014 and will affect the Group’s consolidated results going forward.

However, high oil and gas prices can adversely impact the demand for our products and consequently our profitability, especially in the refining & marketing businesses. Furthermore, a high price scenario may imply increase of costs and taxes and may negatively impact the share of production and reserve to which Eni is entitled under some Production Sharing Agreements (PSAs) (See the specific risks of the Exploration & Production segment below).

In gas markets, price volatility reflected the dynamics of demand and supply for natural gas. In 2014, gas demand in Europe dropped on average by approximately 12% in the 28-EU countries compared to the previous year driven by exceptionally mild weather conditions in the first part of the year and competition from coal and a growing share of electricity generation from renewables. Despite falling demand, gas supply has continued to increase due to a number of factors, mainly increased availability of liquefied natural gas ("LNG") on global scale, take-or-pay obligations provided by long-term supply contracts held by European gas wholesalers and the other trends described in the specific risk-factors section of our gas & power business below. The increased liquidity of European hubs put significant downward pressure on spot prices. We expect those trends to continue in the foreseeable future due to a weak outlook for gas demand and continued oversupplies. In case we fail to renegotiate our long-term gas supply contract in order to make our gas competitive as market conditions evolve, our profitability and cash flow in the Gas & Power segment would be significantly impacted by current downward trends in gas prices.

The Refining & Marketing segment is substantially affected by changes in European refining margins, which reflect changes in prices of crude oil and refined products. The prices of refined products depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather conditions. Furthermore, Eni’s realized margins are also affected by price differentials between heavy crudes versus light ones, taking into account the ability of Eni’s refineries to process complex crudes. This may represent a cost advantage for Eni when light-heavy differential widens. Finally, it is worth noting that the impact of changes in crude oil prices on Eni’s refining businesses depends on the speed at which the prices of refined products adjust to reflect movements in oil prices, as a time lag exists between movements in oil prices and in prices of finished products. Generally speaking, when oil prices decline, depending also on the rapidity and materiality of the decline, our refining margins improve on the short term, and vice versa. However, we believe that in the current depressed environment for refining margins, lower costs of the crude oil feedstock could represent only a temporary boost to our refining margins due to the structural headwinds existing in the European industry. Those headwinds include excess capacity and the competitive pressure from oil products having a cheaper cost structure than ours. See "Competition" below.

Also our Chemical segment is subject to fluctuations in supply and demand for petrochemical products and movements in crude oil prices, to which costs of feedstock are indexed, with a consequent effect on prices and profitability. Similarly to our Refining & Marketing segment, our Chemical segment has been negatively impacted by structural headwinds tied to excess capacity, weak commodity demand in Europe and the competition from cheaper products coming from Asia and the United States. See "Competition" below. Based on these negative trends, we believe that any improvement in the oil-linked costs of the petrochemical feedstock will represent only a temporary boost to our margins of petrochemical products.

7


Table of Contents

Competition

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

Eni faces strong competition in each of its business segments.

In the current uncertain financial and economic environment, Eni expects that prices of energy commodities, in particular oil and gas, will be very volatile, with average prices and margins influenced by changes in the global supply and demand for energy, as well as in the market dynamics. This is likely to increase competition in all of Eni’s businesses, which may impact costs and margins. Competition affects license costs and product prices, with a consequent effect on our margins and our market shares. Eni’s ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It is also depends on our ability to get an access to new investment opportunities, both in Europe and worldwide.
  In the Exploration & Production segment, Eni faces competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its relatively smaller size compared to other international oil companies, particularly when bidding for large scale or capital intensive projects, and may be exposed to industry-wide cost increases to a greater extent compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, as a result of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flows may be adversely affected.
  In the Gas & Power segment, Eni faces strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been fuelled by ongoing weak trends in demand due to the downturn and macroeconomic uncertainties, oversupplies which have been supported by large availability of liquefied natural gas ("LNG") on global scale, and inter-fuel competition due to rising use of coal in firing power plants due to cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic and solar) which have materially impacted the use of gas in the production of electricity and hence sales of gas to the thermoelectric industry. The extensive development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe. The continuing growth in the production of shale gas in the United States increased global gas supplies.
    These market imbalances in Europe were exacerbated by the fact that throughout the last decade and up to a few years ago the market consensus projected that gas demand in the continent would grow steadily till 2020 and beyond driven by economic growth and increased use of gas in firing power production. European gas wholesalers including Eni committed well in advance to purchasing large amounts of gas under long-term supply contracts with so-called "take-or-pay" clauses from the main producing countries bordering Europe (namely Russia and Algeria) and invested heavily to upgrade existing pipelines and to build new infrastructure along several European routes in order to expand gas import capacity to continental markets. Long-term gas supply contracts with take-or-pay clauses expose gas wholesalers to a volume risk as they are contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Due to the trends described above of the prolonged economic downturn and inter-fuel competition, the projected increases in gas demand failed to materialize, resulting in a situation of oversupply and pricing pressure. As demand contracted across Europe, gas supplies built, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs became the main benchmarks to which selling prices are indexed in supplies to large industrial customers and thermoelectric utilities. The profitability of gas operators was negatively impacted by falling sales prices at those hubs, where prices have been pressured by intense competition among gas operators in the face of weak demand, oversupplies and the constraint to dispose of minimum annual volumes of gas to be purchased under long-tem supply contracts. We believe that those headwinds have become structural ones and therefore we do not expect any meaningful improvement in the European gas sector for the foreseeable future. Gas demand will remain weak due to macroeconomic uncertainties and unclear EU policies regarding how to satisfy energy demand in Europe and the energetic mix. Supplies at continental hubs will continue building up also in view of a possible ramp-up of LNG exports from the United States due to steady growth in gas production and ongoing projects to reconvert LNG re-gasification facilities into liquefaction export units and the start of several LNG projects in the Pacific Region and elsewhere.
    We believe that these ongoing negative trends may adversely affect the Company’s future results of operations and cash flows, also taking into account the Company’s contractual obligations to off-take minimum annual volumes of gas in accordance to its long-term gas supply contracts with take-or-pay clauses.
  In its Gas & Power segment, Eni is vertically integrated in the production of electricity via its gas-fired power plants which currently use the combined-cycle technology. In the electricity business, Eni competes with other producers and traders from Italy or outside of Italy who sell electricity on the Italian market. Going forward, the Company expects continuing competition due to the projections of weak economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production in the Italian market. The economics of the gas-fired electricity business have dramatically changed over the last

8


Table of Contents
    few years due to ongoing competitive trends. Spot prices of electricity in the wholesale market across Europe decreased due to excess supplies driven by the growing production of electricity from renewable sources, which also benefited from governmental subsides, and a recovery in the production of coal-fired electricity generation which was helped by a substantial reduction in the price of this fuel on the back of a massive oversupply of coal which occurred on a global scale. As a result of falling electricity prices, margins on the production of gas-fired electricity went into negative territory. Eni believes that the profitability outlook in this business will remain weak in the foreseeable future.
  Our Refining & Marketing business faces strong competition in the marketing of refined products to final customers in the retail and wholesale markets in Italy and in certain countries in Europe where we have an established presence. The economics of this business have progressively deteriorated over the latest years due to structural headwinds in the industry. Refining and distribution margins have been negatively impacted by a combination of drivers, including weak demand for fuels due to the economic downturn particularly in Italy, high crude oil feedstock costs, trends in oil-linked costs of energy and other plant utilities, excess refining capacity across Europe and increasing competition of products streams coming from Russia, the Middle East, East Asia and the United States. This latter trend is particularly worrisome as refiners in those areas can leverage on cost advantages due to plans scale and availability of cheap raw materials. The United States for example, have become a net exporter of refined products, particularly gasoline and middle distillates, due to the tight oil revolution which has improved the competitiveness of U.S.-based refiners as prices of U.S. crudes are generally lower than the Brent crude to which crude oil purchases of European refiners are mainly indexed. Instead, Eni’s margins of refined products were affected by cost disadvantages due to unfavorable geographic location and lack of scale of Eni’s refineries. Furthermore, narrowing price differentials between the Brent benchmark and heavy crude qualities hit Eni’s profitability of complex cycles which depends upon the availability of cheaper crude qualities than the Brent crude in order to remunerate the higher operating costs of complex plants. This latter trend reflected reduced supplies of heavy crudes in the Mediterranean area, reversing the pattern observed historically whereby heavy crude qualities traded at a discount vs. the Brent benchmark due to their relatively smaller yield of valuable products. These trends negatively affected Eni’s integrated refining and marketing results of operations and cash flows in recent years. This segment reported losses at the operating level and negative cash flows for several consecutive years. In 2014, operating losses amounted to euro 2.23 billion. We believe that these competitive headwinds have become structural trends and looking forward we do not expect any reversal of those trends in the foreseeable future, thus negatively impacting the profitability outlook in our Refining & Marketing segment over the foreseeable future.
    In the retail marketing of refined products both in Italy and abroad, Eni competes with oil companies and non-oil operators (such as supermarket chains and other commercial operators) to obtain concessions to establish and operate service stations. Eni’s service stations compete primarily on the basis of pricing, services and availability of non-petroleum products. Eni expects that competitive pressures will continue in the foreseeable future.
  In the Chemical segment, Eni faces strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized segments such as the production of basic petrochemical products and plastics. Many of those competitors based in the Far East and the Middle East are able to benefit from cost advantages due to scale, favorable environmental regulations, availability of cheap feedstock and proximity to end-markets. Excess capacity and sluggish economic growth in Europe have exacerbated competitive pressures with negative impacts on profitability. Furthermore, petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas. The Company expects continuing margin pressures in its petrochemical segment in the foreseeable future as a result of those trends which we believe have become structural headwinds. This segment has reported losses at the operating level and negative cash flows for several consecutive years, driven by the trends in the industry described above. In 2014, operating losses amounted to euro 704 million. Management believes that the profitability outlook in Eni’s petrochemical segment will remain negative over the foreseeable future due to anticipated weak trends in European demand for petrochemical commodities, strong competitive pressures and overcapacity.
  Competition in the oil field services, construction and engineering industries is primarily based on technical expertise, quality and number of services and availability of technologically advanced facilities (for example, vessels for offshore construction). Lower oil prices could result in lower margins and lower demand for oil services. Failure or inability to respond effectively to competition could adversely impact the Company’s growth prospects, future results of operations and cash flows in this business. In 2014, the Company’s Engineering & Construction segment returned to profit following the sizeable losses incurred in the previous year. However the level of profitability in 2014 was below management’s own targets and initial guidance as the execution of legacy, low-margin contracts dragged down profitability. Furthermore, there was a slow ramp-up of activities at newly acquired orders due to market uncertainties and a continuing deterioration in the competitive environment. The business outlook remains challenging due to a number of headwinds. These include strong competitive pressures and risks and uncertainties relating to the acceptance by customers of the works done in the execution of certain legacy contracts which are still in progress. Finally a slowdown in oil prices may force oil companies to revise their capital budget plans and postpone investment decision. This trend may hurt profitability of our oilfield services and engineering segment in the next future years.

9


Table of Contents

Safety, security, environmental and other operational risks

The Group engages in the exploration and production of oil and natural gas, processing, transportation, and refining of crude oil, transport of natural gas, storage and distribution of petroleum products, production of base chemicals, plastics and elastomers. By their nature the Group’s operations expose Eni to a wide range of significant health, safety, security and environmental risks. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni’s activities. Eni’s future results from operations and liquidity depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries.

In Exploration & Production, Eni faces natural hazards and other operational risks including those relating to the physical characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni’s personnel and risks of blowout, fire or explosion. Accidents at a single well can lead to loss of life, damage or destruction to property, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation, liquidity, reputation and prospects of the Group.

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

All of Eni’s segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend both on the hazardous nature of the products transported, and on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road, gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people and the environment.

The Company invests significant resources in order to upgrade the methods and systems for safeguarding the safety and health of employees, contractors and communities, and the environment; to prevent risks; to comply with applicable laws and policies; and to respond to and learn from unexpected incidents. Eni seeks to minimize these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and managing its operations in a safe, compliant and reliable manner. Failure to manage these risks could effectively result in unexpected incidents, including releases or oil spills, blowouts, fire, mechanical failures and other incidents resulting in personal injury, loss of life, environmental damage, legal liabilities and/or damage claims, destruction of crude oil or natural gas wells, as well as damage to equipment and other property, all of which could lead to a disruption in operations. Eni’s operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued, because Eni’s activities require decommissioning of productive infrastructure and environmental site remediation.

Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

Eni’s insurance subsidiary provides insurance coverage to Eni’s entities, generally up to $1.1 billion in case of offshore incident and $1.5 billion in case of incident at onshore facilities (refineries). In addition, the Company also maintains worldwide third-party liability insurance coverage for all of its subsidiaries. Management believes that its insurance coverage is in line with industry practice and sufficient to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster like BP Deepwater Horizon, for example, Eni’s third-party liability insurance would not provide any material coverage and thus the Company’s liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in the event of such a disaster would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster.

The occurrence of the events mentioned above could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ return and damage the Group’s reputation.

10


Table of Contents

The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Company.

 

Risks associated with the exploration and production of oil and natural gas

The exploration and production of oil and natural gas requires high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. A description of the main risks facing the Company’s business in the exploration and production of oil and gas is provided below.

 

(i) Eni’s oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks

Eni has material operations relating to the exploration and production of hydrocarbons located offshore. In 2014, approximately 55% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Italy, Angola, the Gulf of Mexico, Congo, United Kingdom and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. As the Macondo accident in the Gulf of Mexico has shown, the potential impacts of offshore accidents and spills to health, safety, security and the environment can be catastrophic due to the objective difficulties in handling hydrocarbons containment and other factors. Further, offshore operations are subject to marine risks, including severe storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations. Failure to manage these risks could result in injury or loss of life, damage to property, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni’s reputation and could have a material adverse effect on Eni’s operations, results, liquidity, reputation and prospects.

 

(ii) Exploratory drilling efforts may be unsuccessful

Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells have margins of uncertainty, and drilling operations may be unsuccessful as a result of a large variety of factors, including geological play failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents, and shortages or delays in the delivery of equipment. The Company also engages in exploration drilling activities offshore, also in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea). In these locations, the Company generally experiences more challenging conditions and incurs higher exploration costs than onshore or in shallow waters. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to make investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Some of these activities are high-risk high reward projects that generally involve sizeable plays located in deep and ultra-deep waters or at higher depths where operations are more challenging and costly than in other areas. Furthermore, deep and ultra-deep water operations will require significant time before commercial production of discovered reserves can commence, increasing both the operational and financial risks associated with these activities. The Company plans to conduct exploration projects offshore West Africa (Angola, Nigeria, Congo, and Gabon), East Africa (Mozambique, Kenya and South Africa), South-East Asia (Indonesia, Vietnam, Myanmar and other locations), Australia, the Norwegian Barents Sea, the Mediterranean and offshore Gulf of Mexico. In 2014, the Company spent euro 1.4 billion to conduct exploration projects and plans to spend approximately euro 1.2 billion on average in the next four-year plan on exploration activities. Unsuccessful exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory program.

 

(iii) Development projects bear significant operational risks which may adversely affect actual returns

Eni is executing several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or environmentally sensitive locations. Eni’s future results of operations and liquidity depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:

11


Table of Contents
  the outcome of negotiations with co-venturers, governments and state-owned companies, suppliers, customers or others, including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves;
  the development of reliable spot markets that may be necessary to support the development of particular production projects, or commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;
  timely issuance of permits and licenses by government agencies;
  the Company’s relative size compared to its main competitors which may prevent it from participating in large-scale projects or affect its ability to reap benefits associated with economies of scale, for example by obtaining more favorable contractual terms by suppliers of equipment and services;
  the ability to carefully carry out front-end engineering design so as to prevent the occurrence of technical inconvenience during the execution phase;
  timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; these events may cause cost overruns and delays impacting the time-to-market of the reserves;
  risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
  poor performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) – turn key contractual scheme. Eni believes this kind of risk may be due to lack of contractual flexibility, poor quality of front-end engineering design and commissioning delays;
  changes in operating conditions and cost overruns. In recent years, the industry has been adversely impacted by the growing complexity and scale of projects which drove cost increases and delays, including higher environmental and safety costs. Due to the recent downtrend in crude oil prices, the Company will seek to renegotiate construction contracts, daily rates for rigs and other field services and costs for materials and other productive factors to preserve margins at its development projects. In case it fail to obtaining the planned cost reductions, its profitability in the Exploration & Production segment could be adversely affected;
  the actual performance of the reservoir and natural field decline; and
  the ability and time necessary to build suitable transport infrastructures to export production to final markets.

Events such as the ones described above of poor project execution, inadequate front-end engineering design, delays in the achievement of critical events and project milestones, delays in the delivery of production facilities and other equipment by third parties, differences between scheduled and actual timing of the first oil, as well as cost overruns may adversely affect the economic returns of Eni’s development projects. Failure to successfully deliver major projects on time and on budget could negatively impact results of operations, cash flow and the achievement of short-term targets of production growth. Finally, development and marketing of hydrocarbons reserves typically require several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-lead-time projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from the prices and costs assumed when the investment decision was actually made, leading to lower rates of return. In addition, projects executed with partners and co-venturers reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. Furthermore, Eni may not have full operation control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operation and strategic objectives due to the nature of its relationships.

For example in the Kashagan offshore field, in the Kazakh section of the Caspian Sea, the latest issue related to the downtime of a pipeline which forced the consortium to shut down production after the start-up. The damaged pipeline needs to the replaced with the consequence of additional costs to the project and the production will resume in late 2016.

Finally, in case the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment charges of capitalized costs associated with reduced future cash flows of those projects.

 

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

Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company’s reserve replacement is also affected by the entitlement mechanism in its PSAs and similar contractual schemes. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni’s proved

12


Table of Contents

reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The opposite occurs incase of lower oil prices. Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with national oil companies and other entities owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies decide to develop portion of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserves without the participation of international oil companies or if the Company fails to establish partnership with national oil companies, Eni’s ability to access or develop additional reserves will be limited.

An inability to replace produced reserves by finding, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of production growth and reserve replacement, Eni’s future total proved reserves and production will decline and this will negatively affect future results of operations and liquidity.

 

(v) Eni expects that tightening regulation in oil and gas activities following the Macondo accident will lead to rising compliance costs and other restrictions

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. Following the Macondo accident in the Gulf of Mexico, governments throughout the world have enacted stricter regulations on environmental protection, risk prevention and other forms of restrictions to drilling and other well operations. These new regulations and legislation, as well as evolving practices, increase the burden of compliance costs by requiring industry participants to adopt new security and risk prevention measures and procedures. They may also require changes to Eni’s drilling operations and exploration and development plans and may lead to higher royalties and taxes.

 

(vi) Uncertainties in estimates of oil and natural gas reserves

Several 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 depend on a number of factors, assumptions and variables, among which the most important are the following:
  the quality of available geological, technical and economic data and their interpretation and judgment;
  projections regarding future rates of production and costs and timing of development expenditures;
  changes in the prevailing tax rules, other government regulations and contractual conditions;
  results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and
  changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s production sharing agreements and similar contractual schemes.

The prices used in calculating our estimated proved reserves are, in accordance with U.S. SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our estimated proved reserves were based on 101 $/BBL for the Brent crude oil. Commodity prices declined significantly in the fourth quarter of 2014 and if such prices do not increase significantly, our future calculations of estimated proved reserves will be based on lower commodity prices which could result in our having to remove non-economic reserves from our proved reserves in future periods. This effect will be partially counterbalanced by an increase of reserves corresponding to the additional production entitlement under the PSA relating to cost oil: i.e. because of lower oil and gas prices the reimbursement of expenditures incurred by the Company requires additional volumes of reserves.

Many of these factors, assumptions and variables involved in estimating proved reserves are subject to change over time therefore impacting the estimates of oil and natural gas reserves. Accordingly, the estimated reserves reported as of the end of the period covered by this filing could be significantly different from the quantities of oil and natural gas that will ultimately be recovered. Any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.

13


Table of Contents

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

The oil and gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities. In addition, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the Italian statutory tax rate for corporate profit which currently stands at 38 per cent.

The tax rate of the Company’s Exploration & Production segment for the fiscal year 2014 was estimated at approximately 60 per cent. Eni believes that the tax rate in the Company’s Exploration & Production segment for the fiscal year 2015 will trend higher due to a projected higher share of taxable profit which will be reported in countries with higher taxation than this segment average.

Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group profit before income taxes in its oil and gas operations would have a negative impact on Eni’s future results of operations and cash flows.

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

Eni’s results depend on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to Eni’s operation.

 

(viii) The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves and, in particular, may be reduced due to the recent significant decline in commodity prices

Investors should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, we base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the U.S. SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
  the actual prices we receive for sales of crude oil and natural gas;
  the actual cost and timing of development and production expenditures;
  the timing and amount of actual production; and
  changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry in general.

At December 31, 2014, the net present value of our proved reserves totaled approximately euro 59.6 billion. The average prices used to estimate our proved reserves and the net present value at December 31, 2014, as calculated in accordance with U.S. SEC rules, were 101 $/BBL for the Brent crude oil. Actual future prices may materially differ from those used in our year-end estimates.

Commodity prices have decreased significantly in recent months. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were in line with the pricing environment existing in the first quarter of 2015, our PV-10 at December 31, 2014 could decrease significantly.

14


Table of Contents

Political considerations

A substantial portion of Eni’s oil and gas reserves and gas supplies are located in countries where the socio-political framework and macroeconomic outlook is less stable than those of the OECD countries. In those less stable countries Eni is exposed to a wide range of risks and uncertainties which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner. As of December 31, 2014, approximately 79% of Eni’s proved hydrocarbon reserves were located in such countries and 60% of Eni’s supplies of natural gas derived from non-OECD countries.

Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events in any of those less stable countries may negatively affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues:
(i)   lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
(ii)   unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriations, nationalizations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from state-owned oil companies who are partnering Eni in a number of oil and gas projects and properties in the host countries where Eni conducts its upstream operations. These state-owned oil companies can change contractual terms and other conditions of oil and gas projects in order to obtain a larger profit share from a given project, thereby reducing Eni’s profit share. Furthermore, as of the balance sheet date receivables for euro 663 million relating to cost recovery under certain petroleum contracts in a non-OECD country were the subject of an arbitration proceeding;
(iii)   restrictions on exploration, production, imports and exports;
(iv)   tax or royalty increases (including retroactive claims); and
(v)   political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions in economic activity, loss of output, plant closures and shutdowns, project delays, the loss of personnel or assets. They may force Eni to evacuate personnel for security reasons and to increase spending on security worldwide. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which Eni operates. Areas where Eni operates where the Company is exposed to the political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Indonesia, Kazakhstan, Venezuela, Iraq, Iran and Russia. In addition, any possible reprisals as a consequence of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on Eni’s business, consolidated results of operations, and consolidated financial condition. In recent years, Eni’s production levels in Libya were negatively impacted by acts of local conflict, social unrest, protests, strikes, which forced Eni to temporarily interrupt or reduce its producing activities, negatively affecting Eni’s results of operations and cash flow. Also Eni’s activities in Nigeria have been impacted in recent years by continuing episodes of theft, acts of sabotage and other similar disruptions which have jeopardized the Company’s ability to conduct operations in full security, particularly in the onshore area of the Niger Delta. Looking forward, Eni expects that those risks will continue to affect Eni’s operations in those countries. Particularly, the uncertain socio-political outlook in Libya and unsafe operational conditions onshore Nigeria were factored in the Company’s projections of future production levels in these two countries. For more information about the status of Eni’s operations in Libya see “Risks associated with continuing political instability in North Africa and the Middle East” below.

In the current low oil price environment, the financial outlook of few countries where Eni’s hydrocarbons reserves are located has significantly deteriorated due to a contraction in the proceeds associated with the exploitation of hydrocarbons resources. This may increase the risk of default which may lead to higher political and macroeconomic instability. Furthermore in few cases, Eni is partnering with the national oil companies of such countries in executing oil&gas development projects. A possible sovereign default might jeopardize the financial feasibility of ongoing projects or increase the financial exposure of Eni which would be forced to finance the share of development expenditures of the first party.

There are certain instances where Eni is contractually obligated to finance the share of costs of the first party. This risk is mitigated by the customary default clause which states that in case of a default, the non-defaulting party is entitled to compensate its claims with the share of production of the defaulting party.

While the occurrence of those events is unpredictable, it is likely that the occurrence of such events could adversely impact Eni financial exposure.

15


Table of Contents

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

As of the end of 2014, approximately 27% of the Company’s proved oil and gas reserves were located in North Africa and the Middle East. Since 2011, several North African and Middle Eastern oil producing countries have been experiencing an extreme level of political instability that has resulted in changes of governments, internal conflict, unrest and violence which led to economic disruptions and shutdowns in industrial activities.

The instability of the socio-political framework in those countries still represents an area of concern involving risks and uncertainties for the foreseeable future. Particularly, the internal situation in Libya continues to represent an issue to Eni’s management. Following the internal conflict of 2011 and the fall of the regime which forced the Company to shutdown almost all its producing facilities including gas exports for a period of about 8 months, a period of social and political instability began which turned into disorders, strikes, protests and a resurgence of the internal conflict. These events jeopardized Eni’s ability to perform its industrial activity in safety, forcing the Company to interrupt its operations on certain occasions as precautionary measure. These events were fairly frequent in 2013 and more sporadic in 2014. In 2014, Eni’s facilities in Libya produced on average 233 KBOE/d, registering a small increase compared to 2013.

The political instability in Egypt hindered the Country’s access to the financial markets, and resulted in continued difficulties for the local oil and gas companies to fulfill financial obligations towards international oil companies including trade payables due to Eni which supplies its oil and gas entitlements to local companies. Eni has not experienced any disruptions at its producing activities in the Country to date.

The Company believes that the political outlook in North Africa and the Middle East remains an area of risk for the Company’s operations, results, liquidity and prospects. In light of the recent developments in Libya, management decided to strengthen security measures at the Company’s production installations and facilities in the Country. However, we did not suffer any significant production shutdowns in the first part of 2015 up to the filing date.

 

Risks associated with Eni’s presence in sanction targets

Eni is currently engaging in residual oil and gas operations in Iran. The legislation and other regulations in the United States and the European Union that target Iran and persons who have certain dealings with Iran may lead to the imposition of sanctions on any persons doing business in Iran or with Iranian counterparties, unless specific authorizations, exceptions and assurances apply, as is currently the case for Eni. With reference to recent sanctions imposed on Russia, see "An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally" below.

 

United States measures towards Iran

The United States enacted the Iran Sanctions Act of 1996 (ISA), which required the President of the United States to impose sanctions against any entity that is determined to have engaged in certain activities, including investing in Iran’s petroleum sector. The ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 (CISADA) which targets activities that either: (i) support the maintenance or expansion of Iran’s domestic production of refined petroleum products, or (ii) contribute to the enhancement of Iran’s ability to import refined petroleum products.

CISADA expanded the list of sanctions available to the President of the United States while at the same time providing that an investigation need not be initiated, and may be terminated once begun, if the President certifies in writing to the U.S. Congress that the person whose activities in Iran were the basis for the investigation is no longer engaging in those activities or has taken significant steps toward stopping the activities, and that the President has received reliable assurances that the person will not knowingly engage in any sanctionable activity in the future.

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

The United States maintains, however, broad and comprehensive economic sanctions targeting Iran that are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC sanctions”). These

16


Table of Contents

sanctions generally restrict the dealings of U.S. citizens and persons subject to the jurisdiction of the United States. In addition, Eni is aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. CISADA specifically authorized certain state and local Iran-related divestment initiatives. If Eni’s operations in Iran are determined to fall within the scope of divestment laws or policies, sales resulting from such divestment laws and policies, if significant, could have an adverse effect on the value of Eni’s shares. Even if Eni’s activities in and with respect to Iran do not expose it to sanctions or divestment, companies with investments in the oil and gas sectors in Iran may suffer reputational harm as a result of increased international scrutiny.

Between the end of 2011 and 2013, the United States adopted new measures designed to intensify the scope of U.S. sanctions against Iran, in particular related to Iran’s energy and financial sectors.

Such restrictive measures are: the Executive Orders 13590 of November 21, 2011 and 13622 of July 31, 2012, the Iran Threat Reduction and Syrian Human Rights Acts of August 10, 2012 (ITRSHRA), which expanded the ISA/CISADA scope by increasing from three to five the minimum number of sanctions to be imposed in case of violations of the energy sector restrictions; the National Defense Authorization Acts - 2012, related to transactions with the Iranian Central Bank and transactions for the acquisition of Iranian crude oil and the National Defense Authorization Acts - 2013, which, inter alia, adds the shipbuilding sector to those areas subject to sanctions.

While Eni has no formal assurances that the U.S. State Department’s 2010 determination of non-sanctionability under the ISA would similarly extend to sanctions under the measures issued in 2011, 2012 and 2013, during this period, Eni has continued to inform the U.S. State Department of its Iran-related activities. Eni does not believe that its activities in Iran (the completion of existing contracts which were notified to the U.S. Administration when the Special Rule was applied) are sanctionable under such more recent measures described above.

 

European Union restrictive measures towards Iran

On March 23, 2012, the Council of the European Union enacted a regulation which prohibits the supply, import and transport of Iranian crude oil and petroleum products. The rules waive the execution of contracts entered into force before January 23, 2012, whereby the supply of Iranian crude oil and petroleum products is intended to reimburse outstanding receivables due to entities under the jurisdiction of EU Member States. According to these waivers, Eni received by the empowered European Member States’ Authorities the relevant authorizations in order to carry out its oil import activities from Iran. This waiver is renewed from time to time.

In 2012, the Council of the European Union adopted a new round restrictive measures against Iran including among others: prohibition of transactions between the European Union and Iranian banks and financial institutions, unless an authorization is granted in advance by the relevant Member State, an embargo on the supply to Iran and use in Iran of key equipment or technology which could be used in the sectors of the oil, natural gas and petrochemical industries from April 15, 2013.

Furthermore, the new measures designate new Iranian entities as subject to asset freeze, including the Iranian oil and gas industry companies (the National Iranian Oil Co - NIOC and its subsidiary operating companies).

Eni has been operating in Iran for several years under four service contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the NIOC between 1999 and 2001, and no other exploration and development contracts have been entered into since then. Under such service contracts, Eni has carried out development operations in respect of certain oilfields, and is entitled to recovery of expenditures made, as well as a service fee. All projects mentioned above have been completed: the Darquain project was handed over to NIOC in the final months of 2014 and as such Eni’s obligations to provide technical assistance, commissioning services and spare parts and supplies for field maintenance and operations have been winded down. In 2014, Eni incurred operating expenses of $1 million to provide such activities and services and does not expect to incur further operating costs in this respect. Therefore, Eni’s only involvement in the Country will be the recovery of its past investments.

Eni’s projects in Iran are currently in the cost recovery phase. Therefore, Eni has ceased making any further investment in the Country and is not planning to make additional capital expenditures in Iran in future years. In 2014, Eni’s production in Iran averaged less than 1 KBOE/d, and is negligible in comparison with Eni Group’s total production. Eni’s entitlement in 2014 represented approximately 1 per cent of the overall production from the oil and gas fields that Eni has developed in Iran. Eni believes that the results from its Iranian activities are immaterial to the Group’s results of operations and cash flow.

17


Table of Contents

Eni has no involvement in Iran’s refined petroleum sector and does not export refined petroleum to Iran.

Finally, Eni’s Chemical segment licensed a number of technologies in Iran in past years, relating to plastics/elastomers and relevant raw materials, but it never supplied equipment or materials for plant construction. By April 2013, Eni had suspended all contracts to comply with EU restrictions.

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

 

An escalation of the political crisis in Russia and Ukraine could affect Eni’s business in particular and the global energy supply generally

The political crisis in Ukraine and the Crimean Peninsula unfolded in February 2014 and led to the impeachment of the President of Ukraine Viktor Yanukovych and the subsequent reaction by the Russian Federation. In March 2014, the announcement of the Supreme Council of Crimea and the City Council of Sevastopol of their intention to declare Crimea’s independence from Ukraine as a single united nation with the possibility of joining the Russian Federation as a federal subject was followed by a referendum where 96 per cent of those who voted in Crimea supported joining Russia. The Russian Federation annexed Crimea immediately after the result of the referendum. The Ukrainian Parliament, the United States and the European Union consider the referendum to be illegal and unconstitutional. Sanctions were imposed by the EU and the United States on officials and politicians from Russia and Crimea. Subsequently, allegations that the Russian Government has provided military and other support to separatists in Ukraine have led to further EU and U.S. sanctions.

Eni is closely monitoring developments to the political situation in Russia, Ukraine and the Crimea Region, is adapting its business activities to the sanctions already adopted by the relevant authorities and will adapt to any further related regulations and/or economic sanctions that could be adopted by the authorities.

Among other activities, Eni is currently part of a strategic co-operation agreement for exploration activities in the Russian sections of the Barents Sea and the Black Sea. Contracts pertaining to this exploration were entered into before enactment of the restrictive measures. Eni also holds a 50% interest in the Blue Stream pipeline which links the Russian and Turkish coasts and transport volumes of gas which are jointly supplied by Eni and is Russian partner to Turkish companies.

The EU and U.S.-enacted sanctions are mainly target the financial sector and the energy sector in Russia. The EU sanctions relating to the upstream sector in Russia may negatively impact our ongoing activities, mainly in the exploration sector, unless the Company obtains a waiver from the relevant EU Authorities for projects entered into before enactment of restrictions. Eni started the required authorization procedure before the relevant EU Authorities. However, the outcome is uncertain and we cannot exclude major delays in certain ongoing upstream projects in Russia.

It is possible that wider sanctions covering the Russian energy, banking and/or finance industries may be implemented, which may be targeted at specific individuals or companies or more generally. Further sanctions imposed on Russia, Russian individuals or Russian companies by the international community, such as sanctions enacting restrictions on purchases of Russian gas by European companies or restricting dealings with Russian counterparties could adversely impact Eni’s business, results of operations and cash flow. In addition, an escalation of the crisis and of imposed sanctions could result in a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group’s business, financial conditions, results of operations and future prospects.

 

Risks in the Company Gas & Power business

(i) Risks associated with the trading environment and competition in the industry

The Company expects that the profitability outlook in its Gas & Power segment will be negatively affected by a projected weak demand recovery, strong competitive pressures and oversupplies. We believe that these downtrends have become structural headwinds. Gas demand was severely hit by the economic slowdown in Europe and, more importantly, a steep fall in consumption in the thermoelectric sector. The latter trend was affected by an ongoing expansion of renewable sources of electricity which have benefited from governmental subsides across Europe, whilst coal has displaced gas on a large scale in firing power plants due to cost advantages and lowering rates for obtaining emission allowances in Europe due to the economic downturn. Coal prices have seen a dramatic fall in recent years due to a massive glut of coal on a global scale. We do not expect any meaningful recovery in demand for the foreseeable

18


Table of Contents

future. In the face of weak demand, supplies on the European marketplace have continued to increase due to a number of factors. First of all, before the beginning of the downturn, gas wholesaler operators in Europe (overestimating the projected growth rates in demand) were committed to purchase large amounts of gas under long-term supply contracts with producing countries also bearing the volume risk as a result of the take-or-pay clause of those contracts. They also built large pipeline upgrades to import gas to Europe. Secondly, several LNG projects came on stream, which improved the liquidity of spot markets. Finally, production of shale gas in the United States continued to ramp-up forcing LNG exporters from the Gulf Region and other areas to redirect their LNG supplies to other markets, contributing to increase global gas supplies. Besides certain operators in the United States are planning to build or are actually building LNG export facilities. Those trends drove the expansion of very liquid European hubs where spot prices have become the prevailing benchmark of sale contracts, particularly in the industrial and thermoelectric segments. Spot prices have been on a downtrend over the last few years pressured by oversupplies and weak demand. This trend hit the profitability of European gas marketing operators, including Eni. In particular, Eni’s results of operations were adversely impacted by a faster than anticipated alignment between continental benchmarks and spot prices at Italian hubs leading to sharply lower price realizations in the Italian wholesale market, which is the main market to the Company Gas & Power segment. Adding to the pressure, reduced sales opportunities due to weak demand forced operators to compete even more aggressively on pricing to limit the financial risks associated with the take-or-pay clause provided by the long term supply contracts. Eni forecasts that market conditions will remain unfavorable in the gas sector in Italy and Europe for the foreseeable future due to the structural headwinds described above, volatile commodity prices and lack of visibility. Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the next two to three years. Those include weak demand growth due to a projected slow recovery in the Euro-zone and macroeconomic uncertainties, declining thermoelectric consumption due to inter-fuel competition, continuing oversupplies and strong competition. Eni believes that those trends will negatively impact the gas marketing business future results of operations and cash flows by reducing gas selling prices and margins, also considering Eni’s obligations under its take-or-pay supply contracts.

 

The Company is seeking to improve its cost competitiveness by renegotiating more favorable contractual terms with Eni’s long-term suppliers. If it fails to achieve this its profitability could be adversely affected

The Company’s long-term supply contracts provide clauses whereby the parties are entitled to renegotiate pricing terms and other contractual conditions from time to time to reflect a changed market environment. The Company plans to renegotiate better terms and pricing of Eni’s long-term supply contracts in the coming years to align its cost structure which comprise the raw material purchase cost and the associated logistic costs to prices prevailing in the marketplace in order to preserve the profitability of its gas operations and to fulfill the contractual obligation of off-taking the annual minimum take in its long-term supply contracts. If it fails to obtain the planned benefits, future results and cash flow could be adversely affected.

The outcome of the planned renegotiations is uncertain in respect of both the amount of the economic benefits which will be ultimately achieved and the timing of recognition in profit. Should we fail to obtain revised contractual terms, we will evaluate whether to commence arbitration proceedings to satisfy our claims. However, arbitration proceedings may require complex and lengthy processes in order to reach a ruling, thus adding to the uncertainty about the final outcome of those renegotiations. Considering also ongoing price renegotiations with Eni long-term buyers, results of gas marketing activities are subject to an increasing rate of volatility and unpredictability.

 

Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts

In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market and anticipating certain trends in gas demand which actually failed to materialize, Eni has signed a number of long-term gas supply contracts with national operators of key producing countries that supply the European gas markets. These contracts have a residual life of approximately 13 years. These contracts include take-or-pay clauses whereby the Company is required to off-take minimum, pre-set volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to the minimum contractual quantity. The take-or-pay clause entitles the Company to off-take pre-paid volumes of gas in later years. Amounts of cash pre-payments and time schedules for off-taking pre-paid gas vary from contract to contract. Generally, cash pre-payments are calculated on the basis of the energy prices current in the year when the Company is scheduled to purchase the gas, with the balance due in the year when the gas is actually purchased. Amounts of prepayments range from 10 to 100 per cent of the full price.

The right to off-take pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, the right to off-take the pre-paid gas can be exercised in future years provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity. In this case, Eni will pay the residual price calculating it as the percentage that complements

19


Table of Contents

100 per cent, based on the arithmetical average of monthly base prices current in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.

Although during the recent supply contract round of renegotiations the minimum pre-set volumes of gas that the Company is required to off-take has been significantly reduced, management believes that the current market outlook which will be driven by a weak recovery in gas demand and large gas availability, as well as strong competitive pressures in the marketplace and the possible changes in the sector specific regulation represent a risk factor to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts, considering also the Company’s plans for its sales volumes which are anticipated to remain flat or to decrease slightly in 2015 and in the subsequent years.

This risk materialized during the sector downturn in 2009 through 2012 when the Company accumulated deferred costs amounting to euro 1.9 billion paying the related cash advances to its gas suppliers due to the incurrence of the take-or-pay clause. This amount was substantially reduced in the subsequent years by approximately 50% due to the benefits of contract renegotiations and other commercial initiatives.

 

(ii) Risks associated with sector-specific regulations in Italy

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

The Authority for Electricity Gas and Water (the “AEEGSI”) is entrusted with certain powers in the matter of natural gas pricing. Specifically, the AEEG has general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users (as provided for by Resolution ARG/gas No. 64/2009) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the AEEGSI on these matters may limit the ability of Eni to pass an increase in the cost of the raw material onto final consumers of natural gas.

Effective on October 1, 2013, AEEGSI with Resolution No. 196 reformulated the pricing mechanism of gas supplies to retail customers by introducing a full indexation of the raw material cost component of the tariff to spot prices which replaced an oil-linked indexation. The new regulatory regime negatively impacted the Gas & Power results of operations and cash flow in 2014 compared to 2013 due to unfavorable trends in hub-based pricing to residential compared to the previous oil-linked tariff.

Furthermore, this new regulation provides a mechanism of compensation which addresses the wholesaler operators, as in the case of Eni, who have long-term procurement contracts to supply the Italian market and is designed to promote effective renegotiations of these contracts. The compensation mechanism covers a three-year period and is intended to indemnify wholesalers of possible unfavorable spreads between the oil-linked average prices of gas imported to Italy and the spot prices of gas in sales to residential customers. Vice versa, in case of favorable trends in the above mentioned spreads, the wholesalers have an obligation to refund residential customers. Wholesalers are free to adhere to this compensation mechanism. Eni elected to adhere to it. In 2014, due to unfavorable trends in the cost of oil-linked supplies with respect to spot prices to which gas selling prices are indexed, based on the Authority’s index of procurement costs the Company recognized a gain of euro 60 million. However, due to the current downturn in crude oil prices, Eni is projecting that the oil-linked index of the procurement costs set by the Authority could determine a loss to Eni up to euro 480 million. This contingent liability reflects the fact that the Authority index is not reflective of the current setup of Eni’s portfolio of gas supply costs which due to the renegotiations achieved in 2014 is largely indexed to hub prices and therefore Eni’s procurement costs are not expected to benefit from a fall in oil-linked gas procurement costs. It is still possible that the Authority updates its index of procurement costs to better reflect the status of the gas portfolio of those wholesalers who achieved new pricing terms for their gas supplies. Alternatively, Eni might file an administrative appeal against any deliberations of the Authority on this matter which might possibly lead to unfair results to Eni.

 

Due to a structurally adverse competitive environment in our Refining & Marketing and Chemicals segments, our prospects to recover profitability depends on our ability to restructure those businesses

Our Refining & Marketing and Chemical segments have been unprofitable for many years to date. Those trends reflected (in addition to movements in the cost of crude oil), competitive disadvantages of our businesses due to industry excess capacity, lack of efficient scale at our refining and chemicals plants and competition from cheaper oil products and commodities coming from Asia, Russia and the United States. We believe that these trends will not reverse in the foreseeable future. We plan on rightsizing our production capacity in those businesses through plant closure, divestments, restructuring and plant conversion to production based on renewable feedstock. If we fail to

20


Table of Contents

implement capacity restructuring and rationalization as planned, our business, results of operations and financial condition and cash flow could be negatively impacted.

 

Antitrust and competition law

The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. It is possible that the Group may incur significant loss provisions in future years relating to ongoing antitrust proceedings or new proceedings that may possibly arise. The Group is particularly exposed to this risk in its natural gas, refining and marketing and petrochemical activities due to the fact that Eni is the incumbent operator in those markets in Italy and a large European player. Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to compensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the Group’s future results of operations and cash flows.

 

Environmental, health and safety regulations

Eni has incurred in the past and will incur material operating expenses and expenditures in relation to compliance with applicable environmental, health and safety regulations in future years

Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, refining, chemicals, hydrocarbons transportation and other activities. Generally, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining, petrochemical and other Group’s operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the Company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees’ or communities’ health and safety resulting from oil, natural gas, refining, petrochemical and other Group’s operations.

These laws and regulations also regulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface of water resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials.

Breach of environmental, health and safety laws expose the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage, as well as damage to its reputation. Additionally, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace, the Company can be liable for negligent or willful conduct on part of its employees as per Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations addressing the safeguard of the environment, safety on the workplace, health of employees, contractors and communities involved by the Company operations, including:
  costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change;
  remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);
  damage compensation claimed by individuals and entities, including local, regional or state administrations, in case Eni causes any kind of accident, pollution, contamination or other environmental liability involving its operations or the Company is found guilty of violating environmental laws and regulations; and
  costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging.

 

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

21


Table of Contents
  installing pollution control equipment;
  implementing additional safety measures; and
  performing site clean-ups.

As a further result of any new laws and regulations or other factors, Eni may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish Eni’s productivity and materially and adversely impact Eni’s results of operations, including profits. Security threats require continuous assessment and response measures. Acts of terrorism against Eni’s plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change could have a negative impact on Eni’s business and may result in additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which Eni conducts business. Because Eni’s business depends on the global demand for oil and natural gas, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on Eni’s business if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide that could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management’s belief that Eni adopts high operational standards to ensure the safety of its operations and the protection of the environment and the health of people and employees, it is possible that incidents like blowouts, oil spills, contaminations, pollution, release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and similar events could occur that would result in damage to the environment, employees and communities. The occurrence of any such events could have a material adverse impact on the Group business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ return and damage to the Group reputation.

Eni has incurred in the past and may incur in the future material environmental provisions in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. In Italy, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, natural resource damages, and other damages as a result of Eni’s conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Also plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case the Company is found guilty of having violated any environmental laws or regulations.

Eni is periodically notified of potential liabilities at Italian sites. These potential liabilities may arise from both historical Eni operations and the historical operations of companies that Eni has acquired. Many of those potential liabilities relate to certain industrial sites that the Company disposed of, liquidated, closed or shut down in prior years where Group products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities. At those industrial locations Eni has commenced a number of initiatives to restore and clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. Notwithstanding the Group’s position that it cannot be held liable for contaminations occurred in past years or (as permitted by applicable regulations in case of declaration rendered by a guiltless owner i.e. as a result of Eni’s conduct that was lawful at the time it occurred) or because Eni took over operations from third parties, nonetheless several public administrations used Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company.

Eni expects remedial and clean-up activities at Eni’s sites to continue in the foreseeable future impacting Eni’s liquidity. As of December 31, 2014, the Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amounts represent the management’s best estimates of the Company’s liability.

Management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain of Eni’s industrial sites as

22


Table of Contents

required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations and the Italian Ministry of the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites.

As a result of those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s liquidity, consolidated results of operations, and consolidated financial condition.

 

Risks related to legal proceedings and compliance with anti-corruption legislation

Eni is the defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of December 31, 2014 to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate.

Certain legal proceedings where Eni or its subsidiaries or its officers are parties involve the alleged breach of anti-corruption laws and regulations and ethical misconduct. Ethical misconduct and non-compliance with applicable laws and regulations, including non-compliance with anti-bribery and anti-corruption laws, by Eni, its partners, agents or others that act on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation and shareholder value.

 

Risks from acquisitions

Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or companies in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – a significant risk, among other matters, that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks connected to acquisitions materialize, Eni’s financial performance and shareholders’ returns may be adversely affected.

 

Risks deriving from Eni’s exposure to weather conditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing segment, as well as the comparability of results over different periods may be affected by such changes in weather conditions. In general, the effects of climate change could result in less stable weather patterns, resulting in more severe storms and other weather conditions that could interfere with Eni’s operations and damage Eni’s facilities. Furthermore, Eni’s operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to Eni’s operations and consequent loss or damage of properties and facilities.

 

Eni’s crisis management systems may be ineffective and Eni may be the target of cyber attacks

Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed time frame could prolong the impact of any disruption and could severely affect business and operations. Likewise, Eni has crisis management plans and capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, its business and operations could be severely disrupted.

23


Table of Contents

Exposure to financial risk

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

Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts which are not covered by contracted sales, its refining margins and other activities. The Group’s risk management objectives in addressing commodity risk are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group’s exposures and to profit from short-term market opportunities and trading. The Group’s risk management has evolved particularly in response to the major changes which have occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets.

Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over The Counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage the commodity risk exposure. Eni also uses financial instruments to manage foreign exchange and interest rate risk.

The Group’s approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group’s Chief Executive Officer is responsible for implementing the Group risk management strategy, while the Group’s Chief Financial and Risk Management Officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities.

Various Group committees are in charge of defining internal criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni’s top level, to be used by the Group’s business units, including monitoring and controlling activities. Although Eni believes it has established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.

 

Commodity risk

Commodity risk is the risk associated with fluctuations in the price of commodities which may impact the Group’s results of operations and cash flow. Exposure to commodity risk is both of a strategic and commercial nature. Generally, the Group does not hedge its strategic exposure to commodity risk. However, the Group actively manages its exposure to commercial risk arising when a contractual sale of a commodity has occurred or it is highly probable that it will occur and the Group aims to lock in the associated commercial margin.

The Group’s risk management policies have evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, volatile gas margins and development of liquid markets to trade spot gas. These policies also contemplate the use of derivative contracts for speculative purposes whereby Eni is seeking to profit from opportunities available in the gas market based, among other things, on its expectations regarding trends in future prices.

As part of those trading activities, the Company is implementing strategies of asset-backed trading in order to maximize the economic value of the flexibilities associated with its assets. Management believes that the price risks related to asset-backed trading activities are mitigated by the natural hedge granted by the assets’ availability.

These derivative contracts entered into for trading purposes may lead to gains, as well as losses, which, in each case, may be significant. Those derivatives are accounted for through profit and loss, resulting in higher volatility in Eni’s earnings.

 

Exchange rate risk

Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni’s expenses are denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Chemical 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

24


Table of Contents

on Eni’s results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni’s shareholders’ equity. The Exploration & Production segment is particularly affected by movements in the U.S. dollar versus the euro exchange rates as the U.S. dollar is the functional currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations. In 2014, the Exploration & Production results of operations were marginally affected by trends in exchange rate of the euro against the U.S. dollar as the average exchange rate for the full year was substantially flat at 1 EUR = 1.33 US$. However, the decline of the euro against the U.S. dollar in the fourth quarter 2014 resulted in a appreciation of approximately 12% of the U.S. dollar at the closing rate on December 31, 2014 with respect to the closing rate at December 31, 2013 which movements boosted the Group net equity by approximately euro 5 billion as a result of the translation differences of the net assets of dollar-denominated subsidiaries. This trend has continued in the first quarter of 2015.

 

Susceptibility to variations in sovereign rating risk

Eni’s credit ratings are potentially exposed to risk in reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the Notes or other debt instruments issued by the Company could be downgraded.

 

Interest rate risk

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

 

Liquidity risk

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

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation and production of oil and natural gas reserves.

Historically, our capital expenditures have been financed with cash generated by operations, proceeds from asset disposal, borrowings under our credit facility and proceeds from the issuance of debt and bonds. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments.

Our cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:
  the amount of our proved reserves;
  the volume of crude oil and natural gas we are able to produce and sell from existing wells;
  the prices at which crude oil and natural gas are sold;
  our ability to acquire, find and produce new reserves; and

25


Table of Contents
  the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our bonds.

If revenues or our ability to borrow decrease significantly due to factors like a prolonged decline in crude oil and natural gas prices, we might have limited ability to obtain the capital necessary to sustain our planned capital expenditures. If cash generated by operations, cash from asset disposal, or cash available under our liquidity reserve or our credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of our reserves, which in turn could adversely affect our business, financial condition, results of operations, and cash flows and our ability to achieve our growth plans.

In addition, funding our capital expenditures with additional debt will increase our leverage and the issuance of additional debt will require a portion of our cash flows from operations to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund capital expenditures and dividends.

 

Credit risk

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In recent years, the Group has experienced a higher than normal level of counterparty default due to the severity of the economic and financial downturn and the amount of trade receivables overdue at the balance sheet date has increased significantly. In Eni’s 2014 Consolidated Financial Statements, Eni accrued an allowance against doubtful accounts amounting to euro 531 million (compared to euro 384 million), mainly relating to the Gas & Power business. Management believes that this business is particularly exposed to credit risks due to its large and diversified customer base which include a large number of medium and small sized businesses and retail customers who have been particularly impacted by the financial and economic downturn. However, trade receivable amounts due at the balance sheet date have also increased in relation to supplies of the Group’s products to state-owned companies, public administrations and other governmental agencies in Italy and abroad. Eni believes that the management of doubtful accounts represents an issue to the Company which will require management focus and commitment going forward. In the future we cannot exclude the recognition of significant provisions for doubtful accounts.

 

Critical accounting estimates

The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience and other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and other risk provisions and recognition of revenues in the oilfield services construction and engineering businesses. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information, availability of new informative elements, variations in economic conditions such as prices, costs, other significant factors including evolution in technologies, industrial practices and standards (e.g. removal technologies) and the final outcome of legal, environmental or regulatory proceedings.

 

Digital infrastructure is an important part of maintaining Eni’s operations, and a breach of Eni’s digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs

The reliability and security of Eni’s digital infrastructure is critical to maintaining the availability of Eni’s business applications, including the reliable operation of technology in Eni’s various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni’s systems for protecting Eni’s digital security prove not to be sufficient, either due to intentional actions such as cyber attacks or due to negligence, Eni could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having Eni’s business operations interrupted, and increased costs to prevent, respond to, or mitigate potential risks to Eni’s digital infrastructure; also, in some circumstances, failures to

26


Table of Contents

protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

 

The Company’s auditors, like all other independent registered public accounting firms operating in Italy, are not permitted to be subject to inspection by the Public Company Accounting Oversight Board, and accordingly, investors may be deprived of the benefits of such inspection

The independent registered public accounting firm that issues the audit reports included in Eni’s annual reports filed with the U.S. Securities and Exchange Commission (the U.S. SEC), as auditor of companies that are traded publicly in the United States and firms registered with the Public Company Accounting Oversight Board, or PCAOB, is required by the laws of the United States to undergo regular inspections by the PCAOB to assess its compliance with U.S. SEC rules and PCAOB professional standards.

Because Eni’s auditor is a registered public accounting firm in Italy, a jurisdiction where the PCAOB is currently unable under Italian law to conduct inspections pending the mutual agreement between the PCAOB and the Italian Authorities, Eni’s auditor, like all other independent registered public accounting firms in Italy, is currently not inspected by the PCAOB. Inspections of audit firms that the PCAOB has conducted where allowed have identified deficiencies in those firms’ audit procedures and quality control procedures, which may be addressed as part of the inspection process to improve future audit quality. The lack of PCAOB inspections in Italy prevents the PCAOB from regularly evaluating Eni’s auditor’s audits and quality control procedures. As a result, the inability of the PCAOB to conduct inspections of auditors in Italy may deprive investors of the benefits of PCAOB inspections.

 

 

 

 

 

 

27


Table of Contents

Item 4. INFORMATION ON THE COMPANY

History and development of the Company

Eni SpA with its consolidated subsidiaries engages in oil and gas exploration, development and production, marketing of gas, electricity and LNG, power generation, refining and marketing of petroleum products, production and marketing of petrochemical products, commodity trading and oilfield services and engineering industries. Eni has operations in 83 countries and 84,405 employees as of December 31, 2014.

Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.

Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in:
  San Donato Milanese (Milan), Via Emilia, 1; and
  San Donato Milanese (Milan), Piazza Ezio Vanoni, 1.
Internet address: eni.com

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

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations in 40 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2014, Eni average daily production amounted to 1,517 KBOE/d on an available-for-sale basis. As of December 31, 2014, Eni’s total proved reserves amounted to 6,602 mmBOE; proved reserves of subsidiaries totaled 5,772 mmBOE; Eni’s share of reserves of equity-accounted entities was 830 mmBOE. In 2014, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 28,488 million and operating profit of euro 10,766 million.

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international gas transport activities, and LNG supply and marketing. This segment also includes the activity of electricity generation that is ancillary to the marketing of electricity. In 2014, Eni’s worldwide sales of natural gas amounted to 89.17 BCM. Sales in Italy amounted to 34.04 BCM, while sales in European markets were 55.13 BCM which included 4.01 BCM of gas sold to certain importers to Italy. Eni produces power at a number of operated sites in Italy with a total installed capacity of 4.9 GW as of December 31, 2014. In 2014, sales of power totaled 33.58 TWh. In 2014, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 28,250 million and operating profit of euro 186 million.

Eni’s Refining & Marketing segment engages in crude oil supply and refining and marketing of petroleum products at retail and wholesale markets mainly in Italy and in the rest of Europe. In 2014, processed volumes of crude oil and other feedstock amounted to 25.03 mmtonnes and sales of refined products were 44.41 mmtonnes, of which 22.76 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 9.21 mmtonnes in Italy and in the rest of Europe. In 2014, Eni’s retail market share in Italy through its "Eni" and "Agip" branded network of service stations was 25.5%. In 2014, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 56,153 million and operating loss of euro 2,229 million.

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

28


Table of Contents

Eni’s chemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s chemical operations are concentrated in Italy and Western Europe. In 2014, Eni sold 3.46 mmtonnes of chemical products. In 2014, Eni’s Chemical segment reported net sales from operations (including inter-segment sales) of euro 5,284 million and operating loss of euro 704 million.

Eni engages in oilfield services, construction and engineering activities through its partially-owned subsidiary Saipem and Saipem’s controlled entities (Eni’s interest being 42.91%). Saipem provides a full range of engineering, drilling and construction services to the oil and gas industry and downstream refining and petrochemical sectors, mainly in the field of performing large EPC contracts offshore and onshore for the construction and installation of fixed platforms, sub-sea pipe laying and floating production systems and onshore industrial complexes. In 2014, Eni’s Engineering & Construction segment reported net sales from operations (including intragroup sales) of euro 12,873 million and operating profit of euro 18 million.

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

 

Strategy

In order to manage a radically changed price environment, the Company outlined for the next four-year period an action plan which comprises a number of rigorous initiatives and objectives in order to mitigate the impact of lower oil prices and to preserve a robust financial structure, particularly in the short to medium term. Our oil price assumptions for the Brent benchmark are $55 per barrel in 2015 and we expect a gradual recovery in the subsequent years up to our long term case of $90 per barrel. Against the backdrop of a low price environment in the short to medium term, our primary target remains cash generation which will be underpinned by well-designed industrial actions, capital discipline, focus on Exploration & Production activities and a large disposal plan. In approving the capital expenditure plan the Company selected high-return projects with short pay-back periods; this optimization will result in a euro 48 billion capital expenditures in the next four years, down by approximately 17% compared to the previous plan, net of exchange rate effects. The disposal plan, amounting to more than euro 8 billion in the 2015-2018 period, is based on the anticipated monetization of exploratory discoveries, optimization of the upstream portfolio, rationalization of midstream and downstream portfolio, and the divestment of residual interests in Snam and Galp. The Company forecasts that the planned industrial actions, the selective approach to capital expenditure and the disposal plan will enable Eni to preserve a robust financial structure and we plan to maintain the leverage below the threshold of 0.3 throughout the oil cycle. As part of its effort to preserve liquidity and the balance sheet, the Company decided to rebase the dividend as it is planning to pay a dividend of euro 0.8 per share for fiscal year 2015. In the subsequent years, management will re asses its progressive dividend policy against the backdrop of an expected improvement in the oil price scenario and the planned growth in our cash generation as our value-generation strategy in Exploration & Production and our turnaround of Gas & Power, Refining & Marketing and Chemicals progress towards our goals. See “Item 5 – Management’s expectations of operations”.
  In the Exploration & Production segment we plan to preserve cash generation in a low oil price environment. To achieve this objective we plan the following strategic actions: (i) focus on near-field exploration reducing expenditures; (ii) fast track development of discovered resources through the optimization of the time-to-market and strict control of project execution; (iii) monetization of interests in discoveries made; (iv) production growth at an average rate of 3.5% across the plan period, maintaining a solid base of long plateau/long-term cash flow projects; (v) modular approach and phased project development in order to reduce the financial exposure and fasten production start-up; and (vi) increased efficiency through a wide range of actions aimed at reducing operating costs, pursued also through the renegotiations of supply contracts.
  In the Gas & Power segment we are seeking to preserve the economic and financial sustainability in the long term against the backdrop of structural headwinds in the European gas sector where we do not expect significant improvement in the trading environment due to continued weak demand, strong competition and oversupplies which will affect sale prices and margins.
    Our turnaround strategy will be driven by the renegotiation of our entire portfolio of long-term supply contracts in order to align our cost position to prevailing market conditions. The consolidation of profitability and cash generation will be helped by the streamlining of operations and optimization of logistic costs, focusing on the development and growth in value added segments.
  Our priority in the Refining & Marketing segment is to recover profitability and positive cash generation in a short time frame against the backdrop of weak industry fundamentals and an unfavorable trading environment. We plan to complete our target of up to 50% refining capacity reduction also through process reconversion in Italy and to implement a number of efficiency and cost reduction initiatives, energy saving and optimization of plant operations, in order to drive margin expansions. In the marketing business in Italy we plan to enhance profitability by closing down marginal outlets and continuing upgrading our modern and most efficient service stations, also improving service quality and client retention and non-oil profit contribution taking into account a weak outlook for fuel consumption. Outside Italy, Eni plans to grow selectively in target European markets and divest marginal assets.

29


Table of Contents
  Our Engineering & Construction segment is expected to strength profitability and reinforce the financial structure. Management plans to focus on working capital optimization and selective capital expenditure. In the next four-year plan we will leverage on our competitive advantages in ultra-deep projects, in the lying of large-diameter pipelines in harsh environments and complex onshore projects. We intend to complete legacy projects with low profitability with the aim to focus on certain projects leveraging on our technologically-advanced assets and our skills in engineering and project management, as well as by strengthening the EPC model.
  In the Chemical segment, management intends to recover profitability by progressively reducing the exposure to loss-making commodity business lines. This will be achieved by restructuring production capacity by plant closure, divestment or reconversion, and by refocusing the chemical business on more profitable market segments. Our return to profitability will be underpinned by a progressive growth in the production of chemicals based on green technologies and in niche productions such as elastomers where we have the competitive advantage granted by proprietary technologies. We also plan to expand our elastomers and other niche productions internationally to seek to capture opportunities for growth and returns in the fast-growing Asian markets leveraging our technologies and know-how in those fields.

In executing this strategy, management intends to pursue integration opportunities among segments and within each segment to strongly focus on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all segments.

For a description of risks and uncertainties associated with the Company’s outlook, and the capital expenditure program see "Item 5 – Operating and financial review and prospects – Management’s expectations of operations".

 

Significant business and portfolio developments

The significant business and portfolio developments that occurred in 2014 and to date in 2015 were the following:
  In April 2015, Versalis and the South Korean petrochemical company LOTTE Chemical extended their cooperation in the elastomers business under a technology license agreement regarding, in particular, the Styrene-Isoprene-Styrene and Styrene-Butadiene-Styrene (SIS/SBS) product lines to target the specialty hot-melt adhesives market and additional market segments such as technical and sports articles, bitumen and plastics.
  In March 2015, Eni signed, within the framework of Egyptian Economic Development Conference (EEDC), a framework agreement for the development of Egypt’s oil and gas resources by investing approximately $5 billion. The investments to be implemented in the next 4 years are directed to the development of significant oil and gas reserves.
  In March 2015, Eni made a significant discovery of gas and condensates offshore Libya, in the Bahr Essalam South exploration prospect. The proximity to the Bahr Essalam infrastructures will allow a quick development of this new discovery.
  On January 15, 2014, Eni sold to certain Gazprom subsidiaries its 60% interest in Artic Russia which is the parent company with a 49% stake of Severenergia, which holds four licenses for the exploration and production of hydrocarbons in the Region of Yamal Nenets (Siberia), including in particular the on stream field of Samburgskoye, Eni’s first development in the Russian upstream. The cash consideration for the disposal amounted to euro 2.16 billion ($2,940 million).
  In December 2014, Eni divested to Gazprom its 20% stake in South Stream Transport BV engaged in the economic feasibility, procurement and construction of the offshore section of the South Stream pipeline. Pursuant to the shareholders’ agreement, Eni exercised a put option of its stake whereby the Company will recover the capital invested to date in the project, determined in accordance with existing agreements.
  At the end of December 2014, Versalis signed an agreement to divest the Sarroch plant to the refining company Saras, which owns a refinery close to Eni’s petrochemical site. The agreement includes the disposal of the Versalis plants connected with the production cycle of the refinery, in particular the reforming unit, the propylene splitter unit and other related services, including the logistics system. Versalis will continue to operate on the site with the planned HSE activities and environmental remediation activities, not included in the transaction.
  The exploration campaign carried out in 2014 achieved success with: (i) the Ochigufu well, in the deep waters of Block 15/06 (Eni operator with a 35% interest). This discovery is located near the West Hub oil project, which started up at the end of 2014. In January 2015, Eni obtained from the Angolan authorities a three-year extension of the exploration period of the above mentioned block; (ii) Congo: in the conventional waters of Block Marine XII, the Minsala well marked the third oil discovery in the last two, with characteristics similar to the previous discoveries of Litchendjili and Nené, the latter started up early production in quick time; (iii) Ecuador: the Oglan well in Block 10 (Eni operator with a 100% interest), located near the processing facilities of the operated Villano oilfield; (iv) Indonesia: the Merakes gas discovery in East Sepinggan offshore Block (Eni operator with a 85% interest). This discovery is located in proximity of the operated field of Jangkrik, which is currently under development and will supply additional gas volumes to the Bontang

30


Table of Contents
    LNG plant; and (v) Mozambique: the appraisal gas wells Agulha 2 at Mamba and Coral 4 DIR confirmed the extension of their respective discoveries in Area 4 (Eni operator with a 50% interest).
  In November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders (including trade unions and local communities) a plan to restore the profitability of the Gela refinery. Key to the agreement is the reconversion of the Gela site into a bio-refinery. This will follow the model adopted in the Venice green refinery scheme, where green diesel will be produced from raw vegetable materials by using the proprietary EcofiningTM technology. The agreement also defines terms for building a modern logistic pole and new initiatives in the upstream sector in Sicily. Eni will also perform environmental remediation and cleanup activities and institute a competence center for safety. The investment plan for such initiatives amounts to euro 2.2 billion, mainly relating to upstream projects in the Sicily Region.
  In August 2014, Eni divested its stake in EnBW Eni Verwaltungsgesellschaft (EEV), a joint venture which controls the companies Gasversorgung Süddeutschland (GVS) and Terranets BW, to its current partner EnBW (Energie Baden-Württemberg). In 2013, Eni’s share of the sales volumes made by the joint venture amounted to 2.62 BCM.
  In June 2014, the start-up of the bio-refinery of Porto Marghera was achieved, with green diesel capacity of approximately 300 ktonnes/y, from refined vegetable oil, utilizing the proprietary EcofiningTM technology. The production will fulfill half of Eni’s annual requirement of green diesel, thus ensuring new perspectives for the industrial site of Venice and allowing economic and environmental benefits.
  In June 2014, the green chemical project of Matrìca, a 50/50 joint venture between Eni’s subsidiary Versalis and Novamont, started operations marking the full conversion of the Porto Torres site. Matrìca’s plant is currently leveraging on innovative technology to transform vegetable oils into monomers and intermediates that are feedstock for the production of complex bio-products destined for a number of industries such as the tyre industry, bio-lubricants and plastic production. The overall production capacity of approximately 70 ktonnes per year will come gradually online during 2015. Cracking production line was closed definitively.
  In the first half of 2014, Eni completed the divestment of Galp through the sale of approximately 8% of the share capital of the investee for a cash consideration of euro 824 million. Following the sale, Eni holds approximately 8% of Galp’s share capital, entirely underlying the approximately euro 1,028 million exchangeable bond issued on November 30, 2012 and due on November 30, 2015.
  In May 2014, Eni signed a preliminary agreement for the divestment of Eni’s marketing activities of fuels located in Czech Republic, Slovakia and Romania to the Hungarian Company MOL. The agreement also comprises the refinery capacity to supply the marketing network through a 32.445% interest in the joint refining asset Ceská Rafinérská as (CRC). The latter will be ultimately purchased by another partner in the venture, Unipetrol, which exercised the relevant preemption rights according to the conditions agreed by Eni and MOL. All these agreements are subject to the approval of the relevant European Antitrust Authorities.
     
In addition, Eni closed the following transactions:
  In March 2015, following its participation in the competitive International Bid Round launched by the Republic of the Union of Myanmar, Eni signed two Production Sharing Contracts (PSC) for offshore blocks MD-02 and MD-04. These contracts foresee a study period of two years, followed by a 3-phases exploration period lasting six years.
  In January 2015, Eni and the relevant authorities of Ghana sanctioned the OCTP integrated oil and gas project (Eni 47.22%, operator). First oil is expected in 2017, first gas in 2018 and production is expected to peak at 80,000 BOE/d.
  In June 2014, Eni signed a strategic agreement with the Kazakh national company KazMunaiGas (KMG) for the exploitation of exploration and production rights in the Isatay area, located in the North Caspian Sea, through a joint operating company.
  In October 2014, a Memorandum of Understanding and Cooperation was signed with the National Company Petroleos Mexicanos (Pemex) establishing the basis for future cooperation in the upstream and other business segments and areas.
  In November 2014, Eni and the State oil company Turkmenneft agreed to extend up to 2032 the production sharing agreement regulating exploration and production activities at the onshore Nebit Dag Block. The agreements also establish the transfer of a 10% stake out of the contractor share to Turkmenneft.
  In July 2014, a cooperation agreement was signed with the relevant authorities to extend existing oil permits and to develop new initiatives in the Country’s coastal basin, which extends from onshore Mayombe to frontage deep waters. At the end of December 2014, Eni started production at the recent Nené discovery in Block Marine XII (Eni’s interest 65%, operator) just eight months after obtaining the production permit. The early production phase is yielding 7,500 BOE/d and the fast-track development of the field has leveraged on the synergies with the front-end loading and the infrastructures of the fields located in the area. The full-field development will take place in several stages and will include the installation of production platforms and the drilling of over 30 wells, with a plateau of over 120,000 BOE/d.

In 2014, capital expenditures amounted to euro 12,240 million, of which 92% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 9,021 million) deployed mainly in Norway, Angola, Congo, the United States, Italy, Nigeria, Egypt, Indonesia and Kazakhstan and exploratory projects (euro 1,398 million) carried out primarily in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon; (ii) upgrading of the fleet used in the Engineering

31


Table of Contents

& Construction segment (euro 694 million); (iii) refining, supply and logistics in Italy and outside Italy (euro 362 million) with projects designed to improve the conversion rate and flexibility of refineries, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 175 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 98 million).

In 2013, capital expenditures of continuing operations amounted to euro 12,800 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 8,580 million) deployed mainly in Norway, the United States, Angola, Congo, Italy, Nigeria, Kazakhstan, Egypt and the United Kingdom, and exploration projects (euro 1,669 million) carried out mainly in Mozambique, Norway, Congo, Togo, Nigeria, the United States and Angola; (ii) upgrading of the fleet used in the Engineering & Construction segment (euro 902 million); (iii) refining, supply and logistics in Italy and outside Italy (euro 462 million) with projects designed to improve the conversion rate and flexibility of refineries, in particular at the Sannazzaro refinery, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 210 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 119 million). There were no significant acquisitions in the year.

In 2012, capital expenditures of continuing operations amounted to euro 12,805 million, of which 89% related to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 8,304 million) deployed mainly in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria, and exploration projects (euro 1,850 million) carried out mainly in Mozambique, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia; (ii) upgrading of the fleet used in the Engineering & Construction segment (euro 1,011 million); (iii) refining, supply and logistics with projects designed to improve the conversion rate and flexibility of refineries (euro 639 million), in particular at the Sannazzaro refinery, as well as upgrading and rebranding of the refined product retail network (euro 259 million); and (iv) initiatives to improve flexibility of the combined-cycle power plants (euro 123 million). There were no significant acquisitions in the year.

 

 

BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 40 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2014, Eni average daily production amounted to 1,517 KBOE/d on an available-for-sale basis. As of December 31, 2014, Eni’s total proved reserves amounted to 6,602 mmBOE; proved reserves of subsidiaries totaled 5,772 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 830 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve a production growth rate of 3.5% on average in the next 2015-2018 four-year period, based on our long-term Brent price assumptions of 90 $/BBL and certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under "Item 5 – Management’s expectations of operations".

Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations, including North Africa, Sub-Saharan Africa, Barents Sea, Kazakhstan, Venezuela and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. We plan to start 16 new large fields over the next four years which will contribute more with than 650 KBOE/d of new production by 2018; about 90% of these new projects have already been sanctioned and 84% operated.

Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery.

Management plans to invest some euro 36 billion to develop reserves over the next four years, with a decrease of 12% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Congo, Angola and Egypt, while we plan to re-schedule spending in some large projects. This re-scheduling will account for half of the overall reduction, while the remaining will be determined by contracts renegotiations.

32


Table of Contents

Exploration projects will attract some euro 5 billion with a reduction of 35% net of exchange rate effects in 2015 and 25% over the plan period. Exploration expenditure will be focused on proven plays and near-field exploration, where we plan to drill 70% of our scheduled wells. The most important amounts of exploration expenses will be incurred in Norway, Nigeria, the United States and Italy.

Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control on project time schedules and costs and reducing the time span which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities also redeploying to other areas key competences which will be freed with the start-up of certain strategic projects and increase direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on these initiatives we believe that almost all of our project which we are currently developing over the next four-year plan will be completed on time and on cost schedule.

Finally we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; (iii) applying our technologies which we believe can reduce drilling and completion costs; and (iv) renegotiating contracts for oilfield services and other items to reap the benefits of the deflationary trend in the industry.

We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies.

For the year 2015, management plans to spend over euro 10 billion in reserves development and exploration projects.

 

Disclosure of reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.

Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (cost oil) and recognize the profit oil set contractually (profit oil). A similar scheme applies to buy-back and service contracts.

33


Table of Contents

Reserves governance

Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is entrusted with the tasks of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.

Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the U.S. SEC rules1. D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditures, operating expenses and costs related to asset retirement obligations; (ii) the Petroleum Engineering Department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; and (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserves data.

The head of the Reserves Department attended the "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. She has more than 25 years of experience in the oil and gas industry and more than 15 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

 

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation2 of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third-party audit report3. In the preparation of their reports, independent evaluators rely upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.

In order to calculate the economic value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third-party evaluators. In 2014, Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of approximately 27% of Eni’s total proved reserves at December 31, 20144, confirming, as in previous years, the reasonableness of Eni internal evaluation5.

In the 2012-2014 three-year period, 94% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2014, the main Eni properties not subjected to independent evaluation in the last three years were M’Boundi (Congo) and Junin 5 (Venezuela).


(1) i See "Item 19 – Exhibits" in the Annual Report on Form 20-F 2009.
(2) i From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
(3)  i See "Item 19 – Exhibits".
(4)  i Includes Eni’s share of proved reserves of equity-accounted entities.
(5)  i See "Item 19 – Exhibits".

34


Table of Contents

Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2014, 2013 and 2012. Net proved reserves are set out in more detail under the heading "Supplemental oil and gas information" on page F-138.

HYDROCARBONS
(mmBOE)
 

Italy

 

Rest
of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total reserves

   
 
 
 
 
 
 
 
 
Consolidated subsidiaries                                    
Year ended Dec. 31, 2012   524   591   1,915   1,048   1,041   184   236   128   5,667
developed   406   349   1,080   716   458   108   170   107   3,394
undeveloped   118   242   835   332   583   76   66   21   2,273
Year ended Dec. 31, 2013   499   557   1,783   1,155   1,035   263   240   176   5,708
developed   408   343   1,003   701   566   90   153   123   3,387
undeveloped   91   214   780   454   469   173   87   53   2,321
Year ended Dec. 31, 2014   503   544   1,740   1,239   1,069   285   232   160   5,772
developed   401   335   904   702   589   112   188   135   3,366
undeveloped   102   209   836   537   480   173   44   25   2,406
Equity-accounted entities                                    
Year ended Dec. 31, 2012           20   81       668   730       1,499
developed           20           82   20       122
undeveloped               81       586   710       1,377
Year ended Dec. 31, 2013           19   75       7   726       827
developed           19           3   18       40
undeveloped               75       4   708       787
Year ended Dec. 31, 2014           16   81       5   728       830
developed           15   23       3   26       67
undeveloped           1   58       2   702       763
Consolidated subsidiaries
and equity-accounted entities
                                   
Year ended Dec. 31, 2012   524   591   1,935   1,129   1,041   852   966   128   7,166
developed   406   349   1,100   716   458   190   190   107   3,516
undeveloped   118   242   835   413   583   662   776   21   3,650
Year ended Dec. 31, 2013   499   557   1,802   1,230   1,035   270   966   176   6,535
developed   408   343   1,022   701   566   93   171   123   3,427
undeveloped   91   214   780   529   469   177   795   53   3,108
Year ended Dec. 31, 2014   503   544   1,756   1,320   1,069   290   960   160   6,602
developed   401   335   919   725   589   115   214   135   3,433
undeveloped   102   209   837   595   480   175   746   25   3,169

35


Table of Contents
LIQUIDS
(mmBBL)
 

Italy

 

Rest
of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total reserves

   
 
 
 
 
 
 
 
 
Consolidated subsidiaries                                    
Year ended Dec. 31, 2012   227   351   904   672   670   82   154   24   3,084
developed   165   180   584   456   203   41   109   24   1,762
undeveloped   62   171   320   216   467   41   45       1,322
Year ended Dec. 31, 2013   220   330   830   723   679   128   147   22   3,079
developed   177   179   561   465   295   38   96   20   1,831
undeveloped   43   151   269   258   384   90   51   2   1,248
Year ended Dec. 31, 2014   243   331   776   739   697   131   147   13   3,077
developed   184   174   521   470   306   64   116   12   1,847
undeveloped   59   157   255   269   391   67   31   1   1,230
Equity-accounted entities                                    
Year ended Dec. 31, 2012           17   16       114   119       266
developed           17           8   19       44
undeveloped               16       106   100       222
Year ended Dec. 31, 2013           16   15       1   116       148
developed           16               19       35
undeveloped               15       1   97       113
Year ended Dec. 31, 2014           14   17       1   117       149
developed           13   7           26       46
undeveloped           1   10       1   91       103
Consolidated subsidiaries
and equity-accounted entities
                                   
Year ended Dec. 31, 2012   227   351   921   688   670   196   273   24   3,350
developed   165   180   601   456   203   49   128   24   1,806
undeveloped   62   171   320   232   467   147   145       1,544
Year ended Dec. 31, 2013   220   330   846   738   679   129   263   22   3,227
developed   177   179   577   465   295   38   115   20   1,866
undeveloped   43   151   269   273   384   91   148   2   1,361
Year ended Dec. 31, 2014   243   331   790   756   697   132   264   13   3,226
developed   184   174   534   477   306   64   142   12   1,893
undeveloped   59   157   256   279   391   68   122   1   1,333

36


Table of Contents
NATURAL GAS
(BCF)
 

Italy

 

Rest
of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total reserves

   
 
 
 
 
 
 
 
 
Consolidated subsidiaries                                    
Year ended Dec. 31, 2012   1,633   1,317   5,558   2,061   2,038   562   449   572   14,190
developed   1,325   925   2,720   1,429   1,401   372   334   459   8,965
undeveloped   308   392   2,838   632   637   190   115   113   5,225
Year ended Dec. 31, 2013   1,532   1,247   5,231   2,374   1,957   744   509   848   14,442
developed   1,266   904   2,432   1,295   1,488   286   310   561   8,542
undeveloped   266   343   2,799   1,079   469   458   199   287   5,900
Year ended Dec. 31, 2014   1,432   1,171   5,291   2,744   2,049   846   468   807   14,808
developed   1,192   887   2,110   1,271   1,553   261   393   675   8,342
undeveloped   240   284   3,181   1,473   496   585   75   132   6,466
Equity-accounted entities                                    
Year ended Dec. 31, 2012           16   353       3,043   3,355       6,767
developed           16           402   6       424
undeveloped               353       2,641   3,349       6,343
Year ended Dec. 31, 2013           15   330       28   3,353       3,726
developed           15           14   5       34
undeveloped               330       14   3,348       3,692
Year ended Dec. 31, 2014           15   351       18   3,353       3,737
developed           15   89       10   6       120
undeveloped               262       8   3,347       3,617
Consolidated subsidiaries
and equity-accounted entities
                                   
Year ended Dec. 31, 2012   1,633   1,317   5,574   2,414   2,038   3,605   3,804   572   20,957
developed   1,325   925   2,736   1,429   1,401   774   340   459   9,389
undeveloped   308   392   2,838   985   637   2,831   3,464   113   11,568
Year ended Dec. 31, 2013   1,532   1,247   5,246   2,704   1,957   772   3,862   848   18,168
developed   1,266   904   2,447   1,295   1,488   300   315   561   8,576
undeveloped   266   343   2,799   1,409   469   472   3,547   287   9,592
Year ended Dec. 31, 2014   1,432   1,171   5,306   3,095   2,049   864   3,821   807   18,545
developed   1,192   887   2,125   1,360   1,553   271   399   675   8,462
undeveloped   240   284   3,181   1,735   496   593   3,422   132   10,083

Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 282 mmBOE as of December 31, 2014 (536 and 648 mmBOE as of December 31, 2013 and 2012, respectively). Said volumes are not included in reserves volumes shown in the table herein.

 

Subsidiaries

 

Equity-accounted entities

 
 
 

2012

 

2013

 

2014

 

2012

 

2013

 

2014

 
 
 
 
 
 
  (mmBOE)
Additions to proved reserves   549     621     643     404           11  
Purchases of minerals-in-place         4     4                    
Sales of minerals-in-place   (212 )   (13 )   (8 )   (38 )   (652 )      
Production for the year (a)   (610 )   (571 )   (575 )   (13 )   (20 )   (8 )

(a)    The difference over production sold of 549.5 mmBOE (598.7 mmBOE in 2012 and 555.3 mmBOE in 2013) reflected natural gas volumes of 29.4 mmBOE consumed in operations (25.5 mmBOE in 2012 and 30 mmBOE in 2013), changes in inventories and other factors.
   
 

Subsidiaries and
equity-accounted entities

 
 

2012

 

2013

 

2014

 
 
 
  (%)
Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources   113   (7)   112

Eni’s proved reserves as of December 31, 2014 totaled 6,602 mmBOE (liquids 3,226 mmBBL; natural gas 18,545 BCF). Eni’s proved reserves reported an increase of 67 mmBOE, or 1%, from December 31, 2013. All sources

37


Table of Contents

additions to proved reserves booked in 2014 were 654 mmBOE of which 643 mmBOE came from Eni’s subsidiaries and 11 mmBOE from Eni’s share of equity-accounted entities.

Price effects were negligible, leading to an upward revision of 33 mmBOE, due to a lowered Brent price used in the reserve estimation process down to 101 $/BBL in 2014 compared to 108 $/BBL in 2013. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in “Item 3 – Risk factors – Risks associated with the exploration and production of oil and natural gas”.

The methods (or technologies) used in the Eni’s proved reserves assessment in 2014 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modeling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However, for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates.

The all sources reserves replacement ratio achieved by Eni’s subsidiaries and equity-accounted entities was 112% in 2014 (negative in 2013 and 113% in 2012). The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities - Oil & Gas (Topic 932) (see "Item 18 – Supplemental oil and gas information – of the Notes on Consolidated Financial Statements"). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserves replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, as well as changes in oil and gas prices, political risks, geological, reservoir performance and environmental risks. See "Item 3 – Risks associated with the exploration and production of oil and natural gas and Uncertainties in estimates of oil and natural gas reserves".

The average reserves life index of Eni’s proved reserves was 11.3 years as of December 31, 2014 which included reserves of both subsidiaries and equity-accounted entities.

 

Eni’s subsidiaries

Eni’s subsidiaries added 643 mmBOE of proved oil and gas reserves in 2014. This comprised 302 mmBBL of liquids and 1,872 BCF of natural gas. Additions to proved reserves derived from: (i) revisions of previous estimates were 513 mmBOE mainly reported in Libya, Italy, Kazakhstan and Congo due to contractual revisions, continuous development activities and field performances; (ii) extensions and discoveries were 124 mmBOE, with major increases booked in Ghana, Indonesia, the United States and Congo, following new project sanctions and proved area extensions; (iii) improved recovery were 6 mmBOE mainly reported in Algeria and Kazakhstan; (iv) sales of mineral-in-place related to the divestment of assets in Nigeria (7 mmBOE) and the United Kingdom (1 mmBOE); and (v) purchase of mineral-in-place referred to interests in assets located in the United Kingdom (4 mmBOE).

 

Eni’s share of equity-accounted entities

Additions in Eni’s share of equity-accounted entities’ proved oil and gas reserves amounted to 11 mmBOE in 2014 and derived from revisions of previous estimates reported mainly in Angola and Venezuela.

 

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2014 totaled 3,169 mmBOE. At year end, proved undeveloped reserves of liquids amounted to 1,333 mmBBL, mainly concentrated in Africa and Kazakhstan. Proved undeveloped reserves of natural gas amounted to 10,083 BCF, mainly located in Africa and Venezuela. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,230 mmBBL of liquids and 6,466 BCF of natural gas.

In 2014, total proved undeveloped reserves increased by 61 mmBOE mainly due to: (i) discoveries and extensions (up by 109 mmBOE) in particular in Ghana and Indonesia associated to new project sanctions and proved area

38


Table of Contents

extensions; (ii) revisions of previous estimates (up by 173 mmBOE) mainly reported in Libya, Nigeria, Angola, Italy and Norway due to contractual revisions, development activities and field performances; (iii) divestments (down by 4 mmBOE) in Nigeria; and (iv) reclassification to proved developed reserves (down by 217 mmBOE).

During 2014, Eni converted 217 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress of development activities and production start-ups. The main reclassifications to proved developed reserves related to the following fields/projects: Hadrian South and Nikaitchuq (United States), A-LNG and Sangos (Angola) and Karachaganak (Kazakhstan).

In 2014, capital expenditure amounted to approximately euro 2.3 billion and was made to progress the development of proved undeveloped reserves.

Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1 BBOE of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (approximately 0.5 BBOE), which will be progressively reclassified to proved developed as a result of hooking-up new producing wells which are currently being drilled and plant capacity expansion as part of the completion of the sanctioned Phase 1 of the global development plan of the Kashagan field (the so-called Experimental Program); (ii) certain Libyan gas fields (0.4 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years; and (iii) the Goliat project in Norway and other minor projects where development activities are progressing. See also our discussion under the "Risk factors" section about risks associated with oil and gas development projects on page 6.

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

 

Delivery commitments

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

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 331 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria and Norway.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 77% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2014.

 

Oil and gas production, production prices and production costs

The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying 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 2014, oil and natural gas production available for sale averaged 1,517 KBOE/d (1,537 KBOE/d in 2013) declined by 1.3% from 2013. On a homogeneous basis i.e. excluding the impact of the divestment of Eni’s interest in Siberian assets (29 KBOE/d, or 11 mmBOE in 2013), hydrocarbon production for the full year 2014 was up by 0.6%.

39


Table of Contents

The main production increases were reported in the United Kingdom, Algeria, the United States and Angola. These additions more than offset mature fields’ declines. New fields’ start-ups and production ramp-ups at fields started up in 2013 contributed 126 KBOE/d of production.

Liquids production (828 KBBL/d) was barely unchanged from 2013 (down by 0.6%) with major increases reported in: (i) the United Kingdom due to the ramp-up of the Jasmine field (Eni’s interest 33%); (ii) Algeria with the ramp-up of the El Merk field (Eni’s interest 12.25%); (iii) the United States due to ramp-ups following development activities and optimization of operated projects of Nikaitchuq (Eni 100%), Pegasus (Eni 58%) and Appaloosa (Eni 100%); and (iv) Angola with the start-up of the West Hub project (Eni operator with a 35% interest). These increases were offset by mature field decline and other factors, including unplanned facility downtime in the United Kingdom, Norway and the United States.

Natural gas production (3,782 mmCF/d) reported a slight increase from 2013, excluding the impact of the divestment of Eni’s interest in Siberian assets (up by 1.3%). Mature fields’ declines were more than offset by the contribution of new fields’ start-ups and ramp-ups.

Oil and gas production sold amounted to 549.5 mmBOE. The 4.3 mmBOE difference over production on an available-for-sale basis (553.8 mmBOE) reflected mainly changes in inventories and other factors. Approximately 62% of liquids production sold (299.8 mmBBL) was destined to Eni’s Refining & Marketing segment (of which 23% was processed in Eni’s refineries). About 27% of natural gas production sold (1,371 BCF) was destined to Eni’s Gas & Power segment.

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

2012 Production available for sale (a)  

Italy

 

Rest of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total

   
 
 
 
 
 
 
 
 
Hydrocarbons production                                        
Eni consolidated subsidiaries   (KBOE/d)   184   171   556   326   98   106   122   35   1,598
    (mmBOE)   67   63   203   119   36   39   45   13   585
Eni share of equity-accounted entities   (KBOE/d)           5   2       15   11       33
    (mmBOE)           2   1       5   4       12
Liquids production                                        
Eni consolidated subsidiaries   (KBBL/d)   63   95   267   245   61   41   72   18   862
    (mmBBL)   23   35   98   90   22   15   26   7   316
Eni share of equity-accounted entities   (KBBL/d)           4   2       3   11       20
    (mmBBL)           1   1       1   4       7
Natural gas production                                        
Eni consolidated subsidiaries   (mmCF/d)   667   421   1,589   444   202   355   273   96   4,047
    (BCF)   244   154   582   162   74   130   100   35   1,481
Eni share of equity-accounted entities   (mmCF/d)           3           68           71
    (BCF)           1           25           26

(a)    It excludes production volumes of natural gas consumed in operations. Said volumes were 383 mmCF/d, or 25.5 mmBOE.

40


Table of Contents
2013 Production available for sale (a)  

Italy

 

Rest of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total

   
 
 
 
 
 
 
 
 
Hydrocarbons production                                        
Eni consolidated subsidiaries   (KBOE/d)   179   149   523   305   96   101   104   29   1,486
    (mmBOE)   65   54   191   111   35   36   38   11   541
Eni share of equity-accounted entities   (KBOE/d)           5   2       34   10       51
    (mmBOE)           2   1       13   4       20
Liquids production                                        
Eni consolidated subsidiaries   (KBBL/d)   71   77   248   242   61   43   61   10   813
    (mmBBL)   26   28   91   88   22   16   22   4   297
Eni share of equity-accounted entities   (KBBL/d)           4           6   10       20
    (mmBBL)           1           2   4       7
Natural gas production                                        
Eni consolidated subsidiaries   (mmCF/d)   593   395   1,510   349   195   322   234   105   3,703
    (BCF)   217   144   551   127   71   118   85   38   1,351
Eni share of equity-accounted entities   (mmCF/d)           4   7       154           165
    (BCF)           2   3       56           61

(a)    It excludes production volumes of natural gas consumed in operations. Said volumes were 451 mmCF/d, or 30 mmBOE.

 

2014 Production available for sale (a)  

Italy

 

Rest of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total

   
 
 
 
 
 
 
 
 
Hydrocarbons production                                        
Eni consolidated subsidiaries   (KBOE/d)   171   184   528   305   85   87   112   25   1,497
    (mmBOE)   63   67   193   111   31   31   41   9   546
Eni share of equity-accounted entities   (KBOE/d)           4   2       4   10       20
    (mmBOE)           1   1       2   4       8
Liquids production                                        
Eni consolidated subsidiaries   (KBBL/d)   73   93   249   230   52   36   74   6   813
    (mmBBL)   27   34   91   84   19   13   27   2   297
Eni share of equity-accounted entities   (KBBL/d)           4           1   10       15
    (mmBBL)           1               4       5
Natural gas production                                        
Eni consolidated subsidiaries   (mmCF/d)   541   498   1,533   411   181   279   205   106   3,754
    (BCF)   198   182   559   150   66   102   75   39   1,371
Eni share of equity-accounted entities   (mmCF/d)           3   7       18           28
    (BCF)           1   3       6           10

(a)    It excludes production volumes of natural gas consumed in operations. Said volumes were 442 mmCF/d, or 29.4 mmBOE.

Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 78 KBOE/d, 67 KBOE/d and 78 KBOE/d in 2014, 2013 and 2012, respectively.

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

41


Table of Contents

AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTION

($)  

Italy

 

Rest of Europe

 

North Africa

 

Sub-Saharan Africa

 

Kazakhstan

 

Rest of Asia

 

Americas

 

Australia and Oceania

 

Total

   
 
 
 
 
 
 
 
 
2012                                    
Consolidated subsidiaries                                    
Oil and condensates, per BBL   100.52   100.67   103.63   108.34   102.25   103.44   85.94   102.06   103.06
Natural gas, per KCF   10.68   10.13   8.13   2.16   0.67   5.94   2.90   7.73   7.14
Average production cost, per BOE   11.60   13.43   6.28   18.65   6.73   8.37   10.46   13.23   10.82
Equity-accounted entities                                    
Oil and condensates, per BBL       93.11   17.93   112.28       40.36   93.45       77.94
Natural gas, per KCF       11.64   4.91           6.17           6.16
Average production cost, per BOE       30.10   10.35   10.60       4.37   46.01       20.21
2013                                    
Consolidated subsidiaries                                    
Oil and condensates, per BBL   98.50   98.97   100.42   105.13   99.37   99.69   85.27   98.72   100.20
Natural gas, per KCF   11.65   10.62   7.96   2.16   0.64   5.83   3.37   7.80   7.41
Average production cost, per BOE   14.58   17.49   6.72   19.60   7.23   9.32   12.08   18.17   12.19
Equity-accounted entities                                    
Oil and condensates, per BBL           17.96           33.87   93.32       64.92
Natural gas, per KCF           6.29           3.49           4.00
Average production cost, per BOE           11.87           3.48   50.57       16.68
2014                                    
Consolidated subsidiaries                                    
Oil and condensates, per BBL   87.80   88.80   88.99   93.45   91.86   77.99   79.13   91.61   88.90
Natural gas, per KCF   8.74   8.49   8.08   2.12   0.62   6.18   3.96   7.46   6.83
Average production cost, per BOE   15.19   13.61   6.79   18.88   8.94   10.70   11.75   20.14   12.00
Equity-accounted entities                                    
Oil and condensates, per BBL           17.94           65.90   81.48       70.56
Natural gas, per KCF           6.08           15.64           14.13
Average production cost, per BOE           12.50           9.79   42.27       26.18


Development activities

In 2014, a total of 440 development wells were drilled (191 of which represented Eni’s share) as compared to 463 development wells drilled in 2013 (187.2 of which represented Eni’s share) and 351 development wells drilled in 2012 (163.6 of which represented Eni’s share). The drilling of 142 wells (46.5 of which represented Eni’s share) is currently underway.

The table below summarizes the number of the Company’s net interests in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2014. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

DEVELOPMENT WELL ACTIVITY

   

Net wells completed

 

Wells in progress at Dec. 31,

   
 
   

2012

 

2013

 

2014

 

2014

   
 
 
 
(units)  

Productive

 

Dry

 

Productive

 

Dry

 

Productive

 

Dry

 

Gross

 

Net

   
 
 
 
 
 
 
 
Italy   18.0   1.0   7.4   1.0   12.5       5.0   4.6
Rest of Europe   2.9   0.6   6.3       9.8   1.0   36.0   7.9
North Africa   46.0   1.6   61.6   3.3   54.5   1.0   15.0   7.4
Sub-Saharan Africa   27.4   0.3   26.3   1.2   31.6       23.0   7.5
Kazakhstan   1.4       0.3       1.5       22.0   3.9
Rest of Asia   41.2   0.1   61.7   4.3   54.2   1.6   19.0   8.2
Americas   23.1       13.8       22.1   0.7   20.0   6.5
Australia and Oceania                   0.1   0.4   2.0   0.5
Total including equity-accounted entities   160.0   3.6   177.4   9.8   186.3   4.7   142.0   46.5


Exploration activities

In 2014, a total of 44 new exploratory wells were drilled (25.8 of which represented Eni’s share), as compared to 53 exploratory wells drilled in 2013 (27.8 of which represented Eni’s share) and 60 exploratory wells drilled in 2012 (34.1 of which represented Eni’s share).

42


Table of Contents

The overall commercial success rate was 31.3% (38.0% net to Eni) as compared to 36.9% (38.5% net to Eni) and 40% (40.8% net to Eni) in 2013 and 2012, respectively.

The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2014. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

EXPLORATORY WELL ACTIVITY

   

Net wells completed

 

Wells in progress
at Dec. 31,
(1)

   
 
   

2012

 

2013

 

2014

 

2014

   
 
 
 
(units)  

Productive

 

Dry

 

Productive

 

Dry

 

Productive

 

Dry

 

Gross

 

Net

   
 
 
 
 
 
 
 
Italy   1.0                   0.6   4.0   2.8
Rest of Europe   1.0   1.0       3.4       4.3   12.0   3.3
North Africa   6.3   11.3   4.9   5.4   3.5   4.3   13.0   10.3
Sub-Saharan Africa   4.5   5.1   3.2   6.6   7.3   7.3   49.0   16.9
Kazakhstan       0.8       0.4           6.0   1.1
Rest of Asia   0.5   0.6   4.3   2.7   1.3   4.3   12.0   5.0
Americas       0.1   0.2   1.2   2.0   1.4   4.0   2.5
Australia and Oceania       0.4       0.5       0.9   1.0   0.3
Total including equity-accounted entities   13.3   19.3   12.6   20.2   14.1   23.1   101.0   42.2

(1)   Includes temporary suspended wells pending further evaluation.


Oil and gas properties, operations and acreage

In 2014, Eni performed its operations in 40 countries located in five continents. As of December 31, 2014, Eni’s mineral right portfolio consisted of 938 exclusive or shared rights of exploration and development activities for a total acreage of 334,739 square kilometers net to Eni of which developed acreage of 40,771 square kilometers and undeveloped acreage of 293,968 square kilometers net to Eni. In 2014, changes in total net acreage mainly derived from: (i) new leases mainly in South Africa, Indonesia, Vietnam, Myanmar, Portugal, China, Egypt, Greenland, Australia and Kenya for a total acreage of approximately 76,000 square kilometers; (ii) interest increase in Indonesia and Ireland for a total acreage of approximately 2,100 square kilometers; (iii) the total relinquishment of licenses mainly in Togo, Pakistan, Australia, Poland, Democratic Republic of Congo, covering an acreage of approximately 12,000 square kilometers; and (iv) partial relinquishment or interest reduction in Indonesia, Norway, Congo and Angola for approximately 6,000 square kilometers.

In addition, Eni has been granted three prospection permits in Algeria for a net acreage of approximately 23,000 square kilometers.

The table below provides certain information about the Company’s oil and gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2014. A gross acreage is one in which Eni owns a working interest.

43


Table of Contents
 

December 31, 2013

 

December 31, 2014

 
 
   

Total net acreage (a)

 

Number
of interests

 

Gross developed acreage (a) (b)

 

Gross undeveloped acreage (a)

 

Total gross acreage (a)

 

Net
developed
acreage
(a) (b)

 

Net undeveloped acreage (a)

 

Total net acreage (a)

   
 
 
 
 
 
 
 
EUROPE   37,938   265   15,883   53,444   69,327   10,948   33,894   44,842
Italy   17,282   151   10,712   10,751   21,463   8,989   8,308   17,297
Rest of Europe   20,656   114   5,171   42,693   47,864   1,959   25,586   27,545
Croatia   987   2   1,975       1,975   987       987
Cyprus   10,018   3       12,523   12,523       10,018   10,018
Greenland   920   2       4,890   4,890       1,909   1,909
Norway   3,779   56   2,255   9,149   11,404   345   3,327   3,672
Poland   969                            
Portugal       3       9,099   9,099       6,370   6,370
United Kingdom   638   35   941   343   1,284   627   117   744
Other countries   3,345   13       6,689   6,689       3,845   3,845
AFRICA   137,096   282   66,114   263,572   329,686   20,032   139,309   159,341
North Africa   20,412   117   32,559   15,675   48,234   14,144   7,549   21,693
Algeria   1,179   42   3,222   187   3,409   1,148   31   1,179
Egypt   3,665   54   4,926   6,800   11,726   1,772   3,174   4,946
Libya   13,294   10   17,947   8,688   26,635   8,950   4,344   13,294
Tunisia   2,274   11   6,464       6,464   2,274       2,274
Sub-Saharan Africa   116,684   165   33,555   247,897   281,452   5,888   131,760   137,648
Angola   4,443   72   6,555   14,605   21,160   813   3,514   4,327
Congo   3,125   28   1,714   2,649   4,363   921   1,962   2,883
Democratic Republic of Congo   263                            
Gabon   7,615   6       7,615   7,615       7,615   7,615
Ghana   1,664   3       4,676   4,676       1,664   1,664
Kenya   38,930   7       61,363   61,363       40,426   40,426
Liberia   1,841   3       7,365   7,365       1,841   1,841
Mozambique   5,103   1       10,207   10,207       5,103   5,103
Nigeria   7,646   40   25,286   10,837   36,123   4,154   3,484   7,638
South Africa       1       82,117   82,117       32,847   32,847
Togo   6,192                            
Other countries   39,862   4       46,463   46,463       33,304   33,304
ASIA   79,314   71   17,556   199,150   216,706   5,809   103,428   109,237
Kazakhstan   869   6   2,391   2,542   4,933   442   427   869
Rest of Asia   78,445   65   15,165   196,608   211,773   5,367   103,001   108,368
China   5,149   8   77   7,056   7,133   19   7,056   7,075
India   6,167   11   206   16,546   16,752   109   6,058   6,167
Indonesia   19,209   14   3,218   31,608   34,826   1,217   25,031   26,248
Iran   820                            
Iraq   446   1   1,074       1,074   446       446
Myanmar       2       7,850   7,850       7,065   7,065
Pakistan   10,335   17   10,390   15,249   25,639   3,396   6,071   9,467
Russia   20,862   3       62,592   62,592       20,862   20,862
Timor Leste   1,230   1       1,538   1,538       1,230   1,230
Turkmenistan   200   1   200       200   180       180
Vietnam   10,783   6       39,569   39,569       26,384   26,384
Other countries   3,244   1       14,600   14,600       3,244   3,244
AMERICAS   8,286   306   5,064   11,746   16,810   3,273   4,670   7,943
Ecuador   1,985   1   1,985       1,985   1,985       1,985
Trinidad & Tobago   66   1   382       382   66       66
United States   3,843   290   1,895   4,197   6,092   954   2,546   3,500
Venezuela   1,066   6   802   2,002   2,804   268   798   1,066
Other countries   1,326   8       5,547   5,547       1,326   1,326
AUSTRALIA AND OCEANIA   13,622   14   1,140   21,679   22,819   709   12,667   13,376
Australia   13,622   14   1,140   21,679   22,819   709   12,667   13,376
Total   276,256   938   105,757   549,591   655,348   40,771   293,968   334,739

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

The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2014. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same bore hole are counted as one well. Productive wells are producing wells and

44


Table of Contents

wells capable of production. The total number of oil and natural gas productive wells is 8,777 (3,518.1 of which represent Eni’s share).

Productive oil and gas wells at Dec. 31, 2014 (a)

   

Oil wells

 

Natural gas wells

   
 
(units)  

Gross

 

Net

 

Gross

 

Net

   
 
 
 
Italy   241.0   195.1   615.0   532.4
Rest of Europe   354.0   60.6   188.0   102.9
North Africa   1,710.0   907.0   210.0   89.0
Sub-Saharan Africa   2,950.0   589.8   341.0   25.7
Kazakhstan   149.0   41.1        
Rest of Asia   475.0   363.0   956.0   364.9
Americas   201.0   112.0   366.0   127.5
Australia and Oceania   7.0   3.8   14.0   3.3
Total including equity-accounted entities   6,087.0   2,272.4   2,690.0   1,245.7

(a)    Multiple completion wells included above: approximately 2,234 (799.1 net to Eni).

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

Italy

Eni has been operating in Italy since 1926. In 2014, Eni’s oil and gas production amounted to 171 KBOE/d. Eni’s activities in Italy are deployed in the Adriatic and Ionian 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 (54 operated onshore and 64 operated offshore) and exploration licenses (12 onshore and 9 offshore).

The Adriatic and Ionian Seas represent Eni’s main production area, accounting for 46% of Eni’s domestic production in 2014. Main operated fields are Barbara, Annamaria, Angela-Angelina, Porto Garibaldi, Cervia, Bonaccia, Luna and Hera Lacinia.

Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in Southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano oil center. In 2014, the Val d’Agri concession produced 40% of Eni’s production in Italy.

45


Table of Contents

 

Eni operates 12 production concessions onshore and 3 offshore Sicily. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2014 accounted for approximately 11% of Eni’s production in Italy.

Development activities concerned: (i) the construction of a new gas treatment unit to improve the environmental performance of the treatment centre at the Val d’Agri concession; and (ii) the completion of development activities to achieve the start-up of the Fauzia and Elettra fields located in the Adriatic Sea.

In the medium term, management expects to achieve stable production level driven by continuing ramp-up at the Val d’Agri fields, new field projects and production optimization activities offsetting mature field declines.

Rest of Europe

Eni’s operations in the Rest of Europe are conducted mainly in Croatia, Norway and the United Kingdom. In 2014, the Rest of Europe accounted for 12% of Eni’s total worldwide production of oil and natural gas.

Croatia. Eni has been present in Croatia since 1996. In 2014, Eni’s production of natural gas averaged 36 mmCF/d. Activities are deployed in the Adriatic Sea near the city of Pula.

Exploration and production activities in Croatia are regulated by PSAs.

During 2014, production start-up of a new offshore Ika JZ field was achieved.

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

Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea. Eni’s production in Norway amounted to 109 KBOE/d in 2014.

46


Table of Contents

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

Eni currently holds interests in 10 production areas in the Norwegian Sea. The principal producing fields are Åsgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2014 accounted for 74% of Eni’s production in Norway.

Eni holds interests in 2 production licenses in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2014 produced approximately 24 KBOE/d net to Eni and accounted for 21% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.

Eni is currently performing exploration and development activities in the Barents Sea. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest). The license expires in 2042. Start-up is expected in the second half of 2015, with a production plateau at approximately 65 KBOE/d net to Eni in 2016.

Development activities progressed to: (i) maintain and optimize production at the Ekofisk field by installing a new platform, drilling of infilling wells, upgrading of existing facilities and water injection optimization; and (ii) optimize production activities at the Midgard (Eni’s interest 14.9%) and Mikkel fields.

In January 2015, Eni was awarded: (i) the operatorship and a 40% interest in the PL 806 license located in the Barents Sea; and (ii) a 13.12% interest in the PL 044C license located in the North Sea.

Exploration activities yielded positive results with the oil and gas Drivis discovery made at the offshore license PL 532 (Eni 30%). The discovery will be put into production with the recent oil and gas discoveries of Skrugard, Havis and Skavl by means of the development of the integrated Johan Castberg Hub.

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, the Irish Sea and Atlantic Ocean. In 2014, Eni’s net production of oil and gas averaged 68 KBOE/d. Exploration and production activities in the United Kingdom are regulated by concession contracts.

47


Table of Contents
During the year Eni was awarded the operatorship of the 22/19c (Eni’s interest 50%), 22/19e (Eni’s interest 57.14%) and 30/1b (Eni’s interest 100%) exploration blocks in the North Sea. In April 2014, Eni completed the acquisition of the Liverpool Bay assets (Eni’s interest 100%).

Eni currently holds interests in 5 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni’s interest 21.87%), J Block and Jasmine (Eni’s interest 33%), Jade (Eni’s interest 7%) and MacCulloch (Eni’s interest 40%), which in 2014 accounted for 66% of Eni’s production in the United Kingdom.

Development activities mainly concerned: (i) production start-up of the West Franklin field (Eni’s interest 21.87%) with the completion of the Phase 2 development program by means of the installation of production platform and pipeline connection to the treatment facility in the area; and (ii) production ramp-up of the Jasmine project with the completion of commissioning and start-up of 4 additional production wells.

Exploration activities yielded positive results with the Romeo North discovery, already linked to the production platform of the Jade field.

 

North Africa

Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2014, North Africa accounted for 35% of Eni’s total worldwide production of oil and natural gas.

Algeria. Eni has been present in Algeria since 1981. In 2014, Eni’s oil and gas production averaged 93 KBOE/d.

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

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

Production in blocks 403a/d and Rom North comes mainly from the HBN and Rom and satellites fields and represented approximately 20% of Eni’s production in Algeria in 2014.

Production in blocks 401a/402a comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 14% of Eni’s production in Algeria in 2014.

The main fields in block 403 are BRN, BRW and BRSW which accounted for approximately 11% of Eni’s production in Algeria in 2014.

48


Table of Contents
The main fields in block 404 are HBN and HBNS and satellites which accounted for approximately 25% of Eni’s production in Algeria in 2014.

Production in block 405b comes mainly from MLE-CAFC project and accounted for approximately 15% of Eni’s production in the Country in 2014. Development and optimization activities progressed at the MLE-CAFC project. Activities include an additional oil phase with start-up expected in 2017, targeting a production plateau of approximately 33 KBOE/d net to Eni.

The El-Merk field is the main production project in the block 208 and accounted for approximately 15% of Eni’s production in Algeria in 2014. Production ramp-up was completed in the year with a production plateau target of approximately 18 KBOE/d net to Eni.

Eni was granted three prospection permits in the Timimoun and Oued Mya areas, in Southern onshore Algeria. The agreements expire in two years and cover a total acreage of 46,837 square kilometers. The program includes studies and drilling of prospection wells to assess the mineral potential.

Egypt. Eni has been present in Egypt since 1954. In 2014, Eni’s share of production in this Country amounted to 195 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%), and in the Western Desert mainly the Meleiha (Eni’s interest 76%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%) and Ras el Barr (Eni’s interest 50%, non operated), located offshore the Nile Delta. In 2014, production from these large concessions accounted for approximately 94% of Eni’s production in Egypt.

 

Exploration and production activities in Egypt are regulated by PSAs.

In March 2015, Eni and the Egyptian Ministry of Petroleum and Mineral Resources signed a framework agreement to develop the oil and gas resources in the Country with an estimated investment of $5 billion at 100%. The investments, which will be utilized through the realization of projects to be implemented in the next 4 years, are directed to the development of 200 mm/BBL of oil and 1.3 TCF of gas.

In 2014, Eni was awarded: (i) the operatorship of the South-West Meleiha onshore exploration licenses (Eni’s interest 100%), nearby the Meleiha concession, and the Block 9 (Eni’s interest 100%) and Block 8 (Eni’s interest 50%) located in the deep offshore of the Mediterranean Sea. The closing was achieved in the early 2015 with the ratification of the relevant concession agreements; and (ii) the Shorouk concession (Eni’s interest 100%) in the deep offshore of the Mediterranean Sea.

In August 2014, the DEKA project (Eni operator with a 50% interest) started up with a production of approximately 64 mmCF/d of gas and 800 BBL/d of associated condensates. Produced gas is being processed at the onshore El Gamil plant. Peak production of approximately 230 mmCF/d net to Eni is expected by the first quarter of 2015.

Development activities concerned: (i) infilling activities at the Belayim, Ha’py (Eni’s interest 50%), El Temsah and Pourt Fouad (Eni’s interest 100%) fields to optimize the mineral potential recovery factor; and (ii) start-up of the END Phase 3 sub-sea project (Eni’s interest 50%).

Exploration activities yielded positive results with: (i) the oil discovery ARM-14 in the Abu Rudeis license (Eni’s interest 100%) in the Gulf of Suez. The discovery was linked to the nearby production facilities; and (ii) the oil discovery West Deep in the Meleiha concession (Eni’s interest 76%) that flowed at approximately 2 KBBL/d in test production.

49


Table of Contents
Libya. Eni started operations in Libya in 1959.

The internal situation in Libya continues to represent an issue to Eni’s management. Following the internal conflict of 2011 and the fall of the regime, which forced the Company to shut down almost all its producing facilities including gas exports for a period of about 8 months, a period of social and political instability began which turned into disorders, strikes, protests and a resurgence of the internal conflict. These events jeopardized Eni’s ability to perform its industrial activity in safety, forcing the Company to interrupt its operations on certain occasions as precautionary measure. These events were fairly frequent in 2013 and sporadic in 2014. In 2014, Eni’s facilities in Libya produced on average 233 KBOE/d, registering a small increase compared to 2013. For further information on this matter, see "Item 3 – Risk factors".

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

 

In the exploration phase, Eni is operator of four onshore blocks in the Kufra area (186/1, 2, 3 & 4) and in the onshore contract Areas A, B and offshore Area D.

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

Looking forward, management is prudently assuming a production level in line with 2014.

Exploration activities yielded positive results with the B1-16/4 well in the Bahr Essalam South prospects in the offshore Area D that flowed at approximately 35 mmCF/d of natural gas and over 600 BBL/d of condensates in test production.

Tunisia. Eni has been present in Tunisia since 1961. In 2014, Eni’s production amounted to 12 KBOE/d.

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

Exploration and production in this Country are regulated by concessions.

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

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

Sub-Saharan Africa

Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2014, Sub-Saharan Africa accounted for 20% of Eni’s total worldwide production of oil and natural gas.

50


Table of Contents
Angola. Eni has been present in Angola since 1980. In 2014, Eni’s production averaged 76 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore.

The main Eni’s asset in Angola is the Block 15/06 (Eni operator with a 35% interest) where the West Hub project started up in 2014 and other development projects are underway. Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni’s interest 9.8%) North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin.

Eni retains interests in other non producing concessions, particularly the Lianzi Development Area (Block 14K/A IMI Unit Area - Eni’s interest 10%), Block 35/11 (Eni operator with a 30% interest) and in Block 3/05-A (Eni’s interest 12%), onshore Cabinda North (Eni’s interest 15%) and the Open Areas of Block 2 awarded to the Gas Project (Eni’s interest 20%).

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

In November 2014, Eni signed with the national oil company Sonangol a strategic agreement on future co-operation activities. In particular, the agreement includes the studies to analyze the potential of the non-associated gas present in the Lower Congo Basin and offshore Angola. The project scope is to analyze the different options both internationally and in the domestic market, also in order to sustain the local economy. In addition, the companies will asses possible projects on the mid-downstream business to be carried out in Angola.

 

In December 2014, first oil was achieved at the West Hub development project in Block 15/06 in the deep offshore. This first Eni-operated producing project in the Country is currently producing 45 KBOE/d through the N’Goma FPSO, with a production ramp-up expected to reach a plateau up to 100 KBOE/d in the coming months. The start-up was achieved in 44 months following the announcement of the commercial discovery. The N’Goma FPSO is currently producing from the Sangos discovery; future production will leverage the progressive hooking up of the Block’s discoveries.

The main development activities performed in the year concerned: (i) the Mafumeira Sul field (Eni’s interest 9.8%) with start-up expected in 2016; (ii) the Lianzi project in the Block 14K/A Imi Unit Area (Eni’s interest 10%), with start-up expected in the second half of 2015 and production plateau of 35 KBOE/d; and (iii) the Kizomba satellites Phase 2 project (Eni’s interest 20%). The project provides to put into production three additional discoveries that will be linked to the existing FPSO. Start-up is expected in 2015, with a production plateau of 70 KBOE /d in 2016.

Exploration activities yielded positive results with: (i) the Ochigufu 1 NFW discovery in the deep water of the Block 15/06. In January 2015, Eni obtained from the Angolan Authorities a three-year extension of the exploration period of the above mentioned block; and (ii) the appraisal of the Pinda FM discovery in the Block 0 (Eni’s interest 9.8%).

In the medium term, management expects to increase Eni’s production to approximately 150 KBOE/d reflecting additions from ongoing development projects.

Congo. Eni has been present in Congo since 1968. In 2014, production averaged 100 KBOE/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore.

Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 56%), Loango (Eni’s interest 42.5%), Ikalou (Eni’s interest 100%), Djambala (Eni’s interest 50%), Foukanda and Mwafi (Eni’s interest 58%), Kitina (Eni’s interest 52%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Nené Marine (Eni 65%), Zingali and Loufika (Eni’s interest 100%) fields.

51


Table of Contents
  Other relevant producing areas are a 35% interest in the Pointe-Noire Grand Fond, PEX and Likouala permits.

Exploration and production activities in Congo are regulated by production sharing agreements.

In July 2014, a cooperation agreement was signed with the relevant authorities and ratified by law to extend existing oil permits and to develop new initiatives in the Country’s coastal basin, which extends from onshore Mayombe to frontage deep waters.

At the end of December 2014 was achieved the start-up of the recent Nené Marine discovery in block Marine XII just 8 months after obtaining the production permit. The early production phase is yielding 7,500 BOE/d and the fast-track development of the field has leveraged on the synergies with the front-end loading and the infrastructures of the fields located in the area. The full-field development will take place in several stages and will include the installation of production platforms and the drilling of approximately 30 wells, with a plateau of over 120 KBOE/d.

Development of the Litchendjili sanctioned project progressed in the Marine XII Block. The project provides for the installation of a production platform, the construction of transport facilities and onshore treatment plant. Start-up is expected in the second half of 2015 with a peak production of 12 KBOE/d net to Eni.

Exploration activities yielded positive results in the Marine XII offshore Block (Eni operator with a 65% interest) with: (i) the Nené Marine 3 appraisal well confirming the oil and gas mineral potential of the area; and (ii) the Minsala Marine oil discovery.

In the medium term, management expects to increase Eni’s production in Congo, with a level of approximately 120 KBOE/d in 2018.

Ghana. Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni’s interest 47.22%) and Offshore Keta Contract Area (Eni’s interest 35%) exploration permits.

In January 2015, Eni and the relevant authorities of the Country sanctioned the Offshore Cape Three Points integrated oil and gas project. First oil is expected in 2017, first gas in 2018 and production is expected to peak at 80 KBOE/d.

Mozambique. Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 Block (Eni operator with a 50% interest) located in the offshore Rovuma Basin. The exploration period expires in 2015, and a term of 30 years is awarded in respect of any approved Development and Production Area.

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

Exploration activities for the year yielded positive results with the appraisal gas wells Agulha 2 and Coral 4 DIR, confirming the extension of their respective discoveries.

The Company is planning to develop as first target the Coral discovery and a portion of the Mamba straddling resources. As part of the Mamba plan, based on the enactment of a law decree which defines the fiscal and contractual regime applicable to onshore liquefaction projects, Eni expects to obtain the necessary authorizations to develop and produce up to 12 TCF from the straddling reservoir via an independent industrial plan which needs to be coordinated with the operator of Area 1.

An Unitization Agreement for the straddling resources of Mamba has to be agreed among concessionaries of the straddling reservoirs and submitted to the Mozambique Government within six months dating back to the enactment of the special law on onshore projects which occurred in December 2014.

52


Table of Contents

The Coral project scheme comprises construction of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) fed by subsea wells. The development plan was formally submitted to the local authorities at the end of 2014. The FID is expected in the second half of 2015. The award of the relevant EPCIC contracts for the construction, installation and commissioning of the floating unit is expected by the end of 2015. Production start-up is expected for the end of 2019.

The development plan of the first stage of the Mamba project contemplates construction and commissioning of two onshore LNG trains and the drilling of 16 subsea wells, with start-up in 2022. The scheduled activities comprise: (i) the submission of the Declaration of Commerciality to the Government by the third quarter of 2015; (ii) the filing of the development plan by the end of 2015; and (iii) the finalization of the commercial agreements and the project financing by the first quarter of 2016. The FID is expected in 2016-2017.

In October 2014, Eni signed with the South Korean company KOGAS a cooperation agreement for joint development opportunities in the upstream and LNG areas, in particular in the Area 4 in Mozambique.

Nigeria. Eni has been present in Nigeria since 1962. In 2014, Eni’s oil and gas production averaged 130 KBOE/d located mainly onshore and offshore the Niger Delta.

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%) and OPL 245 (Eni’s interest 50%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the Country, Eni also holds a 5% interest in 21 onshore blocks and in 5 conventional offshore blocks.

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

Exploration and production activities in Nigeria are regulated mainly by production sharing agreements and concession contracts, as well as service contracts, in two blocks, where Eni acts as contractor for state-owned company.

53


Table of Contents

In the year production start-up was achieved at the Bonga NW field in the OML 118 Block with the drilling and completion of 4 production and 2 injection wells.

Development activities progressed at the OML 28 Block (Eni’s interest 5%) with: (i) the drilling campaign within the integrated oil and natural gas project in the Gbaran-Ubie area. The development plan provides for the supply of natural gas to the Bonny liquefaction plant by means of the construction of a Central Processing Facility (CPF) with a treatment capacity of approximately 1 BCF/d of gas and 120 KBBL/d of liquids; and (ii) the development plan of the Forkados-Yokri field including the drilling of 24 producing wells, the upgrading of existing flow stations and the construction of transport facilities is expected to start-up by 2015.

Eni holds a 10.4% interest in the Nigeria LNG Ltd which runs the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. The seventh unit is being engineered as it is in the planning phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount of 2,825 mmCF/d (268 mmCF/d net to Eni corresponding to approximately 49 KBOE/d). LNG production is sold under long-term contracts and exported to European, Asian and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.

In the medium term, management expects to increase Eni’s production in Nigeria to approximately 150 KBOE/d.

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2014, Eni’s operations in Kazakhstan accounted for 6% of its total worldwide production of oil and natural gas.

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

The participating interest in the NCSPSA has been redefined, effective as of January 1, 2008, in line with an agreement signed in October 2008 with Kazakh Authorities which proportionally diluted the participating interest of the international companies by transferring a 10% stake in the project to the Kazakh national oil company, KazMunaiGas. In addition to Eni, the partners of the consortium are the Kazakh national oil company, KazMunaiGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, CNPC with 8.33% and Inpex with 7.56%.

Under the operating model agreed in 2008, Agip Kazakhstan North Caspian Operating Co NV (AKCO), a wholly-owned affiliate of Eni, was assigned the responsibility of executing the development of Phase 1 of the project (the so-called "Experimental Program") acting as agent of the operator North Caspian Operating Co BV (NCOC) owned by all the partners of the Consortium.

On May 23, 2012, the Consortium partners and the Authority of the Republic of Kazakhstan signed an agreement to amend the sanctioned development plan at the Experimental Program of the Kashagan field (Amendment 4) which included an update to the project schedule, a revision of investment estimates and a settlement agreement of all pending claims relating to recoverable costs and other tax matters. The amendment also included a commercial framework to supply a share of the natural gas produced from Kashagan to the domestic market and an agreement whereby the international partners of the Consortium shall finance the share of project cost to be borne by the Kazakh KMG partner, in excess to the amounts sanctioned in the original budget costs (Amendment 3).

In 2014, the Consortium agreed a new setup of the operating model to execute the development of the project, targeting to streamline decision-making process, to increase efficiency in operations and to reduce costs. This new operating model provides that a company, participated by the seven partners of the consortium, acts as the sole operator of all exploration, development and production activities at the Kashagan field. As part of this process, in October 2014 the shareholding in AKCO NV (Eni’s interest 100%) was transferred to NCOC BV. The activities needed to set up the new operating model will be completed by the first half of 2015.

In December 2014, the Consortium and the Kazakh Government signed an agreement which settled a number of pending issues relating to financial, environmental and operational matters.

During the course of 2014, the Consortium performed an assessment of the technical issues which forced the operator to shut down the production at the Kashagan field soon after the production start-up with the effective

54


Table of Contents

completion of Phase 1 of the development plan (the Experimental Program). The issue regarded a gas leak at a support pipeline. The findings of the assessment confirmed the necessity to fully replace the damaged pipelines. The Consortium recently finalized the contracts for the replacement of both oil and gas lines. The Consortium expects to complete the installation works in the second half of 2016 with production re-start by the end of 2016. The planned production rate will be achieved during 2017.

The Phase 1 is targeting an initial production capacity of 180 KBBL/d; when a second offshore treatment train comes online and compression facilities for gas reinjection are operational production capacity will ramp up to 370 KBBL/d. The partners are planning to further increase available production capacity up to 450 KBBL/d by installing additional gas compression capacity for reinjection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities.

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

As of December 31, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013. The major part of these reserves are classified proved undeveloped. See the discussion on "Proved Undeveloped Reserves" section.

As of December 31, 2013, Eni’s proved reserves booked for the Kashagan field amounted to 565 mmBOE, barely unchanged from 2012.

As of December 31, 2012, Eni’s proved reserves booked at the Kashagan field amounted to 568 mmBOE, recording an increase compared to 2011 reflecting the settlement agreement signed with Kazakh Authority whereby Eni will be able to produce and market volumes of natural gas from Kashagan.

As of December 31, 2014, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $8.5 billion (euro 7.0 billion at the EUR/USD exchange rate of December 31, 2014). This capitalized amount included: (i) $6.2 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $2.3 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years.

As of December 31, 2013, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $8.2 billion (euro 5.9 billion at the EUR/USD exchange rate of December 31, 2013). This capitalized amount included: (i) $6.1 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $2.1 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years.

Karachaganak. Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture. On June 28, 2012, the international Contracting Companies of the Final Production Sharing Agreement (FPSA) of the giant Karachaganak gas-condensate field and the Republic of Kazakhstan closed a settlement agreement of all pending claims relating to the recovery of costs incurred to develop the field and certain tax matters. Eni’s interest in the Karachaganak project is 29.25%.

 

55


Table of Contents

In 2014, production of the Karachaganak field averaged 242 KBBL/d of liquids (52 net to Eni) and 842 mmCF/d of natural gas (181 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 50%) at the Russian gas plant in Orenburg and the remaining volumes is utilized for re-injecting in the higher layers and the production of fuel gas. Approximately 90% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production (approximately 16 KBBL/d) are marketed at the Russian terminal in Orenburg.

The expansion project is currently being assessed by the Consortium by means of the installation, in stages, of gas treatment plants and re-injection facilities to support liquids production plateau and increase gas marketable volumes. Phase-one development to increase injection and treatment capacity of natural gas are under economical and technical assessment. Further development projects to support liquids production plateau are under study.

As of December 31, 2014, Eni’s proved reserves booked for the Karachaganak field amounted to 489 mmBOE, barely unchanged compared to 2013.

As of December 31, 2013, Eni’s proved reserves booked for the Karachaganak field amounted to 470 mmBOE, barely unchanged from 2012.

As of December 31, 2012, Eni’s proved reserves booked for the Karachaganak field amounted to 473 mmBOE, reporting a slight decrease from 2011 deriving mainly from the divestment of Eni’s stake in the project, partly offset by upwards revisions.

Rest of Asia

In 2014, Eni’s operations in the rest of Asia accounted for 6% of its total worldwide production of oil and natural gas.

China. Eni has been present in China since 1984 with activities located in the South China Sea. In 2014, Eni’s production amounted to 4 KBOE/d.

Exploration and production activities in China are regulated by PSAs.

In 2014, hydrocarbons were produced from the offshore Blocks 16/08 through 3 platforms connected to an FPSO. Production comes mainly from the HZ25-4 field (Eni’s interest 49%).

In June 2014, Eni signed with CNOOC the PSC for exploration activity of the Block 50/34, located in the shallow water of the South China Sea.

Indonesia. Eni has been present in Indonesia since 2001. In 2014, Eni’s production mainly composed of gas, amounted to 13 KBOE/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua; in total, Eni holds interests in 14 blocks.

Exploration and production activities in Indonesia are regulated by PSAs.

Main ongoing activities to feed the Bontang plant concerned: (i) the Jangkrik field (Eni operator with an 55% interest) in the Kalimantan offshore. The project includes drilling of production wells linked to a Floating Production Unit for gas and condensate treatment, as well as construction of a transportation facility. Start-up is expected in 2017; and (ii) the Bangka project (Eni’s interest 20%) in the Eastern Kalimantan, with start-up expected in 2016.

Exploration activities yielded positive results with a gas discovery through the Merakes 1 NFW exploration well in the East Sepinggan offshore block (Eni operator with an

 

56


Table of Contents
85% interest). This discovery is located in proximity of the operated field of Jangkrik, and will supply additional gas volumes to the Bontang LNG plant.

Iran. Eni has been operating in Iran for several years under four Service Contracts (South Pars, Darquain, Dorood and Balal, these latter two projects being operated by another international oil company) entered into with the NIOC between 1999 and 2001, and no other exploration and development contracts have been entered into since then. All above mentioned projects have been completed or substantially completed. The formal hand over of operations to local partners at the Darquain project was completed in the course of 2014, marking termination of Eni’s direct operations in the Country. Going forward, Eni’s involvements will consist of finalizing the reimbursement of its past investments. In 2014, Eni’s contractual reimbursements were equivalent to a production of 1 KBOE/d, lower than 1% of the Group’s worldwide production. Eni believes that its activities in Iran are marginal to the Group’s results of operations and cash flow. For further information on this matter, see "Item 3 – Risk factors".

Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companies and the national oil company Missan Oil, holds a 41.6% interests in the Zubair oilfield.

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

In 2014, production of the Zubair field averaged 21 KBBL/d net to Eni.

In 2014, phase one of the Rehabilitation Plan of the Zubair field progressed. The project includes the construction of an oil treatment plant for a capacity of 300 KBBL/d, the revamping of existing treatment facilities and the drilling of production and water injection wells.

In March 2014, the national oil company South Oil Company sanctioned the Enhanced Redevelopment Plan to achieve a production plateau of 850 KBBL/d. The main contracts to build new facilities were awarded in the first half of 2014.

Pakistan. Eni has been present in Pakistan since 2000. In 2014, Eni’s production mainly composed of gas amounted to 43 KBOE/d.

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

Eni’s main permits in the Country are Bhit/Bhadra (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2013 accounted for 75% of Eni’s production in Pakistan.

Russia. The drilling exploration program was halted due to the sanctions enacted by European Union and the United States. Eni is closely monitoring developments of

 

57


Table of Contents

the situation and has required all relevant authorizations to continue the exploration activities in compliance with the current sanction regime against Russia. For further information on this matter, see "Item 3 – Risk factors".

Turkmenistan. Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the Country. In 2014, Eni’s production averaged 9 KBOE/d.

Exploration and production activities in Turkmenistan are regulated by PSA.

In November 2014, Eni and the State Agency for Management and Use of Hydrocarbon Resources signed an addendum to the production sharing agreement which extends the duration of the PSA to 2032. The agreement also establishes the transfer of a 10% stake out of the contractor share to the State oil company Turkmenneft (Eni retains a 90% interest stake).

In addition, Eni and Turkmen State Agency signed a Memorandum of Understanding to evaluate the extension of Eni’s activities also in the Turkmenistan’s offshore section of the Caspian Sea.

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

Development activities include: (i) a program to mitigate the natural field production decline; and (ii) the completion of the revamping of the treatment oil plant at the Burun field in order to increase treatment capacity.

Americas

In 2014, Eni’s operations in America area accounted for 8% of its total worldwide production of oil and natural gas.

Ecuador. Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni’s interest 100%) located in the Oriente Basin, in the Amazon forest. In 2014, Eni’s production averaged 12 KBBL/d.

Exploration and production activities in Ecuador are regulated by a service contract that expires in 2023.

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

In the year, the following projects were sanctioned: (i) Villano field Phase VI (infilling), with a production start-up expected in 2016; and (ii) Oglan discovery development, with start-up expected in 2017.

Exploration activities yielded positive results with the Oglan-2 exploration well in Block 10, located near the processing facilities of the Villano field.

Trinidad & Tobago. Eni has been present in Trinidad & Tobago since 1970. In 2014, Eni’s production averaged 60 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block located offshore North of Trinidad.

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

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

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

In 2014, Eni’s oil and gas production was 88 KBOE/d, mainly from the Gulf of Mexico and Alaska fields.

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

58


Table of Contents

Eni holds interests in 188 exploration and production blocks in the Gulf of Mexico of which 122 are operated by Eni.

Eni was awarded the operatorship of exploration licenses MC246 and MC290 (Eni’s interest 100%) in the Gulf of Mexico and in the Leon Valley (Western Texas) with a 50% interest for exploring and developing an area with shale oil reservoirs.

The main operated fields are Allegheny and Appaloosa (Eni’s interest 100%), Pegasus (Eni’s interest 85%), Longhorn, Devils Towers and Triton (Eni’s interest 75%). Eni also holds interests in Europa (Eni’s interest 32%), Medusa (Eni’s interest 25%) and Thunder Hawk (Eni’s interest 25%) fields.

Production start-up was achieved at the St. Malo (Eni’s interest 1.25%) and Lucius (Eni 8.5%) fields, the latter started up in January 2015. The start-up of Hadrian South (Eni’s interest 30%) is achieved in March 2015. In the Greater Hadrian Area (Lucius and Hadrian South fields) Eni plans to achieve an expected net production peak of 22 KBOE/d.

Development activities concerned: (i) the Heidelberg project (Eni’s interest 12.5%) in the deep offshore of the Gulf of Mexico. Activities include the drilling of 5 production wells and the installation of a production platform. Start-up is expected at the end of 2016 with a production of 9 KBOE/d net to Eni; (ii) the drilling of development wells at the operated Devils Tower and Pegasus fields, as well as non-operated Europa and K2 (Eni’s interest 13.39%) fields; and (iii) the development of shale gas reserves in the Alliance area (Eni’s interest 27.5%) with start-up of additional 21 production wells.

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

Eni holds interests in 99 exploration and development blocks in Alaska, with interests ranging from 10 to 100%; Eni is the operator in 46 of these blocks.

59


Table of Contents

Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) with a 2014 overall net production of approximately 21 KBBL/d.

During 2014, drilling activities progressed at the Nikaitchuq and Oooguruk fields.

In June 2014, the Nikaitchuq field achieved the production milestone of 25 KBOE/d.

Exploration activities yielded positive results with the Stallings 1H and Mitchell 1H exploratory wells, under the agreement with Quicksilver Resources signed at the end of 2013 providing for joint evaluation, exploration and development of shale oil reservoirs in the Southern part of the Delaware Basin in West Texas. The wells were already connected to existing production facilities with an initial flow of 1,500 BBL/d.

Venezuela. Eni has been present in Venezuela since 1998. In 2014, Eni’s production averaged 10 KBBL/d.

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

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

Eni’s production comes from the Corocoro field (Eni’s interest 26%), in the Gulfo de Paria, and the Junin 5 field (Eni’s interest 40%), located in the Orinoco Oil Belt which contains 35 BBBL of certified heavy oil in place.

Drilling activities progressed at the Junin 5 field with the drilling of 22 wells. The early production of the first phase started up in 2013 with a target plateau of 75 KBBL/d. The full field development phase includes a long-term production plateau of 240 KBBL/d.

Ongoing development activities progressed at the Perla gas field in the Cardon IV Block (Eni’s interest 50%), located in the Gulf of Venezuela. The early production start-up is expected by the second quarter of 2015 with a target production of approximately 450 mmCF/d. The full project includes the utilization of 4 existing wells, the drilling of 17 additional wells and the installation of production platforms linked by pipelines to an onshore treatment plant. Production ramp-up is expected in 2017 with a target of approximately 800 mmCF/d. The development plan targets a long-term production plateau of approximately 1,200 mmCF/d from 2020.

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

Australia and Oceania

Eni’s operations in this region area are conducted mainly in Australia. In 2014, the area of Australia and Oceania accounted for 2% of Eni’s total worldwide production of oil and natural gas.

Australia. Eni has been present in Australia since 2001. In 2014, Eni’s production of oil and natural gas averaged 25 KBOE/d. Activities are focused on conventional and deep offshore fields.

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

The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%), JPDA 03-13 (Eni’s interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest). In the appraisal and development phase Eni holds interests in NT/P68 (Eni’s interest 50%) and NT/RL7 (Eni’s interest 32.5%). In addition Eni holds interest in 6 exploration licenses, of which 1 in the JPDA.

Ongoing development activities concerned: (i) Phase 3 project of Bayu Undan field in the JPDA 03-13 Block in order to increase liquids and LNG production; and (ii) drilling development activities at the Kitan producing field in the JPDA 06-105 Block in order to increase liquids production.

 

Capital expenditures

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

60


Table of Contents

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

The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. Disclosure responsive to this requirement is presented under "Item 3 – Political considerations – Risks associated with our presence in sanction targets" and below in this section.

In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes.

The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions also considering the waiver that we were granted by relevant U.S. Authorities, including the U.S. Department of State, in relation to certain Iran-related activities. For more information please refer to "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets".

As described in more detail under "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets", in 2014, Eni carried out support activities and services in respect of certain oilfields in Iran pursuant to certain legacy Service Contracts. Eni’s operating expenses pursuant to those contracts in 2014 amounted to approximately $1 million. In addition, in connection with its remaining Iranian operations, in 2014, Eni paid approximately $3 million for social security, withholding tax, corporate tax and rental tax.

In 2014, Eni’s production in Iran averaged 1 KBOE/d, and is negligible in comparison with Eni Group’s total production for the year. We booked revenues of $26 million in 2014 in connection with our share of equity production and we reported a net loss of $16 million at our Iranian operations. As of the balance sheet date Eni had outstanding trade receivables amounting to $76 million towards Iranian oil national companies which were recorded in connection with revenues recognized in 2014 and in previous reporting periods. In 2014, we collected cash payments for a total of $275 million. Those revenues and trade receivables related to the recovery of the costs incurred by Eni in its performance of petroleum projects, mainly pertaining to the ongoing Darquain project as disclosed under "Item 3 – Risk factors – Political considerations – Risks associated with our presence in sanction targets". We had no payables towards Iranian national oil companies as of the balance sheet date. We had a payable amounting to $23 million relating to health and social security insurance due to the Iranian Social Security Organization, which will be settled upon termination of our oil projects.

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

 

Gas & Power

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply and marketing. This segment also includes the activities of electricity generation. In 2014, Eni’s worldwide sales of natural gas amounted to 89.17 BCM, including 3.06 BCM of gas sales made directly by Eni’s Exploration & Production segment. Sales in Italy amounted to 34.04 BCM, while sales in European markets were 46.22 BCM that included 4.01 BCM of gas sold to certain importers to Italy.

In the Gas & Power segment we expect a weak outlook for natural gas sales and prices due to structural headwinds in the industry as we forecast demand stagnation, oversupplies and strong competition across all of our main markets in Europe, including Italy. Management does not expect any improvements in this scenario in the next four-year plan. Management expects gas sales to be flat to down over the next four years and gas prices to continue falling.

Going forward we believe that reduced sales opportunities and continued pricing competition will be caused by weaker-than-anticipated demand growth. This is expected to be further exacerbated by macroeconomic uncertainties and the current downturn in the thermoelectric sector which will be penalized by the competition from coal which is cheaper than gas in firing power plants and the development of renewable sources of energy (photovoltaic, solar to name the most important). The absolute level of gas consumption in Europe contracted by approximately 12% in the time span from 2008 to 2013 and in 2014 gas consumption fell dramatically by 12% in Italy and in Europe. According to our projections gas consumption will return back to 2013 levels sometime in 2020. Against this backdrop, European markets remains well supplied thanks to the fast development of liquid hubs where operators can trade spot gas. In 2013, approximately 62% of gas volumes supplied were traded at continental hubs. These trends will drive continuing

61


Table of Contents

 

competition and pricing pressure, which are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses whereby wholesaler operators are forced to compete aggressively on pricing in order to limit the financial exposure dictated by the contracts in case of volumes off-taken below the minimum take.

Against this backdrop, Eni’s main focus is on profitability and sustainable cash flow generation, according to the following guidelines: (i) alignment of the supply portfolio to market conditions starting from 2016, leveraging on further renegotiations; (ii) the full streamlining of operations and optimization of logistic costs; and (iii) development and growth in the value added segments, in particular in the retail segment, developing the client base also through the sale of extra-commodity products, as well as in the LNG segment, leveraging on the marketing opportunities in premium markets and upstream integration.

Supply of natural gas

In 2014, Eni’s consolidated subsidiaries supplied 82.91 BCM of natural gas, down by 2.76 BCM, or 3.2% from 2013. Gas volumes supplied outside Italy (75.99 BCM from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, down by 2.53 BCM, or 3.2% compared to the previous year, due to lower volumes purchased in Russia (down 2.91 BCM), Algeria (down 1.80 BCM), Norway (down 0.73 BCM) and the United Kingdom (down 0.40 BCM), partly offset by higher volumes purchased in Libya (up 0.88 BCM) and the Netherlands (up 0.40 BCM). Supplies in Italy (6.92 BCM) registered a slight decrease from 2013 (down 0.23 BCM) due to mature fields’ decline. In 2014, main gas volumes from equity production derived from: (i) Italian gas fields (5.6 BCM); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.1 BCM); (iii) Libyan fields (2 BCM); (iv) the United States (0.5 BCM); and (v) other European areas (Croatia with 0.3 BCM). Considering also direct sales of the Exploration & Production Division and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 16 BCM representing 18% of total volumes available for sale.

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

Natural gas supply  

2012

 

2013

 

2014

   
 
 
   

(BCM)

Italy   7.55     7.15     6.92  
Outside Italy   79.14     78.52     75.99  
Russia   19.83     29.59     26.68  
Algeria (including LNG)   14.45     9.31     7.51  
Libya   6.55     5.78     6.66  
the Netherlands   11.97     13.06     13.46  
Norway   12.13     9.16     8.43  
the United Kingdom   3.20     3.04     2.64  
Hungary   0.61     0.48     0.38  
Qatar (LNG)   2.88     2.89     2.98  
Other supplies of natural gas   5.43     3.63     5.56  
Other supplies of LNG   2.09     1.58     1.69  
Total supplies of subsidiaries   86.69     85.67     82.91  
Withdrawals from (input to) storage   (1.35 )   (0.58 )   (0.20 )
Network losses, measurement differences and other changes   (0.28 )   (0.31 )   (0.25 )
Volumes available for sale of Eni’s subsidiaries   85.06     84.78     82.46  
Volumes available for sale of Eni’s affiliates   7.53     5.78     3.65  
E&P volumes   2.73     2.61     3.06  
Total volumes available for sale   95.32     93.17     89.17  


Sales of natural gas

In 2014, natural gas sales amounted to 89.17 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico), representing a decrease of 4 BCM, or 4.3% from the previous year. Sales in Italy decreased to 34.04 BCM, down by 5.1%. Lower sales were reported in the industrial, residential and thermoelectric segments due to decreased consumption, unusual winter weather conditions and a further deterioration of the trading environment for electricity sales reflecting higher use of hydroelectric and renewable sources, as well as lower demand. These negative trends were partially offset by higher spot volumes. Sales in Europe of 42.21 BCM decreased by 1.1% driven mainly by lower volumes marketed in Germany-Austria, France and the United Kingdom due to competitive pressure, partially offset by higher sales in Benelux and the Iberian Peninsula. Direct sales of Exploration & Production in Northern Europe and the United States

62


Table of Contents

(3.06 BCM) increased by 0.45 BCM due to higher volumes sold in the North Sea. Sales to importers to Italy decreased by 14.1% compared to the previous year, due to lower availability of Libyan output and lower sales to Extra European markets (down 20.4%) driven by lower volumes marketed in the United States and Argentina.

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

Natural gas sales by entity  

2012

 

2013

 

2014

   
 
 
   

(BCM)

Total sales of subsidiaries   84.30   83.60   81.73
Italy (including own consumption)   34.66   35.76   34.04
Rest of Europe   44.57   42.30   43.07
Outside Europe   5.07   5.54   4.62
Total sales of Eni’s affiliates (Eni’s share)   8.29   6.96   4.38
Italy   0.12   0.10    
Rest of Europe   6.45   5.05   3.15
Outside Europe   1.72   1.81   1.23
Total sales of G&P   92.59   90.56   86.11
E&P in Europe and in the Gulf of Mexico (a)   2.73   2.61   3.06
Worldwide gas sales   95.32   93.17   89.17

(a)   E&P sales include volumes marketed by the Exploration & Production Division in Europe (2.06, 2.08 and 2.60 BCM in 2012, 2013 and 2014, respectively) and in the Gulf of Mexico (0.67, 0.53 and 0.46 BCM in 2012, 2013 and 2014, respectively).

 

Natural gas sales by market  

2012

 

2013

 

2014

   
 
 
   

(BCM)

ITALY   34.78   35.86   34.04
Wholesalers   4.65   4.58   4.05
Italian gas exchange and spot markets   7.52   10.68   11.96
Industries   6.93   6.07   4.93
Medium-sized enterprises and services   0.81   1.12   1.60
Power generation   2.55   2.11   1.42
Residential   5.89   5.37   4.46
Own consumption   6.43   5.93   5.62
INTERNATIONAL SALES   60.54   57.31   55.13
Rest of Europe   51.02   47.35   46.22
Importers in Italy   2.73   4.67   4.01
European markets   48.29   42.68   42.21
Iberian Peninsula   6.29   4.90   5.31
Germany-Austria   7.78   8.31   7.44
Benelux   10.31   8.68   10.36
Hungary   2.02   1.84   1.55
UK/Northern Europe   4.75   3.51   2.94
Turkey   7.22   6.73   7.12
France   8.36   7.73   7.05
Other   1.56   0.98   0.44
Extra European markets   6.79   7.35   5.85
E&P in Europe and in the Gulf of Mexico   2.73   2.61   3.06
WORLDWIDE GAS SALES   95.32   93.17   89.17


European markets

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

Benelux. Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, through the Belgium Gas & Power branch, in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2014, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 10.36 BCM (8.68 BCM in 2013), up by 1.68 BCM, or 19.4%, due to higher spot sales. In 2012, Eni launched its brand in the business and retail gas and power market in Belgium. The Eni brand replaced that of local operators acquired in the past few years with the aim of consolidating its leadership in the market.

63


Table of Contents

France. Eni sells natural gas to industrial clients, wholesalers and power generation, as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary. In 2014, sales in France amounted to 7.05 BCM (7.73 BCM in 2013), a decrease of 0.68 BCM, or 8.8%, from a year ago. In 2013, Eni launched its brand in France, replacing those of the local operators acquired in the past few years with the aim of becoming one of the major retail operators in the Country.

Germany-Austria. Eni operates in Germany-Austria through Gas & Power branches. In 2014, Eni divested its 50% stake in EnBW Eni Verwaltungsgesellschaft (EEV), a joint venture which controls the companies Gasversorgung Süddeutschland (GVS) and Terranets BW operating in the gas marketing and transport, to the partner EnBW. Currently, sales in this market are ensured by Eni’s direct sales force. In 2014, total sales in Germany-Austria amounted to 7.44 BCM, a decrease of 0.87 BCM, or 10.5%.

Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and through Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2014, UFG gas sales amounted to 3.92 BCM (1.96 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2014, total sales in the Iberian Peninsula amounted to 5.31 BCM, an increase of 0.41 BCM, or 8.4%.

Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2014, sales amounted to 7.12 BCM, an increase of 0.39 BCM, or 5.8% from a year ago.

United Kingdom. Eni through its subsidiary ETS markets in the United Kingdom the equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2014, sales amounted to 2.94 BCM, a decrease of 16.2% from a year ago.

 

The LNG business

Eni is implementing its fully-integrated worldwide commercial LNG Strategy leveraging on Eni’s:
  technological and operational involvement in all phases of the LNG value chain: provide feed gas, liquefaction, shipping, re-gasification and sales both through direct activities and interests in joint ventures;
  portfolio of long-term LNG supply contracts mainly from Qatar, Algeria and Nigeria;
  medium-term LNG sales contracts with buyers all over the world; and
  LNG portfolio management and operations activities targeting value creation by optimizing Eni’s supply and sales portfolio in close operation with Eni’s trading activities and Eni’s European pipeline gas businesses.

Eni’s LNG development strategy is based upon Eni’s world scale gas reserves in Mozambique combined with the existing LNG activities in Nigeria, Angola, Australia, Trinidad & Tobago and Indonesia.

In 2014, Eni could successfully continue its value creation in both the Atlantic and Pacific Basin LNG markets notwithstanding the context of a European Gas Market still impacted by the economic downturn and oversupply and structural modifications caused by the shale gas development in the U.S. market.

However, the significant drop in oil prices from which the gas prices in markets in the Pacific Basin and South America are derived and which has not been reflected in spot gas prices in Europe has substantially reduced the potential optimization margin by the end of 2014 and 2015.

64


Table of Contents
LNG sales  

2012

 

2013

 

2014

   
 
 
   

(BCM)

G&P sales   10.5   8.4   8.9
Rest of Europe   7.6   4.6   5.0
Extra European markets   2.9   3.8   3.9
E&P sales   4.1   4.0   4.4
Liquefaction plants:            
- Soyo (Angola)       0.1   0.1
- Bontang (Indonesia)   0.6   0.5   0.5
- Point Fortin (Trinidad & Tobago)   0.5   0.6   0.6
- Bonny (Nigeria)   2.7   2.4   2.8
- Darwin (Australia)   0.3   0.4   0.4
    14.6   12.4   13.3


Electricity sales and power generation

Electricity sales

As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, at industrial sites and on the Italian Stock Exchange for electricity. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and middle to large industrial users, the Company has been developing a commercial offer that provides the combined supply of gas, power and fuels. In 2014, power sales (33.58 TWh) were directed to the free market (74%), the Italian Power Exchange (14%), industrial sites (9%) and others (3%). Compared with 2013, electricity sales were down by 4.2%, due to lower sales to large clients and wholesalers partially offset by higher volumes traded on the Italian Power Exchange.

Power availability  

2012

 

2013

 

2014

   
 
 
   

(TWh)

Power generation sold   23.58   21.38   19.55
Trading of electricity (a)   19.00   13.67   14.03
    42.58   35.05   33.58
Power sales by market            
Free market (a)   31.84   28.73   24.86
Italian Exchange for electricity   6.10   1.96   4.71
Industrial plants   3.30   3.31   3.17
Other (a)   1.34   1.05   0.84
    42.58   35.05   33.58

(a)    Include positive and negative imbalances.

 

Power generation

Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Mantova, Brindisi, Ferrara and Bolgiano. In 2014, power generation was 19.55 TWh, down by 1.83 TWh, or 8.6% from 2013, mainly due to lower production at Ravenna and Brindisi plants due to decreasing demand. As of December 31, 2014, installed operational capacity was 4.9 GW (4.8 GW as of December 31, 2013). Electricity trading reported a slight increase (up 2.6% to 14.03 TWh) due to higher purchases on the spot market.

65


Table of Contents
Site  

Total installed capacity in 2014 (a)
(MW)

 

Technology

 

Fuel

   
 
 
Brindisi   1.3   CCGT   gas
Ferrera Erbognone   1.0   CCGT   gas/syngas
Livorno   0.2   Power station   gas/fuel oil
Mantova   0.9   CCGT   gas
Ravenna   1.0   CCGT   gas
Ferrara (b)   0.8   CCGT   gas
Bolgiano   0.1   Power station   gas
    5.3        

(a)    Capacity available after completion of dismantling of obsolete plants.
(b)    Eni’s share of capacity.

 

Power generation  

2012

 

2013

 

2014

   
 
 
Purchases                
Natural gas   (mmCM)   4,792   4,295   4,074
Other fuels   (ktoe)   462   449   338
- of which steam cracking       98   99   104
Production                
Electricity   (TWh)   23.58   21.38   19.55
Steam   (ktonnes)   12,603   9,907   9,010
Installed generation capacity   (GW)   5.3   4.8   4.9


International transport

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

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

International transport infrastructure

Route  

Lines

 

Total length

 

Diameter

 

Transport capacity (1)

 

Transit capacity (2)

 

Compression stations

   
 
 
 
 
 
   

(units)

 

(km)

 

(inch)

 

(BCM/y)

 

(BCM/y)

 

(No.)

TTPC (Oued Saf Saf-Cap Bon)  

2 lines of km 370

 

740

 

48

 

34.0

 

33.2

 

5

TMPC (Cap Bon-Mazara del Vallo)  

5 lines of km 155

 

775

 

20/26

 

33.5

 

33.5

   
GreenStream (Mellitah-Gela)  

1 line of km 520

 

520

 

32

 

8.0

 

8.0

 

1

Blue Stream (Beregovaya-Samsun)  

2 lines of km 387

 

774

 

24

 

16.0

 

16.0

 

1

   
 
 
 
 
 

(1) i Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(2) i The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

66


Table of Contents

International transport activities

The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 BCM/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.

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

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

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

 

The South Stream project

In December 2014, Eni divested its 20% stake in South Stream Transport BV to Gazprom. The company is engaged in the economic feasibility, procurement and construction of the offshore section of the South Stream pipeline. Pursuant to the shareholders’ agreement, Eni exercised a put option of its stake whereby the Company will recover the capital invested to date in the project, determined in accordance with existing agreements.

 

Capital expenditures

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

 

Refining & Marketing

Eni’s Refining & Marketing segment engages in the supply of crude oil, refining and marketing of refined products, trading and shipping of crude oil and refined products primarily in Italy and in Central-Eastern Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company’s operations are fully integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations.

For the next four years, the priority of our Refining & Marketing segment is to return to profitability in the context of weak fundamentals of the European refining market, affected by weak demand, structural overcapacity and competitive pressure from streams of cheaper products from Asia, Russia and the United States. Eni intends to reduce its exposure to the refining segment and implement a number of restructuring initiatives, as well as cost efficiencies and process optimization. The reduction of refining exposure, up to 50% (base 2012) will be achieved through the reconversion of productive processes and adoption of production cycles based on feedstock derived from agriculture and other renewable sources, as well as initiatives which are designed to restructure or shut down unprofitable production lines. As part of this strategy we shut down the obsolete, gasoline-designed refinery at Venice and started up the production of green diesel and we also signed a framework agreement with Italian Authorities and stakeholders for the restructuring of the loss-making Gela refinery which was shut down and will undergo an upgrading initiative to produce bio-fuels. We also signed a preliminary agreement for the divestment of our interest in a refinery located in the Czech Republic. We believe that those actions will significantly reduce our breakeven in the refining business going forward. The refineries in the Eni circuit are in a better position to face competition and will be further strengthened in order to enhance their flexibility and efficiency. In the marketing segment, the strategy is focused on simplifying the commercial offer, the launch of a new loyalty campaign, the operating efficiency, as well as the reorganization of commercial network and the closure of marginal sale points. The main economic and financial targets of the Refining & Marketing segment are the achievement of the break even level of adjusted operating profit and return to the positive cash flow from 2015.

67


Table of Contents

The matters regarding future plans discussed in this section and elsewhere herein are forward-looking statements that involve risks and uncertainties that could cause the actual results to differ materially from those in such forward looking statements. Such risks and uncertainties include difficulties in obtaining approvals from relevant Antitrust Authorities and developments in the relevant market.

Supply

In 2014, a total of 70.14 mmtonnes of crude were purchased by the Refining & Marketing segment (65.96 mmtonnes in 2013), of which 27.47 mmtonnes from Eni’s Exploration & Production segment, 25.60 mmtonnes on the spot market and 17.07 mmtonnes were purchased under long-term supply contracts with producing countries. The subdivision by geographic area was as follows: approximately 35% of crude purchased in 2014 came from Russia, 18% from West Africa, 11% from the North Sea, 8% from the Middle East, 7% from North Africa, 6% from Italy and 15% from other areas. In 2014, a total of 49.99 mmtonnes of crude purchased were marketed, up by 6.03 mmtonnes or 13.7% from 2013. In addition, 4.94 mmtonnes of intermediate products were purchased (5.31 mmtonnes in 2013) to be used as feedstock in conversion plants and 20.87 mmtonnes of refined products (17.79 mmtonnes in 2013) were purchased to be sold on markets outside Italy (16.13 mmtonnes) and on the Italian market (4.74 mmtonnes) as a complement to available production.

Refining

In 2014, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 30.8 mmtonnes (equal to 617 KBBL/d) and a conversion index of 51%. Conversion index is a measure of refinery complexity. The higher the index, the wider the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies which the Company generally expects to achieve as certain qualities of crude (particularly the heavy ones) may trade at discount with reference to the light crude Brent benchmark. Eni’s five 100% owned refineries have balanced capacity of 20.2 mmtonnes (equal to 404 KBBL/d), with a 54% conversion index. In 2014, Eni’s refineries throughputs in Italy and outside Italy was 25.03 mmtonnes.

The table below sets forth certain statistics regarding Eni’s refineries as of December 31, 2014.

Refining system in 2014

   

Ownership share
(%)

 

Distillation capacity
(total)
(KBBL/d)

 

Distillation capacity
(Eni’s share)
(KBBL/d)

 

Primary balanced refining capacity (1)(Eni’s share)
(KBBL/d)

 

Conversion index
(%)

 

Fluid catalytic cracking - FCC
(KBBL/d)

 

Residue conversion
(KBBL/d)

 

Go-Finer/ Mild Hydro- cracking/
(KBBL/d)

 

Mild Hydro- cracking/ Hydro- cracking
(KBBL/d)

 

Visbreaking/ thermal cracking
(KBBL/d)

 

Coking
(KBBL/d)

 

Distillation capacity utilization rate
(Eni’s share)
(%)

 

Balanced refining capacity utilization rate
(Eni’s share)
(%)

   
 
 
 
 
 
 
 
 
 
 
 
 
Wholly-owned refineries      

449

 

449

 

404

 

54

 

34

 

35

 

0

 

66

 

67

 

0

 

72

 

78

Italy                                                    
     Sannazzaro  

100

 

223

 

223

 

200

 

70

 

34

 

13

     

51

 

29

     

75

 

83

     Gela  

100

                                               
     Taranto  

100

 

120

 

120

 

120

 

56

     

22

     

15

 

38

     

62

 

62

     Livorno  

100

 

106

 

106

 

84