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Table of Contents


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 6-K

REPORT OF FOREIGN ISSUER
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

For the month of May 2013

Eni S.p.A.
(Exact name of Registrant as specified in its charter)

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


     (Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.)

Form 20-F x                    Form 40-F o


     (Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2b under the Securities Exchange Act of 1934.)

Yes o                    No x

     (If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):               )



 

Table of Contents

TABLE OF CONTENTS

 

 

Fact Book 2012

Eni in 2012

Press Release dated May 10, 2013

Ordinary Shareholders’ Meeting Resolutions

Press Release dated May 28, 2013

Press Release dated May 30, 2013

 


Table of Contents

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorised.

         
  Eni S.p.A.
 
 
         
    Name: Antonio Cristodoro   
    Title:   Head of Corporate Secretary's Staff Office   
 

Date: May 31, 2013


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    I

Fact Book 2012

     
 




 
             
    Contents   Eni’s Fact Book is a supplement to Eni’s 2012 Annual Report and is designed to provide supplemental financial and operating information.
It contains certain forward-looking statements in particular under the section "Outlook" regarding capital expenditure, development and management of oil and gas resources, dividends, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sale growth, new markets, and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document.
 
         
    4 Eni in 2012  
    5 Eni’s strategy  
    10 Eni business model  
    14 Exploration & Production  
    42 Gas & Power  
    51 Refining & Marketing  
    61 Chemicals  
    65 Engineering & Construction  
         
         
    Tables  
         
    71 Financial Data  
    85 Employees  
    86 Supplemental oil and gas information  
    105 Quarterly information

I

 

 

 


Contents

Eni Fact Book Eni

Eni is an integrated company engaged in the energy chain.
Eni’s strong presence in the gas market, our operations in LNG, our skills in the power generation and refinery activities, strengthened by world class skills in engineering and project management, allow us to catch opportunities in the market and to realize integrated projects.
In 2012 adjusted net profit was euro 7.13 billion, up by 2.7% from a year ago. It was up by 7.6% when excluding Snam’s results included in the continuing operations1. These results were driven by an excellent performance reported by the Exploration & Production Division on the back of a recovery in Libyan production.
Net cash generated by operating activities from continuing operations amounted to euro 12.36 billion and together with the robust proceeds from divestments enabled the Company to finance capital expenditure and other investments of euro 13.33 billion and to pay dividends to Eni’s shareholders and other minorities for euro 4.38 billion, while reducing net borrowings by euro 12.52 billion. Leverage decreased to 0.25 at December 31, 2012 from 0.46 at December 31, 2011.
The Board of Directors proposed to the Shareholders’ Meeting the distribution of a dividend of euro 1.08 per share representing a 4% increase from 2011.
In 2012, Eni continued its commitment in incident prevention also by means of training programs on safety and emergency prevention. For the seventh consecutive year the injury frequency rate relating to employees and contractors decreased by 12.3% and 21.1% respectively, compared to 2011.
In 2012, the Exploration & Production Division reported adjusted net profit amounting to euro 7.43 billion (up 8.2% from 2011) driven by improved operating performance. Oil and natural gas production for the full year was 1,701 kboe/day (up 7% from 2011) sustained by the recovery of activities in Libya,
  the start-up/ramp-up of fields, particularly in Russia and Australia, and higher production in Iraq. Net proved reserves at December 31, 2012 was an eight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. The organic reserves replacement ratio was 147% with a reserves life index of 11.5 years (12.3 years in 2011). All sources reserves replacement ratio was 107%.
The Gas & Power Division reported adjusted net profit of euro 473 million, almost doubled from 2011 due to the benefits associated with the renegotiations of the supply contracts and the full recovery of Libyan supplies. Worldwide gas sales, net of Galp sales, maintained their levels supported by a strong presence in the Italian residential market and presence in strategic European markets of France and Germany/Austria in addition to increasing international sales of LNG.
In a scenario weighted down by a steep fall in fuel demand in Italy, the Refining & Marketing Division managed to reduce adjusted operating loss by euro 85 million from 2011 (down euro 179 million). This result reflects the better operating performances and improved efficiency and performance of refineries. Results posted by the Marketing activity were impacted by falling demand for fuel, high competitive pressure and increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends. The average market share in Italy was 31.2%, up 0.7 percentage points from 2011.
The Engineering & Construction sector reported adjusted net profit amounting to euro 1,109 million reflecting the robust operating performance recorded mainly in the Drilling businesses, while the Engineering & Construction business reported a decline.
The Chemical sector reported a significant increase in adjusted net loss (euro 395 million, down euro 189 million) from 2011, due to a weak trend in demand for commodities reflecting the economic downturn and a fall in unit margins.

(1) The Snam contribution excluded is the result of Snam transactions with Eni included in the continuing operations according to IFRS 5. Adjusted operating profit and adjusted net profit are not provided by IFRS.

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Eni Fact Book Eni

The energy market has become even more challenging on the back of the uncertainty of the macro-economic scenario, mainly in Europe, recent trends in demand even more hinged on emerging Countries and discoveries of high potential basins for hydrocarbon production.
Against this backdrop, Eni’s strategy for the 2013-2016 four-year period confirms the priorities of profitably growing oil and gas production, recovering profitability in the downstream gas sector, improving efficiency in the downstream oil and in the chemical sector.
Eni believes that a sustainable business conduct contributes to both the achievement of industrial performance, and the mitigation of political, financial and operational risks. This strengthens Eni’s role as a trustworthy and reliable partner, who is ready to capture new opportunities in the marketplace and able to manage the complexities of the environment.

Following the divestment of Snam and other portfolio operations, Eni has strengthened its financial structure reaching a leverage of 0.25. Net cash generated by operating activities and portfolio management will enable Eni to finance the planned relevant capital expenditure to fuel long-term growth (euro 56.8 billion) and to remunerate Eni’s shareholders.
Management is targeting a net debt to equity ratio in the 0.1-0.3 range by the end of the plan period even in case of fluctuations and volatility of Brent prices in the scenario and results of our businesses.


Business strategies and targets

In Exploration & Production, Eni confirms its strategy of organic growth focused on exploration and reserve replacement as major drivers for value creation. Growth will be fuelled by new production

  additions in Eni’s core areas (North and Sub-Saharan Africa, Venezuela, Barents Sea, Yamal Peninsula, Kazakhstan, Iraq and the Far East) leveraging Eni’s vast knowledge of reservoirs and geological basins, technical and producing synergies, as well as established partnerships with producing Countries.
Average production growth is expected at a rate of more than 4% in the 2013-2016 period, supported by the development of core areas (Sub-Saharan Africa, and in particular Mozambique, Venezuela, Barents Sea, Yamal Peninsula in Russia, Kazakhstan, Iraq and Indonesia).
Growth will be associated to increased profitability and risk management reducing time to market (more than 90% of the discoveries made in 2008-2012 will reach production within 8 years from their discovery) and retaining large volumes of operated production, in order to directly manage schedules and budget costs of development projects. Technological innovation and the application of proprietary technologies will allow to reach cost efficiency and acquire key competences for supporting increasing production and recovery rates, developing drilling techniques to be applied in complex environments, marginal areas and deep and ultra-deep waters.
This growth strategy will be supported by the mitigation of operational, political, Country and environmental risks.

Eni confirms its commitment to improving the safety of employees and contractors, strengthening the tools for management, training and control, and ensuring asset integrity and process security. Environmental impact targets include the containment of accidental oil spills from 2.9 boe/mmboe to 2.4 boe/mmboe by 2016, an over 30% reduction in GHG emission rates in the E&P segment for each thousand of toe of gross operated production by 2015 as compared to 2010 deploying flaring down policies especially in Africa and energy efficiency programs. Projects for production water reinjection will lead to a rate of reinjection of 65% of total water produced by 2016.

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Eni Fact Book Eni

In the Gas & Power Division, Eni intends to recover profitability leveraging on (i) a competitive and flexible cost position thanks to contract renegotiation; (ii) an expansion in gas sales in Italy through its sales force, diversified offer of innovative products and best-in-class services, mainly to the retail segment; (iii) a selective development in activities outside Italy, focusing on more profitable segments and increasing LNG sales in profitable markets outside Europe.
In the 2013-2016 period Eni intends to preserve its market share in Italy and abroad taking account of the expected increase in supply and logistics costs implementing efficient marketing initiatives.

Management intends to reach a greater integration of trading and commodity price risk management with the supply activities and the non-retail commercial sales of gas and LNG to fully centralize and optimize Eni’s commodity risk exposure in markets characterized by more and more evolved counterparties.

In Refining & Marketing, Eni expects to gradually recover profitability throughout the plan period leveraging on optimization of industrial plants and of logistics operations by means of higher flexibility, process integration and efficiency; selective investments targeting to upgrade conversion capacity and asset integrity; the conversion of the Venice plant into a "bio-refinery" to produce bio-fuels; cost reduction programs.
In Marketing operations management plans to strengthen Eni’s leadership in the Italian retail market leveraging on opportunities deriving from the liberalization process (i.e. closing stations with low throughput, boosting full "iperself" mode and development of non-oil activities).
Building on these initiatives, in the 2013-2016 four-year period, Eni expects; (i) to increase its adjusted EBIT under constant scenario assumptions (base 2012) by euro 0.4 billion by 2016 (in line with the previous Plan’s targets); (ii) to maintain its retail market share in Italy.

  In Chemical segment Eni confirms its strategy of progressively reducing the exposure to loss-making commodity chemicals while at the same time developing innovative and niche productions which are expected to yield better returns such as elastomers and the expansion of the specialties segment. Eni intends to grow the green-chemistry business leveraging on the ongoing project of converting its Porto Torres site in a modern plant for the manufacture of eco-compatible chemical products.
The recent strategic alliances in Asia, supported by our technological know-how and the enhancement of Eni’s proprietary technology platform confirm a greater internationalization of our business, projecting it towards markets characterized by high-growth demand rates.

In the Engineering & Construction segment, Eni confirms its target of consolidating the global competitive position achieved in the offshore and onshore businesses and its role as high-quality niche player in the deepwater drilling business. Saipem will leverage on the enhancement of the EPC(I)-oriented business model, its world-class technology, engineering and delivering skills, its strong local presence and established relationships with oil Majors and National Oil Companies.
In this light the company targets to strengthen its construction ability particularly in large highly-complex projects, in harsh environments, keeping a selective commercial approach. Our focus on local content in strategic areas will contribute to the monetization of achieved competitive advantages.

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Eni Fact Book Eni

Main data

   Key financial data (a)
   (euro million)

 

2003 (*)

   

2004

   

2005

   

2006

   

2007

   

2008

   

2009

   

2010

   

2011

   

2012

 
                                                               
Net sales from operations   51,487     57,498     73,692     86,071     87,204     108,082     83,227     98,523     109,589     128,592  
of which: continuing operations                                 106,978     81,932     96,617     107,690     127,220  
Group operating profit   9,517     12,399     16,664     19,336     18,739     18,517     12,055     16,111     17,435     15,914  
  Special items         (448 )   (1,210 )   88     (620 )   2,034     1,295     2,290     1,567     4,795  
  Profit (loss) on stock         631     1,942     1,059     885     936     (345 )   (881 )   (1,113 )   (17 )
Group adjusted operating profit   9,958     12,582     17,396     20,483     19,004     21,487     13,005     17,520     17,889     20,692  
Adjusted operating profit - continuing operations                                 21,322     12,722     16,845     17,230     19,753  
  Exploration & Production   5,973     8,202     12,649     15,521     13,770     17,166     9,489     13,898     16,075     18,518  
  Gas & Power   3,661     3,448     3,783     4,117     4,414     1,778     2,022     1,268     (247 )   354  
  Refining & Marketing   584     923     1,210     794     292     555     (381 )   (181 )   (539 )   (328 )
  Chemicals   (54 )   263     261     219     116     (382 )   (441 )   (96 )   (273 )   (485 )
  Engineering & Construction   311     215     314     508     840     1,041     1,120     1,326     1,443     1,465  
  Other activities   (236 )   (223 )   (296 )   (299 )   (207 )   (244 )   (258 )   (205 )   (226 )   (224 )
  Corporate and financial companies   (281 )   (187 )   (384 )   (244 )   (195 )   (282 )   (342 )   (265 )   (266 )   (329 )
  Impact of unrealized intragroup profit elimination and consolidation adjustments         (59 )   (141 )   (133 )   (26 )   1,690     1,513     1,100     1,263     782  
Adjusted operating profit - discontinued operations                                 165     283     675     659     939  
































Group net profit   5,585     7,059     8,788     9,217     10,011     8,825     4,367     6,318     6,860     7,788  
  of which: continuing operations                                 8,996     4,488     6,252     6,902     4,198  
  of which: discontinued operations                                 (171 )   (121 )   66     (42 )   3,590  
































Group adjusted net profit   5,096     6,645     9,251     10,401     9,569     10,164     5,207     6,869     6,969     7,323  
  of which: continuing operations                                 10,315     5,321     6,770     6,938     7,128  
  of which: discontinued operations                                 (151 )   (114 )   99     31     195  
































Net cash provided by operating activities   10,827     12,500     14,936     17,001     15,517     21,801     11,136     14,694     14,382     12,371  
  of which: continuing operations                                 21,506     10,755     14,140     13,763     12,356  
  of which: discontinued operations                                 295     381     554     619     15  
Capital expenditure   8,802     7,499     7,414     7,833     10,593     14,562     13,695     13,870     13,438     13,517  
  of which: continuing operations                                 12,935     12,216     12,450     11,909     12,761  
  of which: discontinued operations                                 1,627     1,479     1,420     1,529     756  
































Shareholders’ equity including non-controlling interest   28,318     35,540     39,217     41,199     42,867     48,510     50,051     55,728     60,393     62,713  
Net borrowings   13,543     10,443     10,475     6,767     16,327     18,376     23,055     26,119     28,032     15,511  
Leverage   0.48     0.29     0.27     0.16     0.38     0.38     0.46     0.47     0.46     0.25  
Net capital employed   41,861     45,983     49,692     47,966     59,194     66,886     73,106     81,847     88,425     78,224  
  Exploration & Production   17,340     16,770     19,109     17,783     23,826     31,362     32,455     37,646     42,024     42,445  
  Gas & Power   15,617     19,554     20,075     19,713     21,333     9,636     11,024     12,931     12,367     11,135  
  Snam                                 11,918     13,730     14,415     15,393        
  Refining & Marketing   5,089     5,081    

5,993

    5,631     7,675     7,379     8,105     8,321     9,188     8,876  
  Chemicals   1,821     2,076     2,018     1,953     2,228     1,915     1,774     1,978     2,252     2,569  
  Engineering & Construction   2,119     2,403     2,844     3,399     4,313     5,022     6,566     7,610     8,217     10,020  
  Corporate financial companies and other activities   (125 )   277     2     (95 )   294     24     (192 )   (527 )   (393 )   3,682  
  Impact of unrealized intragroup profit elimination         (178 )   (349 )   (418 )   (475 )   (370 )   (356 )   (527 )   (623 )   (503 )
































(*) Financial data for 2003 were prepared in accordance to Italian Gaap.
(a) Following the divestment of Regulated Businesses in Italy, results of Snam have been accounted as "discontinued operations". Results for the 2008-2011 period have been restated accordingly.

   Key market indicators

 

2003

 

2004

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

                                             
Average price of Brent dated crude oil (a)       28.84   38.22   54.38   65.14   72.52   96.99   61.51   79.47   111.27   111.58
Average EUR/USD exchange rate (b)       1.131   1.244   1.244   1.256   1.371   1.471   1.393   1.327   1.392   1.285
Average price in euro of Brent dated crude oil       25.50   30.72   43.71   51.86   52.90   65.93   44.16   59.89   79.94   86.83
Average European refining margin (c)       2.65   4.35   5.78   3.79   4.52   6.49   3.13   2.66   2.06   4.83
Average European refining margin Brent/Ural (c)       3.40   7.03   8.33   6.50   6.45   8.85   3.56   3.47   2.90   4.94
Euribor - three-month euro rate   (%)   2.3   2.1   2.2   3.1   4.3   4.6   1.2   0.8   1.4   0.6























(a) In US dollars per barrel. Source: Platt’s Oilgram.
(b) Source: ECB.
(c) In US dollars per barrel FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data.

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Eni Fact Book Eni
  

   Selected operating data

 

2003

 

2004

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

Corporate (a)                                            
Employees at period end   (number)   76,529   71,572   71,773   72,850   75,125   71,714   71,461   73,768   72,574   77,838
of which: - women       11,155   10,326   10,620   10,841   10,977   11,611   11,955   12,161   12,542   12,860
of which: - outside Italy       36,678   32,691   34,036   35,818   38,634   41,971   42,633   45,967   45,516   51,034
Female managers   (%)   10.9   12.5   12.4   13.5   14.1   16.3   17.3   18.0   18.5   18.9
Employee injury frequency rate   (number of injuries/million of worked hours)   3.79   3.99   2.74   2.45   1.93   1.22   0.84   0.80   0.65   0.57
Contractor injury frequency rate       4.12   7.84   2.59   1.54   1.45   1.09   0.97   0.71   0.57   0.45
Fatality index   (fatal injuries per one hundred million of worked hours)   5.51   5.64   3.38   2.31   2.97   2.75   1.20   4.77   1.94   1.10
Oil spills   (barrels)   857   7,813   6,908   6,151   6,731   4,749   6,259   4,269   7,295   3,856
Oil spills due to sabotage and terrorism       n.a.   n.a.   1,810   7,014   2,608   2,286   15,288   18,695   7,657   8,384
GHG emission   (mmtonnes CO2 eq)   52.27   58.34   61.85   60.72   67.25   59.59   55.49   58.26   49.12   52.49
R&D expenditures (b)   (euro million)   238   257   204   222   208   211   233   218   190   211























Exploration & Production                                            
Proved reserves of hydrocarbons at period end   (mmboe)   7,272   7,218   6,837   6,436   6,370   6,600   6,571   6,843   7,086   7,166
Reserve life index   (years)   12.7   12.1   10.8   10.0   10.0   10.0   10.2   10.3   12.3   11.5
Hydrocarbons production (c)   (kboe/d)   1,562   1,624   1,737   1,770   1,736   1,797   1,769   1,815   1,581   1,701























Gas & Power                                            
Sales of consolidated companies (including own consumption)   (bcm)   71.39   76.49   82.62   85.76   84.83   89.32   89.60   82.00   84.37   84.67
Sales of Eni’s affiliates (Eni’s share)       6.94   5.84   7.08   7.65   8.74   8.91   7.95   9.41   9.53   7.92
Total sales and own consumption (G&P)       78.33   82.33   89.70   93.41   93.57   98.23   97.55   91.41   93.90   92.59
E&P gas sales (c)           4.70   4.51   4.69   5.39   6.00   6.17   5.65   2.86   2.73
Worldwide gas sales       78.33   87.03   94.21   98.10   98.96   104.23   103.72   97.06   96.76   95.32
Electricity sold   (TWh)   8.65   16.95   27.56   31.03   33.19   29.93   33.96   39.54   40.28   42.58























Refining & Marketing                                            
Throughputs on own account   (mmtonnes)   35.43   37.69   38.79   38.04   37.15   35.84   34.55   34.80   31.96   30.01
Balanced capacity of wholly-owned refineries at period end   (kbbl/d)   504   504   524   534   544   737   747   757   767   767
Sales of refined products   (mmtonnes)   50.43   53.54   51.63   51.13   50.15   49.16   45.59   46.80   45.02   48.33
Retail sales in Europe   (mmtonnes)   14.01   14.40   12.42   12.48   12.65   12.03   12.02   11.73   11.37   10.87
Service stations at year end   (number)   10,647   9,140   6,282   6,294   6,440   5,956   5,986   6,167   6,287   6,384
Average throughput per service station   (kliters/y)   1,771   1,970   2,479   2,470   2,486   2,502   2,477   2,353   2,206   2,064























Chemicals                                            
Production   (ktonnes)   6,907   7,118   7,282   7,072   8,795   7,372   6,521   7,220   6,245   6,090
of which: - Intermediates       4,014   4,236   4,450   4,275   5,688   5,110   4,350   4,860   4,101   4,112
of which: - Polymers       2,893   2,882   2,832   2,797   3,107   2,262   2,171   2,360   2,144   1,978
Average plant utilization rate   (%)   71.3   75.2   78.4   76.4   80.6   68.6   65.4   72.9   65.3   66.7























Engineering & Construction                                            
Orders acquired   (euro million)   5,876   5,784   8,395   11,172   11,845   13,860   9,917   12,935   12,505   13,391
Order backlog at year end       9,405   8,521   10,122   13,191   15,390   19,105   18,370   20,505   20,417   19,739























(a) Following the divestment of Regulated Businesses in Italy, data for the year 2012 do not include Snam contribution. Results for the 2008-2011 period have been restated accordingly.
(b) Net of general and administrative costs.
(c) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,490 standard cubic feet of gas per barrel of oil equivalent. The effect of this update on production expressed in boe was 9 kboe/d for the full-year 2012 and on the initial reserves balance as of January 1, 2011, amounted to 40 mmboe. Other per-boe indicators were only marginally affected by the update (e.g. realization prices, costs per boe) and also negligible was the impact on depletion charges. Other oil companies use different conversion rates.
  

   Share data

 

2003

 

2004

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

Net profit (a) (b)   (euro)   1.48   1.87   2.34   2.49   2.73   2.43   1.21   1.74   1.89   2.15
Net profit - continuing operations (a) (b) (*)                           2.47   1.24   1.72   1.90   1.16
Dividend       0.75   0.90   1.10   1.25   1.30   1.30   1.00   1.00   1.04   1.08
Dividend pertaining to the year (c)   (euro million)   2,828   3,384   4,086   4,594   4,750   4,714   3,622   3,622   3,695   3,840
Cash flow   (euro)   2.87   3.31   3.97   4.59   4.23   5.99   3.07   4.06   3.97   3.41
Dividend yield (d)   (%)   5.1   4.9   4.7   5.0   5.3   7.6   5.8   6.1   6.6   5.9
Net profit per ADR (e)   (US$)   3.72   4.66   5.81   6.26   7.49   7.27   3.45   4.59   5.29   2.98
Dividend per ADR (e)       1.83   2.17   2.74   3.14   3.56   3.82   2.79   2.65   2.90   2.78
Cash flow per ADR (e)       7.22   8.96   9.40   11.53   11.60   17.63   8.56   10.77   11.05   8.78
Dividend yield per ADR (d)   (%)   5.0   5.0   4.7   5.0   5.3   7.6   5.8   6.1   6.6   5.8
Pay-out       51   48   46   50   47   53   81   57   55   50
Number of shares at period end representing share capital   (million shares)   4,002.9   4,004.4   4,005.4   4,005.4   4,005.4   4,005.4   4,005.4   4,005.4   4,005.4   3,634.2
Average number of share outstanding in the year (f) (fully diluted)       3,778.4   3,771.7   3,763.4   3,701.3   3,669.2   3,638.9   3,622.4   3,622.5   3,622.7   3,622.8
TSR   (%)   4.3   28.5   35.3   14.8   3.2   (29.1 ) 13.7   (2.2 ) 5.1   22.0























(*) Following the divestment of Regulated Businesses in Italy, results of Snam have been accounted for as "discontinued operations", based on IFRS 5. Results for the 2008-2011 period have been restated accordingly. Net profit refers to results of continuing operations as reported in Eni consolidated annual report.
(a) Calculated on the average number of Eni shares outstanding during the year.
(b) Pertaining to Eni’s shareholders.
(c) Amounts due on the payment of the balance of 2012 dividend are estimated.
(d) Ratio between dividend of the year and average share price in December.
(e) One ADR represents 2 shares. Net profit, dividends and cash flow data were converted using average exchange rates. Dividends data were converted at the Noon Buying Rate of the pay-out date.
(f) Calculated by excluding own shares in portfolio.

- 8 -


Contents

Eni Fact Book Eni

   Share information

 

2003

 

2004

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

                                             
Share price - Milan Stock Exchange                                            
High   (euro)   15.75   18.75   24.96   25.73   28.33   26.93   18.35   18.56   18.42   18.70
Low       11.88   14.72   17.93   21.82   22.76   13.80   12.30   14.61   12.17   15.25
Average       13.64   16.94   21.60   23.83   25.10   21.43   16.59   16.39   15.95   17.18
End of the period       14.96   18.42   23.43   25.48   25.05   16.74   17.80   16.34   16.01   18.34























ADR price (a) - New York Stock Exchange                                            
High   (US$)   94.98   126.45   151.35   67.69   78.29   84.14   54.45   53.89   53.74   49.44
Low       66.15   92.35   118.50   54.65   60.22   37.22   31.07   35.37   32.98   36.85
Average       77.44   105.60   134.02   59.97   68.80   63.38   46.36   43.56   44.41   44.24
End of the period       94.98   125.84   139.46   67.28   72.43   47.82   50.61   43.74   41.27   49.14























Average daily exchanged shares   (million shares)   22.0   20.0   28.5   26.2   30.5   28.7   27.9   20.7   22.9   15.6
Value   (euro million)   298.5   338.7   620.7   619.1   773.1   610.4   461.6   336.0   355.0   267.0
Number of shares outstanding at period end (b)   (million shares)   3,772.3   3,770.0   3,727.3   3,680.4   3,656.8   3,622.4   3,622.4   3,622.7   3,622.7   3,622.8
Market capitalization (c)                                            
EUR   (billion)   56.4   69.4   87.3   93.8   91.6   60.6   64.5   59.2   58.0   66.4
USD       71.1   94.9   104.0   123.8   132.4   86.6   91.7   79.2   75.0   87.7























(a) Effective January 10, 2006 a 5:2 stock split was made. Previous period’s prices have not been restated.
(b) Excluding treasury shares.
(c) Number of outstanding shares by reference price at period end.

   Data on Eni share placement

 

1995

 

1996

 

1997

 

1998

 

2001

                         
Offer price  

(euro/share)

 

5.42

 

7.40

 

9.90

 

11.80

 

13.60

Number of share placed  

(million shares)

 

601.9

 

647.5

 

728.4

 

608.1

 

200.1

  of which: through bonus share          

1.9

 

15.0

 

24.4

 

39.6

Percentage of share capital (a)  

(%)

 

15.0

 

16.2

 

18.2

 

15.2

 

5.0

Proceeds  

(euro million)

 

3,254

 

4,596

 

6,869

 

6,714

 

2,721














(a) Refers to share capital at December 31, 2012.

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Contents

Eni Fact Book Eni business model

Eni’s excellent market position and competitive advantages derive from the Company’s strategic decision-making which is consistent with the long-term nature of the business, and relies on a sustainable business model fonde on a consolidated and distinctive way of doing business, in a frame work of clear and straightforward rules of corporate governance and respectful of the highest ethical standards and rigorous risk management.
Eni’s strategies, decisions in terms of resource allocation and day-by-day operations underpin sustainable value creation to shareholders and, more generally, all of our stakeholders: the host communities where we work through our contribution to socio-economic standards improvement and responsibly using resources; our people to whom we dedicate our best efforts to preserve health and safety of the workplace and to enhance each individual’s contribution and diversity; our suppliers, partners and public administrations with whom we interact by running our
  operations in a transparent manner, respecting human rights and tackling with corruption; finally our clients to whom we offer competitive and up with the times commercial choices and high quality services.

In 2012 Eni laid the foundations for a new growth phase of its oil and gas production tank to numerous exploration successes, the entry in new Countries and the management of activities in well established Countries of activity.

These results are based on the great attention paid to the specific features of the Countries where Eni operates and thus on cooperation for their development. Starting from an assessment of their potential Eni promotes partnerships providing local people new opportunities for growth and development. This is a competitive lever in the Countries where Eni’s experience is more recent but

- 10 -


Contents

Eni Fact Book Eni business model

also in more established areas. In each one of them our objective is to create high quality jobs targeted at local resources on an equal opportunity basis. The culture of plurality is a distinctive feature of Eni’s strongly internationally oriented business model.

The inclusion of all Eni people with their diversity merges with the protection of health and safety on the workplace, with the professional development and engagement in the company’s objectives. Eni guarantees equal treatment to its entire people defining worldwide remuneration policies and committing itself and its suppliers to the respect of the basic workers’ rights in all the Countries of operation.

Responsibility is assumed as commitment to transparency and anticorruption practices while respecting human rights in all areas and promoting the development of Countries and their society. In deploying its activities, Eni activates a flow of resources that can prove crucial for economic growth. Only a strict discipline of integrity and promotion of transparency, in particular as concerns payments to producing Countries can protect from corruption and build the basis for a proper use of these resources aimed at sustainable development.

The ultimate aim of sustainable growth is upheld by Eni through a way of operating based on operating excellence that leverages on best practices, quality systems, advanced and high quality technologies to guarantee full respect of communities and their environment. A safe management of plants and the mitigation of risks represent a prerequisite for a proper environmental management and for the reduction of environmental impacts.

  The exploration of frontier areas and territories that are considered difficult and environmentally sensitive are the result not only of Eni’s drive to development while applying new technologies but also of a responsible and sustainable corporate strategy.

Eni’s presence worldwide in the most sensitive areas was made possible by technological innovation and the application of advanced methodologies that allow work also in harsh contexts guaranteeing the protection of the environments and the conservation of sensitive ecosystems and biodiversity.

Lastly, as an integrated energy company, Eni works alongside governments of producing Countries in planning and designing solutions for the development of local energy systems, cooperating with national companies in the development of energy sources and building infrastructure for their use and monetization. One of the main actions performed concerns the fight against energy poverty in particular in Sub-Saharan Africa with the support of the development of local technologies and the reduction of waste where infrastructure already exist.
Eni’s commitment to energy for all has been renewed in 2012 in the UN Conference on sustainable development Rio+20.
In Europe, in particular in Italy, Eni is committed to respond to the new industrial challenges by working on higher value added products and a widening and differentiation of its range of products. Eni has in fact started a new path of evolution and relaunch of its chemical and refining activities directing its focus on the so called green chemistry and bio-refining.

 

   Safety

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Injury frequency rate  

(number of injuries/million of worked hours)

 

1.14

 

0.92

 

0.75

 

0.60

 

0.49

- employees      

1.22

 

0.84

 

0.80

 

0.65

 

0.57

- contractors      

1.09

 

0.97

 

0.71

 

0.57

 

0.45

Fatality index  

(fatal injuries/one hundred million of worked hours)

 

2.75

 

1.20

 

4.77

 

1.94

 

1.10

- employees      

2.55

 

0.89

 

6.66

 

1.19

 

0.87

- contractors      

2.85

 

1.40

 

3.55

 

2.38

 

1.23

Safety expenditure and investments  

(euro thousand)

 

407,930

 

487,660

 

260,434

 

320,117

 

370,559

Professional illnesses reported  

(number)

 

82

 

123

 

184

 

135

 

71

Health and hygiene expenditure and investments  

(euro thousand)

 

66,601

 

78,219

 

55,070

 

78,950

 

48,156














 

   Spending for the territory

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Total spending for the territory      

85.9

 

97.7

 

107.2

 

100.9

 

90.6

- of which project investments      

69.4

 

70.4

 

75.4

 

69.3

 

63.1

- of which short-term investments and donations      

0.5

 

0.9

 

4.4

 

0.9

 

3.4

- of which association memberships fees      

1.5

 

1.5

 

1.6

 

1.6

 

1.8

- of which contributions to the Eni Foundation      

-

 

5.0

 

5.0

 

3.0

 

-

- of which sponsorships for the territory      

11.4

 

16.2

 

17.1

 

22.4

 

18.6

- of which contributions to the Eni Enrico Mattei Foundation      

3.2

 

3.7

 

3.7

 

3.7

 

3.7














- 11 -


Contents

Eni Fact Book Eni business model

   Employment

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Employees as of December 31  

(number)

 

71,714

 

71,461

 

73,768

 

72,574

 

77,838

- men      

60,103

 

59,506

 

61,607

 

60,032

 

64,978

- women      

11,611

 

11,955

 

12,161

 

12,542

 

12,860

Employees abroad by type      

41,971

 

42,633

 

45,967

 

45,516

 

51,034

- locals      

33,233

 

33,483

 

35,835

 

34,801

 

39,668

- Italian expatriates      

2,769

 

2,771

 

3,123

 

3,208

 

3,867

- International expatriates (including TCN)      

5,969

 

6,379

 

7,009

 

7,507

 

7,499

Senior Managers employed      

1,471

 

1,437

 

1,454

 

1,468

 

1,474

- of which women      

129

 

141

 

147

 

152

 

159

Managers/Supervisors employed      

12,058

 

12,395

 

12,837

 

12,754

 

13,199

- of which women      

2,075

 

2,258

 

2,421

 

2,477

 

2,615

Employees      

33,483

 

33,931

 

34,599

 

36,019

 

38,497

- of which women      

9,063

 

9,171

 

9,040

 

9,394

 

9,777

Workers employed      

24,702

 

23,698

 

24,878

 

22,333

 

24,668

- of which women      

344

 

385

 

553

 

519

 

309

Local employees abroad by professional category      

33,233

 

33,483

 

35,835

 

34,801

 

39,668

- of which senior managers      

245

 

224

 

228

 

228

 

223

- of which managers/supervisors      

2,900

 

3,138

 

3,461

 

3,476

 

3,798

- of which employees      

14,864

 

15,533

 

16,269

 

17,529

 

19,683

- of which workers      

15,224

 

14,588

 

15,877

 

13,568

 

15,964

Training hours  

(thousand hours)

 

2,888

 

2,930

 

2,949

 

3,127

 

3,132














 

   Procurement by geographical area 2012       Africa   Americas   Asia   Italy   Rest of Europe   Oceania
                             
Number of suppliers used   (number)   6,920   4,541   4,436   11,092   8,573   428
Total procurement   (euro million)   7,099   2,463   5,542   12,328   3,635   745
- in goods   (%)   11.7   29.1   11.9   20.0   17.3   18.9
- in works       7.3   21.1   55.5   16.3   21.8   15.4
- in services       49.5   44.3   28.8   56.0   48.7   56.1
- of which unidentifiable       31.5   5.5   3.8   7.7   12.2   9.6















 

   Local procurement 2012 by Country  
   
% procurement on local market Countries


0 - 25% Algeria, Croatia, Iraq, Libya, Luxembourg, Peru, Poland, Portugal, Spain, Venezuela.
25 - 50% Angola, France, Germany, Ghana, Iran, Kazakhstan, Switzerland.
50 - 75% Australia, Brazil, Ecuador, Egypt, Gabon, Norway, Pakistan, Republic of Congo, Saudi Arabia, Tunisia, United Kingdom.
75 - 100% Argentina, Canada, Hungary, India, Indonesia, Italy, Mexico, Netherlands, Nigeria, Romania, Russia, Singapore, United States.


 

   Relations with suppliers

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Procurement by macro-class  

(euro million)

 

28,375

 

33,084

 

31,187

 

32,586

 

31,811

Supplier concentration top 20  

(%)

 

23

 

24

 

18

 

20

 

15

Suppliers used  

(number)

 

27,956

 

33,447

 

32,601

 

31,878

 

32,621

Qualification cycles carried out during the year      

15,466

 

21,066

 

32,962

 

26,936

 

31,991

Suppliers subjected to qualification procedures including screening on human rights      

5,772

 

7,798

 

10,096

 

11,471

 

12,471

% procurement from suppliers subjected to qualification procedures including screening on human rights   (%)  

88

 

87

 

85

 

90

 

88














- 12 -


Contents

Eni Fact Book Eni business model

   Relations with customers

   

2008

 

2009

 

2010

 

2011

 

2012

                         
R&M Customer satisfaction                        
Customer satisfaction index  

(likert scale)

 

8.14

 

7.93

 

7.84

 

7.74

 

7.90

Clients involved in the survey  

(number)

 

22,609

 

10,711

 

30,618

 

30,524

 

30,438

G&P Customer satisfaction                        
Customer satisfaction index  

(%)

 

75.3

 

83.7

 

87.4

 

88.6

 

89.8 (b)

Average Panel (G&P) (a)      

84.9

 

87.0

 

87.4

 

90.8

 

90.6














(a) Referred to companies representing more than 50% of the gas market and totaling over 50,000 clients.
(b) 2012 figure is calculated as the average of the CSS detected by the AEEG in the first half of 2012 and the result detected by the Eni satisfaction survey in the second half of 2012.

   Technological innovation

   

2008

 

2009

 

2010

 

2011

 

2012

                         
R&D expenditure  

(euro million)

 

338

 

287

 

275

 

246

 

263

- R&D expenditure net of general and administrative costs      

211

 

233

 

218

 

190

 

211

Tangible value generated by R&D activities (a)      

n.a.

 

362

 

540

 

730

 

1,006

Personnel employed in R&D activities (full time equivalent)  

(number)

 

1,123

 

1,019

 

1,019

 

925

 

975

Existing patents      

8,040

 

7,751

 

7,998

 

8,884

 

8,931














(a) Figures refer to E&P, R&M and Versalis activities and had been measured since 2009, when the measurement process started.

   Operating efficiency

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Direct GHG emissions  

(tonnes CO2 eq)

 

59,589,334

 

55,494,551

 

58,259,157

 

49,121,224

 

52,493,340

- of which CO2 from combustion and process  

(tonnes)

 

36,475,270

 

35,788,121

 

37,948,625

 

35,319,845

 

36,365,220

- of which CO2 equivalents from flaring  

(tonnes CO2 eq)

 

16,535,835

 

13,839,353

 

13,834,988

 

9,553,894

 

9,461,518

- of which CO2 equivalents from CH4 (methane)      

4,187,532

 

3,684,874

 

4,135,523

 

3,214,469

 

4,470,307

- of which CO2 equivalents from venting      

2,390,697

 

2,182,202

 

2,340,021

 

1,033,017

 

2,196,295

CO2 eq emissions/100% net operated hydrocarbon production  

(tons CO2 eq/toe)

 

0.254

 

0.235

 

0.235

 

0.206

 

0.225

CO2 eq emissions/kWh eq (EniPower)  

(kg CO2 eq/kWh eq)

 

0.402

 

0.410

 

0.407

 

0.410

 

0.399

CO2 eq emissions/uEDC (R&M)  

(tonnes CO2 eq/kbbl/SD)

 

1,297

 

1,240

 

1,284

 

1,229

 

1,141

NOx (nitrogen oxide) emissions  

(tonnes NO2 eq)

 

112,328

 

110,910

 

106,040

 

97,114

 

115,571

SOx (sulphur oxide) emissions  

(tonnes SO2 eq)

 

47,160

 

45,985

 

50,085

 

37,943

 

30,137

NMVOC (Non-Methane Volatile Organic Compounds) emissions  

(tonnes)

 

80,856

 

75,318

 

68,490

 

46,228

 

48,702

TSP (Total Suspended Particulate) emissions      

4,195

 

3,936

 

3,783

 

3,297

 

3,548

Energy used/net 100% operated hydrocarbon production  

(GJ/toe)

 

1.418

 

1.676

 

1.855

 

1.958

 

2.049

Total water withdrawals  

(mmcm)

 

3,023.32

 

2,839.97

 

2,786.78

 

2,577.22

 

2,357.56

Total production and/or process water extracted  

(mmcm)

 

52.93

 

59.67

 

61.15

 

58.16

 

61.17 (a)

- of which re-injected      

14.88

 

23.32

 

27.11

 

25.18

 

20.82

Total recycled and/or reused water  

(mmcm)

 

460.93

 

490.22

 

544.63

 

521.76

 

521.46

Total number of oil spills (b)  

(number)

 

382

 

308

 

330

 

418

 

771

Total volume of oil spills (b)  

(barrels)

 

7,024

 

21,547

 

22,964

 

14,952

 

12,472

- of which from sabotage and terrorism      

2,286

 

15,288

 

18,695

 

7,657

 

8,616

- of which from accidents      

4,749

 

6,259

 

4,269

 

7,295

 

3,856

Waste from production activities  

(tonnes)

 

1,186,618

 

1,078,839

 

1,400,488

 

1,309,135

 

1,378,351

Hazardous waste from production activities      

479,828

 

418,120

 

489,108

 

476,552

 

365,668

Non-hazardous waste from production activities      

706,790

 

660,719

 

911,380

 

832,582

 

1,012,683

Waste from reclamation activities to be disposed of or recovered/recycled  

(tonnes)

 

9,199,934

 

10,163,403

 

11,020,439

 

13,869,509

 

16,294,882

Environmental expenditure and investments  

(euro thousand)

 

947,605

 

1,230,503

 

916,201

 

893,421

 

743,183














(a) In 2012 the figure include also the amount of produced water injected into deep wells to disposal purpose, equal to 9.43 mmcm.
(b) In the 2010-2011 period only oil spills of more than one barrel are considered for the E&P sector; in 2012 the figure also includes oil spills of less than one barrel (equal to 453, corresponding to 3,684 barrels).

- 13 -


Contents

Eni Fact Book Exploration & Production

   Exploration & Production

 

   Key performance indicators

       

2008

 

2009

 

2010

 

2011

 

2012














Employees injury frequency rate  

(No. of accidents per million of worked hours)

 

0.84

 

0.49

 

0.72

 

0.41

 

0.28

Contractors injury frequency rate      

0.93

 

0.59

 

0.48

 

0.41

 

0.36

Fatality index  

(No. of fatalities per 100 million of worked hours)

 

3.54

 

1.77

 

7.90

 

1.83

 

0.81














Net sales from operations (a)  

(euro million)

 

33,042

 

23,801

 

29,497

 

29,121

 

35,881

Operating profit      

16,239

 

9,120

 

13,866

 

15,887

 

18,451

Adjusted operating profit      

17,166

 

9,489

 

13,898

 

16,075

 

18,518

Adjusted net profit      

7,862

 

3,881

 

5,609

 

6,865

 

7,425

Capital expenditure      

9,281

 

9,486

 

9,690

 

9,435

 

10,307

Adjusted ROACE  

(%)

 

29.2

 

12.3

 

16.0

 

17.2

 

17.6














Profit per boe (b)  

($/boe)

 

16.00

 

8.14

 

11.91

 

16.98

 

15.95

Opex per boe (b)      

5.45

 

5.77

 

6.14

 

7.28

 

7.10

Cash flow per boe (d)      

32.25

 

23.70

 

25.52

 

31.65

 

32.77

Finding & Development cost (c) (d)      

28.79

 

28.90

 

19.32

 

18.82

 

17.37

Average hydrocarbons realizations (d)      

68.13

 

46.90

 

55.60

 

72.26

 

73.39














Production of hydrocarbons (d) (e)  

(kboe/d)

 

1,797

 

1,769

 

1,815

 

1,581

 

1,701

Estimated net proved reserves of hydrocarbons (d) (e)  

(mmboe)

 

6,600

 

6,571

 

6,843

 

7,086

 

7,166

Reserves life index (d)  

(years)

 

10.0

 

10.2

 

10.3

 

12.3

 

11.5

Organic reserves replacement ratio net of updating the natural gas conversion factor (d)  

(%)

 

130

 

93

 

127

 

143

 

147














Employees at year end  

(units)

 

10,236

 

10,271

 

10,276

 

10,425

 

11,304

of which: outside Italy      

6,182

 

6,388

 

6,370

 

6,628

 

7,371

Oil spills  

(bbl)

 

4,738

 

6,259

 

3,820

 

2,930

 

3,093

Oil spills from sabotage and terrorism      

2,286

 

15,288

 

18,695

 

7,657

 

8,384

Produced water re-injected  

(%)

 

28

 

39

 

44

 

43

 

49

Direct GHG emissions  

(mmtonnes CO2 eq)

 

33.21

 

29.73

 

31.20

 

23.59

 

28.46

of which: from flaring      

16.54

 

13.84

 

13.83

 

9.55

 

9.46

Community investment  

(euro million)

 

65

 

67

 

72

 

62

 

59














(a) Before elimination of intragroup sales.
(b) Consolidated subsidiaries.
(c) Three-year average.
(d) Includes Eni’s share of equity-accounted entities.
(e) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,492 standard cubic feet of gas per barrel of oil equivalent. The effect of this update on production expressed in boe was 9 kboe/d for the full-year 2012 and on the initial reserves balance as of January 1, 2012 amounted to 40 mmboe.

Performance of the year    
I In 2012 employees and contractors injury frequency rate declined by 31.7% and 12.2% compared to the previous year.
- Total greenhouse gas emissions increased by 20.6% due to the recovery of activities in Libya. Greenhouse gas emissions from flaring were in line with 2011 (down 0.9%).
- Oil spills increased in the full year (up 5.6% from accidents and up 9.5% from sabotage and terrorism) due to force majeure and security issues in Nigeria.
- Achieved the best ever levels in re-injection of the produced water with a level of 49%. In particular, the water re-injection project at the Belayim field (Eni’s interest 100%) in Egypt reported a level equal to 99%.
  - In 2012 the E&P Division reported a record performance with an adjusted net profit amounting to euro 7,425 million (up 8.2% from 2011) driven by an ongoing production recovery in Libya.
- Eni reported oil and natural gas production for the full year of 1,701 kboe/day (up 7% form 2011)1 sustained by the recovery of activities in Libya, the start-up/ramp-up of fields, particularly in Russia and Australia, and higher production in Iraq.
- Estimated net proved reserves at December 31, 2012 was aneight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. The organic reserves replacement ratio was 147%1 with a reserves life index of 11.5 years (12.3 years in 2011). All sources reserves replacement ratio was 107%1.

(1) Excluding the impact of updating the natural gas conversion rate.

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Exploration activity

I Full year 2012 was a record for exploration, adding 3.64 bboe of discovered resources, about six times production of the year, increasing Eni’s reserves to best ever levels with rapid time-to-market and cost effectiveness. Eni’s approach in the selective development initiatives, advanced technologies and knowledge management of core basins will be the key to achieve future targets.
- The exploration campaign executed in Mozambique in the Area 4 offshore the Rovuma basin proved the Mamba gas complex to be the largest discovery in the Company’s exploration history. Eni estimates the full mineral potential of Area 4 at 75 Tcf of gas in place. The geological studies confirmed the high productivity of exploration wells. This means that this huge resource base can be exploited with a limited number of producing wells that will make the upstream project highly efficient.
- In the Barents Sea, appraisal activities at the Skrugard discovery and the new Havis discovery showed recoverable reserves estimated at approximately 500 mmbbl at 100% in the license PL 532 (Eni’s interest 30%).
- In Ghana, appraisal activities at the Sankofa discovery in the Offshore Cape Three Points license (Eni operator with a 47.22% interest) confirmed the overall potential of the discovery to be around 450 million barrels of oil in place.
- A relevant onshore discovery in Pakistan with an estimated resource from 300 to 400 bcf of gas in place and in line with Eni’s strategy of focusing on conventional and synergic assets.
- Onshore exploration activity in Libya was resumed by drilling the A1-108/4 exploration well that will reach a total depth of approximately 4,420 meters. This is the first well of an onshore exploration campaign that will continue in 2013, marking a relevant step in the full recovery of Eni’s upstream activity in the Country.
- Other significant exploration successes were achieved in Egypt, Congo, Indonesia, Angola, the United States and Nigeria where synergies with existing infrastructures ensure to reduce time-to-market discovered resources.
- Eni’s portfolio was boosted with the acquisition of new exploration acreage in high potential areas such as Kenya, Liberia, Vietnam, Cyprus, offshore Russia and shale gas in Ukraine, as well as legacy areas such as China, Pakistan, Indonesia and Norway.
- In 2012 exploration expenditure amounted to euro 1,850 million (up 52.9% from 2011) to complete 60 new exploratory wells (34.1 net to Eni). The overall commercial success rate was 40% (40.8% net to Eni). In addition 144 exploratory wells drilled are in progress at year end (62 net to Eni).

  Sustainability and portfolio developments

I Signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of our subsidiary Eni East Africa, which currently owns 70% interest in Area 4 in Mozambique, for an agreed price equal to $4,210 million. The deal is subject to approval by relevant authorities. Once finalized, CNPC indirectly acquires, through its 28.57% equity investment in Eni East Africa, a 20% interest in Area 4, while Eni will retain the 50% interest through the remaining controlling stake in Eni East Africa.
- The international Contracting Companies of the Final Production Sharing Agreement (FPSA) of the Karachaganak 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.
The Contracting Companies divested 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for $1 billion net cash consideration ($325 million being Eni’s share). Eni’s interest in the Karachaganak project has been reduced to 29.25% from the 32.5% previously held.
- Signed an agreement with Anadarko Petroleum Corporation establishing basic principles for the coordinated development of common offshore activities in Area 4, operated by Eni and Area 1, operated by Anadarko. Furthermore, the two companies will jointly plan and construct onshore LNG liquefaction facilities in Northern Mozambique.
- The Consortium partners and the Authority of the Republic of Kazakhstan reached an agreement on the Amendment to the sanctioned development plan of the Kashagan field (Amendment 4) which included an update to the project schedule, a revision of investments estimate and the settlement of all pending claims relating to recoverable costs and other tax matters. The commercial production start-up is expected by the end of the first half of 2013.
- Developed a training program in the field of human rights for staff, in particular employed in the security area, at Eni’s subsidiaries in Congo and Angola. The activities involved about 900 employees in the Pointe Noire and Luanda area, respectively.
- Divested production and development assets in Italy, Nigeria, Norway, the United Kingdom and offshore Gulf of Mexico confirming a selective growth approach to optimize Eni’s asset portfolio.
- Sanctioned by Venezuelan authorities the development plan of the Perla gas project, in Block Cardón IV (Eni’s interest 50%), in the Gulf of Venezuela. In 2012 two more phases were sanctioned to reach a plateau production of approximately 1,200 mmcf/d.
- Made final investment decisions to develop fields, in addition to the above mentioned Perla field, in Angola, Congo, Nigeria and Italy which are expected to add 59 kboe/d in 2016.
- Development expenditure was euro 8,304 million (up 12.9% from 2011) to fuel the growth of major projects in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria.
- In 2012 overall R&D expenditure of the Exploration & Production Division amounted to approximately euro 94 million (euro 90 million in 2011).

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Activity areas

n  Italy
Eni has been operating in Italy since 1926. In 2012, Eni’s oil and gas production amounted to 189 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, on a total acreage of 22,285 square kilometers (17,556 net to Eni).
Eni’s exploration and development activities in Italy are regulated by concession contracts (54 operated onshore and 61 operated offshore).
Energy efficiency programs progressed with the application of innovative technologies such as: (i) Organic Rankine Cycle (ORC) technology to increase the efficiency of compression stations with a reduction in CO2 emissions that is expected to be applied to the Fano power station; (ii) the optimization of the LNG refrigeration process, patented by Eni, that increases overall efficiency.

Adriatic and Ionian Sea
Production Fields in the Adriatic and Ionian Sea represents Eni’s main production area for gas, accounting for 50% of Eni’s domestic production in 2012. Main operated fields are Barbara, Annamaria, Angela-Angelina, Porto Garibaldi, Cervia, Bonaccia, Luna and Hera Lacinia. Production is operated by means of 73 fixed platforms (3 of these are manned) installed on the main fields, to which satellite fields are linked by underwater infrastructures. Production is carried by sealine to the mainland where it is input in the national gas network.
Within the Cooperation Agreement signed with local authorities in the area of Ravenna, projects progressed to protect ecosystems in particular in the Comacchio Valleys in the Po Delta Park.

  Development Main development activities concerned: (i) production optimization at the Antonella, Barbara, Basil, Brenda, Naomi & Pandora and Porto Corsini fields; and (ii) upgrading of compression and hydrocarbon treatment facilities at the production platform of the Barbara field.

Central-Southern Apennines
Production Eni is the operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata Region in Southern Italy, resulting from the unitization of the Volturino and Grumento Nova concessions made in late 2005. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is fed by 26 production wells and is treated by the Viggiano oil center. Oil produced is carried to Eni’s Refinery in Taranto via a 136-kilometer long pipeline. Gas produced is delivered to the national grid system.
In 2012, the Val d’Agri concession accounted 30% of Eni’s production in Italy.
Development The development plan of the Val d’Agri concession is ongoing as agreed with the Basilicata Region in 1998. The construction of a new gas treatment unit started at the end of 2012 targeting a production capacity of 104 kbbl/d.

Sicily
Production Eni is the operator of 12 production concessions onshore and 2 production concessions offshore in Sicily. Its main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2012

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accounted for approximately 10% of Eni’s production in Italy.
Development Onshore activity was focused on production optimization at the Gela field. Studies for project development are underway at the Argo and Cassiopea offshore fields.

  n  Rest of Europe

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 over a developed and undeveloped acreage of 8,490 square kilometers (2,676 square kilometers net to Eni). Eni’s production in Norway amounted to 126 kboe/d in 2012.
In April 2012, Eni signed with Solveig Gas Norway AS an agreement for the sale of its 1.43% interest in the Gassled JV, a network of gas pipelines and terminals for natural gas transportation. The sale was closed at the end of 2012 with a consideration amount of approximately euro 130 million.
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.

Norwegian Sea
Production Eni currently holds interests in 10 production areas. The principal producing fields are Åsgård (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 2012 accounted for 78% of Eni’s production in Norway.
The gas produced in the area is collected at the Åsgård facilities, carried by pipeline to the Karsto treatment plant and then delivered to the Dornum terminal in Germany. Liquids recovered in the area mainly through FPSO units are sold FOB.
Development Development activities progressed to put in production discovered reserves near the Åsgård field. In particular activities are underway at the Marulk field, which is started-up in April 2012 with a yearly production of approximately 12 kboe/d (approximately 2 kboe/d net to Eni).
Exploration Eni holds interests in 33 prospecting licenses ranging from 5% to 50%, 4 of these are operated.
During the year, Eni was awarded the PL091D exploration licenses with a 7.9% interest.

Norwegian section of the North Sea
Production Eni holds interests in 5 production licenses. The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018, which in 2012 produced approximately 28 kboe/d net to Eni and accounted for 22% of Eni’s production in Norway. Production from Ekofisk and satellites is carried by pipeline to the Teesside terminal in the United Kingdom for oil and to the Emdem terminal in Germany for gas.
Development Activities were performed during the year to maintain and optimize the production rate at the Ekofisk field by means of infilling wells, the development of the South Area extension, upgrading of existing facilities and optimization of water injection.
Exploration Eni holds interests in 7 prospecting licenses ranging from 12% to 45%, two of them as operator.

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Barents Sea
Eni is currently performing exploration and development activities in the Barents Sea. Eni holds interests in 14 prospecting licenses, 8 of these are operated.
Exploration activities yielded positive results in the: (i) PL 532 license (Eni’s interest 30%) with the appraisal campaign for the assessment of mineral potential of the oil and gas Skrugard discovery and the new Havis oil and gas discovery. The total recoverable reserves of the PL 532 license are estimated at approximately 500 mmbbl at 100%. Both fields are planned to be put in production by means of a fast-track synergic development; (ii) PL 533 license (Eni’s interest 40%) with the gas and condensate Salina discovery.
Eni was awarded the PL 697 (Eni operator with a 65% interest), the PL 657 (Eni operator with an 80% interest) and the PL 696 license (Eni’s interest 30%).
Development operations have been focused on the Goliat discovery in the PL 229 (Eni operator with a 65% interest). The project is progressing; the production start-up is expected in 2014 with the production plateau of 100 kbbl/d. Subsea facilities were completed and an FPSO unit is in progress. In 2012 the emergency oil spill preparedness program has been completed engaging all stakeholders and checking all the responses to an oil spill. Testing activities were a joint effort between the operator Eni, its partner in the field and the Norwegian Clean Seas Association for Operating Companies (NOFO). Several public and private sector operators contributed with personnel and equipment to activities such as the use of fishing vessels for coastal cleaning operations, and the use of actual contingency resources during all phases of an oil spill response. These results showed that the Goliat project is characterized

  by a well-advance emergency system for the management of an oil spill, especially in terms of increased resources, organizational innovation, consolidation of the contingency apparatus, as well as equipment development and investment.
The Norwegian Authorities acknowledged this project as the reference standard for all future development projects in the Arctic.

United Kingdom
Eni has been present in the UK since 1964. Eni’s activities are carried out in the British section of the North Sea and the Irish Sea, over a developed and undeveloped acreage of 2,702 square kilometers (914 square kilometers net to Eni). In 2012, Eni’s net production of oil and gas averaged 47 kboe/d, the portion of liquids being approximately 50%.
During 2012, a gas leak occurred on a well at the Elgin/Franklin (Eni’s interest 21.87%) field which is located in the UK North Sea. Production for the field operated by an international oil company was stopped at the end of March. Production resumed during the first quarter of 2013. The impact on 2012 production was estimated at approximately 7 mmbbl.
Eni signed an agreement for the divestment of the following development/production assets: Mariner (Eni’s interest 20%), Andrew (Eni’s interest 16.21%), Kinnoul (Eni’s interest 16.67%), Flotta Catchment Area (Eni’s interest 20%) and a few minor ones. At the end of the year, the sale of Mariner was completed. The completion date for the other assets is expected in 2013. These agreements confirmed Eni’s approach to optimize its producing asset portfolio in the Country.
Exploration and production activities in the UK are regulated by concession contracts.
Production Eni holds interests in 13 production areas; in 1 of these, the Hewett Area, Eni is operator with an 89% interest. The

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other main fields are Elgin/Franklin, West Franklin (Eni’s interest 21.87%), Liverpool Bay (Eni’s interest 53.9%), J Block Area (Eni’s interest 33%), Flotta Catchment Area (Eni’s interest 20%) and MacCulloch (Eni’s interest 40%), which in 2012 accounted for 91% of Eni’s production in the Country.
Development Main development activities in 2012 were: (i) the construction of production and treatment facilities for the gas and liquids Jasmine field (Eni’s interest 33%). Start-up is expected in 2013; (ii) the construction of production platforms and linkage to nearby treatment facilities for the West Franklin field.
Exploration Eni holds interests in 30 exploration blocks ranging from 5% to 41%, in 2 of these Eni is operator.

n  North Africa

Algeria
Eni has been present in Algeria since 1981. In 2012, Eni’s oil and gas production averaged 78 kboe/d. Operated and participated activities are located in the Bir Rebaa area in the South-Eastern Desert: (i) Blocks 403a/d (Eni’s interest 100%); (ii) Block Rom North (Eni’s interest 35%); (iii) Blocks 401a/402a (Eni’s interest 55%); (iv) Blocks 403 (Eni’s interest 50%) and 404 (Eni’s interest 12.25%, non operated); (v) Block 212 (Eni’s interest 22.38%) with discoveries already made; and (vi) Blocks 208 (Eni’s interest 12.25%, non operated) and 405b (Eni’s interest 75%) with ongoing development activities.

  Developed and undeveloped acreage of Eni’s interests in Algeria was 3,798 square kilometers (1,232 square kilometers net to Eni).
Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

Blocks 403a/d and Rom North
Production Production in the area comes mainly from the HBN and Rom and satellite fields and represented 21% of Eni’s production in Algeria in 2012. Production from Rom and Satellites (Zea, Zek and Rec) is treated at the Rom Central Production Facilities (CPF) and sent to the BRN treatment plant for final treatment, while production from the HBN field is treated at the HBN/HBNS oil center at the Groupment Berkine.
Development A new multiphase pumping system finalized during the year to achieve zero gas flaring, in compliance with applicable Country law.

Blocks 401a/402a
Production Production from this area is supplied mainly by the ROD/SFNE and satellite fields and accounted for approximately 24% of Eni’s production in the Country in 2012. Activities are being performed in order to maintain the current production plateau.

Block 403
Production The main fields are BRN, BRW and BRSW which accounted for approximately 18% of Eni’s production in Algeria in 2012.

Block 404
Production The main fields are HBN and HBNS which accounted for approximately 37% of Eni’s production in Algeria in 2012.

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Block 405b
Production In 2013, production started at the MLE field part of the MLE-CAFC integrated project. A natural gas treatment plant started operations with a gross production and export capacity of approximately 320 mmcf/d of gas, 15 kbbl/d of oil and condensates and 12 kbbl/d of LPG. Four export pipelines link it to the national grid system.
Development Activities progressed at the CAFC oil project. The project includes the construction of an oil treatment plant and synergies with the MLE production facilities. Production start-up is expected in 2015. The MLE-CAFC integrated project targets a production plateau of approximately 33 kboe/d net to Eni by 2016.

Block 208
Development Block 208 is located south of Bir Rebaa. The El Merk project is designed to jointly develop this block and adjoining blocks operated by other companies. The final investment decision was reached in 2009. The development program provides for the construction of a gas treatment plant for the liquid extraction with a gross capacity of approximately 600 mmcf/d, two oil trains with a gross capacity of 65 kbbl/d each and three export pipelines targeting a production plateau at approximately 18 kbbl/d net to Eni in 2015. Start-up is expected in 2013.

Egypt
Eni has been present in Egypt since 1954. In 2012, Eni’s share of production in this Country amounted to 235 kboe/d and accounted for 14% of Eni’s total annual hydrocarbon production. Developed and undeveloped acreage in Egypt was 12,782 square kilometers (4,590

  square kilometers net to Eni). 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 Melehia (Eni’s interest 56%) 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 2012, 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.

Gulf of Suez
Production
Production mainly comes from the Belayim field, Eni’s first large oil discovery in Egypt, which produced approximately 107 kbbl/d (57 net to Eni) in 2012.
Development The Belayim water injection system has been upgraded in order to optimize the recovery of its mineral potential. The level of produced water re-injected is 99%, corresponding to approximately 1 mmcf/d. Infilling and drilling activities are still in progress.
Exploration Exploration activities yielded positive results with the BLNE-2 and BMSW-1 oil discoveries nearby the Belayim field that were linked to the existing facilities.

Nile Delta
North Port Said
Production Production for the year amounted to 40 kboe/d (29 net to Eni), approximately 106 mmcf/d of gas and approximately 7 kbbl/d of condensates. Part of the production of this concession is supplied to the NGL (natural gas liquids) plant owned by United Gas Derivatives Co (Eni’s interest 33%) with a treatment capacity of 1.3 bcf/d of natural gas, which is achieved in the year, and a yearly production of 380 ktonnes of propane, 305 ktonnes of LPG and 1.5 mmbbl of condensates.
Development Ongoing development activities aim at supporting current gas production levels. Upgrading activities were finalized at the El Gamil plants compression to support the North Port Said, el Temsah and Ras el Barr production concessions.

Baltim
Production In this concession, production for the year amounted to approximately 61 kboe/d (approximately 20 kboe/d net to Eni); approximately 106 mmcf/d of gas and 3 kbbl/d of condensates.
Development Upgrading was completed at the Abu Madi plant by adding new compression capacity to support production.

Ras el Barr
Production This concession contains three fields: Ha’py, Akhen and Taurt. Production in 2012 amounted to approximately 100 kboe/d (35 net to Eni), mainly gas.
In 2012, the gas offshore Seth field achieved production start-up. Production is processed at the El Gamil onshore plant and plateau is expected at approximately 170 mmcf/d (approximately 11 kboe/d net to Eni).

El Temsah
Production This concession includes the Temsah, Denise and Tuna fields. Production in 2012 amounted to approximately 220 kboe/d (68 net to Eni); approximately 318 mmcf/d of gas and approximately 8 kbbl/d of condensates net to Eni.

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Natural gas production of this concession is supplied to the Damietta natural gas liquefaction plant owned by Unión Fenosa Gas. Eni, together with other international oil company, have entered into an agreement to supply 310 mmcf/d for 17-year period.
Development Infilling and workover activities are being performed in order to maintain the current gas production plateau.

Exploration in the Nile Delta
This area shows a relevant mineral potential. Exploration activities yielded positive results with the offshore gas discoveries of Ha’py-12, Taurt North-1, Seth South-1, Plio-1C and with the El Qara N-2 onshore gas discovery.

Western Desert
Production
Other operated production activities are located in the Western Desert, in particular in the Melehia (Eni’s interest 56%), Ras Qattara (Eni’s interest 75%), West Abu Gharadig (Eni’s interest 45%) and West Razzak (Eni’s interest 80%) development permits containing mainly oil. Concessions in the Western Desert accounted for approximately 6% of Eni’s production in Egypt in 2012.
Development Activities for the year concerned the completion and start-up of a hybrid solar/fossil facility in the Aghar field in the West Razzak development lease. The proprietary technology allows to save fuel during oil production by utilizing photovoltaic panels in parallel.
Exploration Exploration activities yielded positive results in the: (i) Meleiha development lease with the Rosa North-1X, Emry Deep 1X and 4X oil discoveries. The Emry Deep field started-up with approximately 18 kbbl/d (approximately 6 kbbl/d net to Eni); and (iv) West Razzak development lease with the Aghar NN-1X oil discovery.

Libya
Eni started operations in Libya in 1959. In 2012, Eni’s oil and gas production averaged 258 kboe/d. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area, over a developed and undeveloped acreage of 26,635 square kilometers (13,294 square kilometers net to Eni). 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 oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).
In the exploration phase, Eni is operator of four onshore blocks in the Kufra area (186/1, 2, 3 and 4) and in the contract Areas A, B and 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.
In the Offshore Area D, Eni was the first IOC to restart exploration activity after revolution, with the acquisition of about 2,600 square kilometers of 3D seismic survey from February to April 2012. In addition, the onshore exploration activity was resumed in December 2012 by drilling the A1-108/4 exploration well that will reach a total depth of approximately 4,420 meters. This is the first well of an onshore exploration campaign that will continue in 2013 marking a relevant step in the full recovery of Eni’s upstream activity in the Country.

  Area A
Production
Located in the Eastern Libyan Desert, it includes six oil fields, started-up in 1984, which are linked to existing facilities at the nearby Bu Attifel field (Area B). In 2012 production from these fields amounted to approximately 11 kbbl/d (approximately 3 kbbl/d net to Eni).

Area B
Production
Located in the Eastern Libyan Desert, it includes the Bu Attifel oil field discovered in 1967 and started-up in 1972, as well as the smaller NC 125 field. Eni’s production in 2012 amounted to approximately 58 kbbl/d (approximately 12 net to Eni).

Area C
Production This area is located in the Mediterranean offshore facing Tripoli. The Bouri oil field, discovered in 1976 and started-up in 1998, produced approximately 42 kbbl/d (approximately 19 net to Eni) in 2012. The field is exploited through two platforms linked to an FSO unit with a storage capacity of approximately 1.5 mmbbl.

Area D
Production Area includes the offshore NC 41 block and the onshore NC 169 block jointly developed in the Western Libyan Gas Project. Production comes from: (i) the Wafa onshore field that started-up in September 2004. In 2012 this field produced approximately 110 kboe/d of liquids and natural gas (approximately 88 net to Eni); (ii) the Bahr Essalam offshore field that started-up in August 2005. In 2012 this field produced approximately 161 kboe/d of liquids and natural gas (approximately 129 net to Eni). Onshore production is treated at the Wafa facility. Gas production is for the internal consumptions or export. Liquids production is delivered by pipeline to the Mellitah plant for fractioning and marketing of

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oil and condensates. Offshore production is operated through the Sabratha platform located on the Bahr Essalam field where gas and liquids undergo a pre-treatment phase and are delivered via sealine to the Mellitah plant. Most of the natural gas produced is exported to Europe through the GreenStream pipeline. In 2012 volumes delivered through this pipeline were approximately 219 bcf. In addition, approximately 145 bcf were sold on the Libyan market for power generation and approximately 4 bcf to feed the GreenStream compressor station.

Area E
Production
Located in the South-Western Libyan desert about 800 kilometers from Tripoli, production of this area is provided mainly by the El Feel (Elephant) oil field. In 2012 the field produced approximately 89 kbbl/d (approximately 8 net to Eni). Production is treated at the field’s facilities and then delivered by pipeline to the Mellitah plant for storage and marketing.

Tunisia
Eni has been present in Tunisia since 1961. In 2012, Eni’s production amounted to 15 kboe/d. Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed and undeveloped acreage of 6,464 square kilometers (2,274 square kilometers net to Eni).
Exploration and production in this Country are regulated by concessions.
Production Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.
Development Production optimization was carried out at the Baraka, Oued Zar, MLD and Adam fields to maintain the current production plateau and to reduce gas flared.
Exploration An exploration campaign, geological and geophysical studies started in the area for assessing the residual mineral potential of conventional and unconventional gas resources.

n  Sub-Saharan Africa

Angola
Eni has been present in Angola since 1980. In 2012, Eni’s production averaged 87 kboe/d. Eni’s activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 24,841 square kilometers (6,079 square kilometers net to Eni).
The main producing blocks with Eni’s participation are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) in the North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest ranging from 12% to 15%) in the offshore of the Congo Basin; (iii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin.
Eni 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 35% 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%).

 

In the exploration and development phase, Eni operates Block 15/06 (Eni’s interest 35%).
Exploration and production activities in Angola are regulated by concessions and PSAs.

Block 0
Production Block 0 is divided into Areas A and B. In 2012, production from this block amounted to approximately 329 kbbl/d (approximately 32 kbbl/d net to Eni). Oil production from Area A, deriving mainly from the Takula, Malongo and Mafumeira fields amounted to approximately 20 kbbl/d net to Eni. Production of Area B derives mainly from the Bomboco, Kokongo, Lomba, N’Dola, Nemba and Sanha fields, and amounted to approximately 12 kbbl/d net to Eni.
Development As part of the activities designed to reduce gas flaring in Block 0, activity progressed at the Nemba field in Area B with completion expected in 2014. Once completed flared gas is expected to decrease by approximately 85% from current level. Other ongoing projects include the installation of a second compression unit at the Nemba platform. In the Area A, development activities progressed at the Mafumeira field, sanctioned during the year. Start-up is expected in 2015.
Infilling activities and near-field exploration are underway on the whole block in order to contrast natural decline.

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Block 3
Production Block 3 is divided into three production offshore areas. In 2012, production from this block amounted to approximately 60 kbbl/d (approximately 5 kbbl/d net to Eni).
Development Concept Definition studies are underway in the Punja and Caco-Gazela discoveries.

Block 14
Production In 2012, Development Areas in former Block 14 produced approximately 162 kbbl/d (approximately 17 kbbl/d net to Eni), accounting for approximately 20% of Eni’s production in Angola. It is one of the most fruitful areas in the West African offshore, recording 9 commercial discoveries to date. Its main fields are: (i) Kuito, started-up in 1999, flowing at approximately 3 kbbl/d net to Eni in 2012; (ii) Landana and Tombua, started-up in 2009, flowing at approximately 7 kboe/d net to Eni. Production is supported by a Compliant Piled Tower provided with treatment facilities; (iii) Benguela-Belize/Lobito-Tomboco, started-up in 2006, flowing at approximately 6 kbbl/d net to Eni. Production from these fields is supported by a Compliant Piled Tower provided with treatment facilities for Benguela-Belize and an underwater linkage system for Lobito-Tomboco. Oil produced is treated at the Malongo plant. Associated gas of Landana/Tombua and Benguela-Belize/Lobito-Tomboco will be re-injected in the Nemba reservoir and later it will be delivered via a transport facility to the A-LNG liquefaction plant (see below).
Development In 2012 Lianzi field (Block 14K4-IMI) has been sanctioned. Concept Selection activities are underway in the recent Malange and Lucapa discoveries.

Block 15
Production Development Areas in former Block 15 produced on average approximately 422 kbbl/d (approximately 31 kbbl/d net to Eni) in 2012. This is considered the most interesting area in the West African offshore with recoverable reserves estimated at 2.55 bbbl of oil. Production derives mainly from the Kizomba discovery area with: (i) the Hungo/Chocalho fields, started-up in August 2004 as part of phase A of the global development plan of the Kizomba reserves; (ii) the Kissanje/Dikanza fields, started-up in July 2005, as part of Phase B. In 2012, these fields operated by FPSO unit yielded production of approximately 233 kbbl/d (approximately 17 kbbl/d net to Eni). Other fields in Block 15 are Mondo and Saxi/Batuque fields which produced approximately 132 kbbl/d (approximately 8 kbbl/d net to Eni) in 2012.
Production started at the satellites Kizomba Phase 1 project with peak production at 72 kbbl/d (12 kbbl/d net to Eni) expected in 2013.
In the medium-term, production plateau will be supported by phased development of satellite discoveries.
Development Main projects underway concerned the drilling activity at the Mondo and Saxi/Batuque fields to finalize their development plan.
The subsea facility of the Gas Gathering project has been completed and will provide for the collection of all the gas of the Kizomba, Mondo and Saxi/Batuque fields to be delivered to the A-LNG liquefaction plant.
In 2012 the second phase of Kizomba satellites has been sanctioned. The project includes the linkage of three additional discoveries (Kakocha, Bavuca and Mondo South) to the existing FPSO. Start-up is expected in 2015.

  Block 15/06
Exploration activities yielded positive results with the oil Vandumbu 1 discovery, first commitment well of the second exploration period. The discoveries of Block 15/06 will be developed within two projects: the West Hub project, sanctioned in 2010, and the East Hub.
The West Hub project includes the development of the Sangos, N’Goma and Cinguvu discoveries, that will be added in two additional phases of the Mpungi and Vandumbu discoveries, which increases the potential of the hub up to 200 mmbbl. First planned phase (Sangos, N’Goma and Cinguvu) concerned drilling of 14 subsea wells (8 producers and 6 injectors) and linkage to an FPSO unit with a capacity of 100 kbbl/d with start-up expected in the first half of 2014. Two additional phases provides the development of the Mpungi field with the drilling of 7 wells (4 producers and 3 injectors) connected to the FPSO and then the Vandumbu field, under study. Peak production is expected at 84 kbbl/d (25 net to Eni) in 2016.
The East Hub project intends to develop the Cabaça North and South-East discoveries with potential resources estimated at more 230 mmbbl. Development activity provides for the drilling of 22 subsea wells and the installation of an FPSO unit with a capacity of 120 kbbl/d. Final investment decision is expected in 2013. Further development phases are planned to start-up nearby discoveries; in particular the significant Lira discoveries. Peak production is expected at approximately 15 kbbl/d net to Eni.

The LNG business in Angola
Eni holds a 13.6% interest in the Angola LNG Ltd (A-LNG), consortium responsible for the construction of an LNG plant with a processing capacity of approximately 1.1 BCF/d of natural gas, producing 5.2 mmtonnes/y of LNG and over 50 kbbl/d of condensates and LPG. The project has been sanctioned by the relevant Angolan Authorities. It envisages the development of 10,594 BCF of gas in 30 years. Exports start-up is expected in 2013. In the year a new agreement has been reached by the partners and local authorities for the sale of LNG on Asian and European markets.
In addition, Eni is part of the Gas Project (Eni’s interest 20%), a second gas consortium with the Angolan national company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or other marketing projects to monetize gas and associated liquids.
Exploration activities yielded positive results in Block 2 with the Etele Tampa 7 well containing gas and condensates.

Congo
Eni has been present in Congo since 1968. In 2012, production averaged 104 kboe/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore covering a developed and undeveloped acreage of 9,516 square kilometers (5,035 square kilometers net to Eni).
In the year, Eni started the integrated Hinda social project for the rehabilitation and construction of schools and dispensaries, the construction of facilities for the water supply and construction of an agricultural training centre.
Exploration and production activities in Congo are regulated by PSAs.
Production Eni’s main operated oil producing interests in Congo are the Zatchi (Eni’s interest 65%), Loango (Eni’s interest 50%), Ikalou (Eni’s interest 100%), Djambala, Foukanda and Mwafi (Eni’s

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interest 65%), Kitina (Eni’s interest 35.75%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%), Kouakouala (Eni’s interest 75%), Zingali and Loufika (Eni’s interest 85%) fields, with a production of approximately 77 Kboe/d in the year.
Other relevant producing areas are a 35% interest in the Pointe-Noire Grand Fond, PEX and Likouala permits (overall production of 26 kboe/d in 2012).
Development Activities on the M’Boundi field moved forward with the application of Eni advanced recovery techniques and a design to monetize associated gas within the activities aimed at zero gas flaring by 2013. Gas is sold under long-term contracts to power plants in the area including the CEC Centrale Electrique du Congo (Eni’s interest 20%) with a 300 MW generation capacity. These facilities will also receive in the future gas from the offshore discoveries of the Marine XII permit. In 2012 M’Boundi contractual supplies were approximately 106 mmcf/d (approximately 17 kboe/d net to Eni).
In 2012 the development project for the gas and condensates Litchendjili field in the Block Marine XII has been sanctioned. The project provides for the installation of a production platform, the construction of transport facilities and of an onshore treatment plant. Production will also feed the CEC power station.
Other activities in the area concerned the optimization of producing fields of Foukanda and Mwafi by means of Eni’s enhanced recovery that allowed to increase production in both fields.
Exploration In the exploration phase, Eni also holds interests in

  the Mer Très Profonde Sud deep offshore block (Eni’s interest 30%), the Noumbi onshore permit (Eni’s interest 37%) and the Marine XII offshore permit.
Exploration activities yielded positive results in the offshore block Marine XII with the Nene Marine 1 gas discovery that confirmed the high mineral potential of the area.

Ghana
Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni’s interest 47.2%) and Offshore Keta Contract Area (Eni’s interest 35%) exploration permits.
Exploration activities yielded positive results in the Offshore Cape Three Points license with the: (i) Sankofa East-1X well, the first commercial oil discovery in the area that flowed at approximately 5 kbbl/d of high quality oil in test production; (ii) the Sankofa East-2A appraisal well that confirmed the high mineral potential of the western area. The total potential of the Sankofa discovery is estimated at 450 mmbbl of oil in place with recoverable reserves up to 150 mmbbl. Studies for a fast track commercial development are underway.
In July 2012, Eni and its partners in the OCPT license, signed a Memorandum of Understanding with the Ministry of Energy of Ghana for the development and marketing of discovered gas resources. The Memorandum focuses particularly on the domestic gas market, in which Eni and its joint venture partners wish to play a prominent role.
Activities progressed to support local communities, focusing mainly on: (i) local economy and training programs for women and young people; and (ii) enhancement of health conditions particularly for children.

Mozambique
Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 block located in the offshore Rovuma Basin.
In 2012 exploration and appraisal campaigns achieved new exploration successes in Area 4 located in the Rovuma Basin with the Mamba South 2, Mamba North 1, Mamba North East 1 and 2 as well as Coral 1 and 2 gas discoveries.
The latest Mamba North East and Coral discoveries are particularly significant since they confirm a new exploration play in Area 4, which is independent from Mamba’s structure. Eni estimates the full mineral potential of Area 4 at 75 Tcf of gas in place. FID is expected in 2014.
In early 2013 a new exploration success was achieved with the delineation of Coral 3 gas well that strengthen the mineral potential of the area operated by Eni. The wells, drilled at the Coral prospect, showed excellent results during the production test.
Eni plans to drill a further delineation well, Mamba South 3, before moving back to exploration drilling in the southern sector of Area 4.
In December 2012, Eni signed an agreement with Anadarko Petroleum Corporation establishing basic principles for the coordinated development of common offshore activities in Area 4, operated by Eni and Area 1, operated by Anadarko. Furthermore, the two companies plan to jointly design and construct onshore LNG liquefaction facilities in Northern Mozambique.
In March 2013, Eni signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of the subsidiary Eni East Africa, which currently owns 70% interest in Area 4, for an agreed price equal to $4,210 million. The deal is subject to approval by relevant

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Authorities. Once finalized, CNPC indirectly acquires, through its 28.57% equity investment in Eni East Africa, a 20% interest in Area 4, while Eni will retain the 50% interest through the remaining controlling stake in Eni East Africa.
Feasibility studies are underway to promote some initiatives in the Country such as schooling, health, socio-economic development and the environment. A first program has been launched for the recruitment of 45 recent graduates of the University of Mozambique to spend two years of training in Italy. More recently, in November 2012, a second selection campaign has been launched for a further training initiative to be carried out in 2013.

Nigeria
Eni has been present in Nigeria since 1962. In 2012, Eni’s oil and gas production averaged 154 kboe/d over a developed and undeveloped acreage of 36,286 square kilometers (7,646 square kilometers net to Eni) located mainly in the onshore and offshore of 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 OPL 245 (Eni’s interest 50%), OML 125 (Eni’s interest 85%), 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 25 onshore blocks and a 12.86% interest in 5 conventional offshore blocks.
In the exploration phase Eni operates offshore Oil Prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (Eni’s interest 85%) and OPL 2009 (Eni’s interest 49%); and onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135.
Exploration activities yielded positive results in: (i) Block OPL 282 with the Tinpa 1 well containing oil; and (ii) Block OPL 2009 with the Afiando 1 and 2 oil wells.
In 2012, Eni completed the divestment of a 5% stake in blocks OMLs 30, 34 and 40 confirming Eni’s strategy of optimizing its producing asset portfolio and selective growth.
Starting from March 21, the oil production of the onshore Swamp area mainly in the Bayelsa State in Nigeria has been temporarily shut down due to the increasing bunkering and sabotage acts on the oil trunk lines. Currently, the area produces from 9 fields through 4 flow stations (Ogbainbiri, Tebidaba, Clough Creek, Obama). A detailed survey of the lines affected by the bunkering is in progress in order to identify and repair the damages suffered.
As a part of a few Memorandum of Understanding signed with local communities in the Niger Delta, some programs were completed

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aimed at improving access to health and education services, initiatives in agriculture and construction of infrastructure for supporting local development. In particular, the following projects were completed: (i) rehabilitation of nine schools for 25 communities; (ii) eight projects allowing access to drinkable water by means of facilities installed in 13 communities; (iii) fifteen projects for electricity supply. Activities are underway to reach other 22 local communities.
Exploration and production activities in Nigeria are regulated mainly by PSAs and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for the state-owned company.

Blocks OMLs 60, 61, 62 and 63
Production Onshore licenses OMLs 60, 61, 62 and 63 produced approximately 59 kboe/d and accounted for 38% of Eni’s production in Nigeria in 2012. Liquid and gas production is supported by the NGL plant at Obiafu-Obrikom with a treatment capacity of approximately 1 bcf/d and by the oil tanker terminal at Brass with a storage capacity of approximately 3.5 mmbbl. A large portion of the gas reserves of these four OMLs is destined to supply the Bonny liquefaction plant (see below). Another portion of gas production is employed in firing the combined cycle power plant at Kwale-Okpai with a 480 MW generation capacity. In 2012, supplies to this power station were an overall amount of approximately 70 mmcf/d, corresponding to approximately 11 kboe/d (approximately 2 kboe/d net to Eni). This project is part of the Nigerian government and Eni’s plans for the reduction of carbon dioxide emissions and qualifies as CDM (Clean Development Mechanism) as provided for by the Kyoto Protocol.
Development Activities progressed to support gas production to feed the Bonny liquefaction plant. Development activities concerned the Tuomo gas field aimed at supplying 170 mmcf/d net to Eni of feed gas to the sixth train for 20 years. The flowstation at Ogbainbiri is nearing completion. This facility will ensure approximately 310 mmcf/d of feed gas to the fourth and the fifth trains. Flaring down program continued with the upgrading of the flowstation at the Idu field with a decline in flared gas of 45 mmcf/d.

Block OML 118
Production The Bonga oil field produced approximately 16 kbbl/d of oil net to Eni in 2012. Production is supported by an FPSO unit with a 225 kbbl/d treatment capacity and a 2 mmbbl storage capacity. Associated gas is carried to a collection platform on the EA field and, from there, is delivered to the Bonny liquefaction plant.

Block OML 119
Production Production derived mainly from the Okono/Okpoho fields which yielded approximately 4 kbbl/d of oil net to Eni in 2012. Production is supported by an FPSO unit with an 80 kbbl/d treatment capacity and a 1 mmbbl storage capacity.
In 2012, Phase 2A achieved production start-up by means of the drilling of two additional sub-sea wells linked to existing FPSO unit.
Peak production is expected at 15 kbbl/d.

Block OML 125
Production The Abo field production amounted to approximately 18 kbbl/d of oil net to Eni in 2012. Production is supported by an FPSO unit with a 45 kbbl/d capacity and an 800 kbbl storage capacity.
Activities progressed at the Abo Phase 3 project. Start-up is expected in 2013.

  Block OPL 245
This deep offshore block includes the largest undeveloped mineral resources potential in the Country. Eni’s commitment is for a fast track development of the Zabazaba and Etan fields. Drilling activities started up in 2012. The preliminary development scheme provides for the installation of an FPSO unit and the drilling of 8 wells (4 productive and 4 injections). FID is expected in 2014.

SPDC Joint Venture (NASE)
In 2012, production from the SPDC JV accounted for approximately 36% of Eni’s production in Nigeria (55 kboe/d).
In block OML 28 the integrated oil and natural gas project in the Gbaran-Ubie area is underway. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of approximately 1 bcf/d of gas and 120 kbbl/d of liquids in order to feed gas the Bonny liquefaction plant.

The LNG business in Nigeria
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 (Eni’s interest 5%) 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 and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.
Eni holds a 17% interest in Brass LNG Ltd Co for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100-kilometer west of Bonny. This plant is expected to start operating in 2017 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 45 net to Eni) of feed gas on two trains for twenty years. Supply to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61.

n  Kazakhstan

Eni has been present in Kazakhstan since 1992 where the Company co-operates the Karachaganak producing field and is a partner of the consortium of the North Caspian Sea PSA to develop the Kashagan field.

Kashagan
Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for approximately 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources which will eventually be developed in phases. The NCSPSA will expire at the end of 2041.
The exploration and development activities of the Kashagan field and the other discoveries made in the contractual area are executed

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through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The North Caspian Operating Company (NCOC) BV, participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and, when sanctioned, the onshore part of Phase 2.
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 2012 the Experimental Program progressed at the last phase of mechanical completion while commissioning and pre-start up activities achieved an advanced stage. Production plants are planned to be handed over to the production organization and tested. Start-up and commercial production is expected by the end of the first half of 2013, as agreed with the Republic of Kazakhstan.
The Phase 1 (Experimental Program) targets an initial production

  capacity of 150 kbbl/d; by 2014 a second treatment train and compression facilities for gas reinjection will be completed and put online enabling to increase the production capacity up to 370 kbbl/d. The partners are planning to further increase available production capacity up to 450 kbbl/d by installing additional gas compression capacity for re-injection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities and sanction is expected in 2013 to start-up with FEED phase.
Eni continues its commitment in the protection of the environment and ecosystems in the Caspian area with the integrated program for the management of biodiversity in the Ural Delta (Ural River Park Project - URPP). The project is almost completed and Eni’s aim is to include it in the Man and Biosphere Program of UNESCO under the patronage of the Kazakh Minister for Environmental Protection.

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. The contracting companies transferred 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for $1 billion net cash consideration ($325 million being Eni’s share). From the effective date of June 28, 2012, Eni’s interest in the Karachaganak project has been reduced to 29.25% from the 32.5% previously held. The agreement also includes the allocation of an additional 2 mmtonnes/y capacity in the Caspian Pipeline.
Production In 2012, production of the Karachaganak field averaged 239 kbbl/d of liquids (61 net to Eni) and 788 mmcf/d of natural gas (approximately 222 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. Approximately 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 and associated raw gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.
Development Phase 3 of the Karachaganak project is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation, in stages, of gas treatment plants and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing definition to be presented to the relevant Authorities.
Eni continues its commitment to support local communities by means of the construction of schools and educational facilities, water and energy systems and the implementation of free health assistance for the villages located in the nearby area of Karachaganak.

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n  Rest of Asia

China
Eni has been present in China since 1984. In 2012, Eni’s production amounted to 9 kboe/d. Activities are located in the South China Sea over a developed and undeveloped acreage of 10,656 square kilometers (10,495 square kilometers net to Eni).
In April 2012, Eni and CNOOC signed a Production Sharing Contract for the exploration of offshore Block 30/27, located in the South China Sea. The exploration commitment provides for the acquisition of a 3D seismic survey and the drilling of one well to be performed during the first exploration period. Eni will be the Operator of the project, with a 100% interest. In the case of a discovery, CNOOC has a back-in right up to 51%.
In March 2013, Eni and CNPC signed a joint study agreement for the development of the Rongchang Block with shale gas resources, over an area of approximately 2,000 square kilometers, located in the Sichuan Basin, in China.
Exploration and production activities in China are regulated by PSAs.
Production Hydrocarbons are produced from the offshore Blocks 16/08 and 16/19 through eight platforms connected to an FPSO. Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal and sold to the Chinese National Co CNOOC. Oil is mainly produced from HZ25-4 field (Eni’s interest 49%). Activity is operated by the CACT-Operating Group (Eni’s interest 16.33%).

Indonesia
Eni has been present in Indonesia since 2001. Eni’s production amounted to 18 kboe/d, mainly gas, in 2012. Activities are concentrated in the Eastern offshore and onshore East Kalimantan, offshore Sumatra, and offshore/onshore areas of West Timor and West Papua, over a developed and undeveloped acreage of 30,225 square kilometers (19,734 square kilometers net to Eni) in 13 blocks.
In May 2012, Eni was awarded the East Sepinggan block (Eni’s interest 100%), located offshore in Kutei Basin, including several exploration discoveries, supported by the nearby Bontang LNG processing facility. The commitment activity foresees performing of geological and geophysical studies, acquisition of seismic data and the drilling of one well over the next three years.
Exploration and production activities in Indonesia are regulated by PSAs.
Production Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.8%) with seven production fields. This gas is treated at the Bontang liquefaction plant, one of the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets.
Development The development plan of the operated Jangkrik (Eni’s interest 55%) and Jau (Eni’s interest 85%) offshore fields progressed. The Jangkrik project includes linkage of production wells to a Floating Production Unit for gas and condensate treatment and the construction of a transportation facility to the Bontang liquefaction plant. Start-up is expected in 2016 with a production peak of 80 kboe/d (41 kboe/d net to Eni). The Jau project provides for the drilling of production wells and the linkage to onshore plants via pipeline.
Appraisal activities related to a coal bed methane project (CBM) progressed at the Sanga Sanga PSC. Predevelopment activities are underway leveraging on the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant.

  Development activities are underway at the Indonesia Deepwater Development project (Eni’s interest 20%), located in the East Kalimantan, to ensure gas supplies to the Bontang plant. The project initially provides for the linkage of the Bangka field to existing facilities, then for the integrated development of four fields through a first Hub serving the Gendalo, Gandang, Maha and a second Hub for Gehem.

Iraq
Eni has been present in Iraq since 2009 and is performing development activities over a developed acreage of 1,074 square kilometers (352 square kilometers net to Eni). Production comes from Zubair oil field (Eni’s interest 32.8%) with a production of 18 kbbl/d net to Eni in 2012.
Exploration and production activities in Iraq are regulated by a Technical Service Contract.
Development activities progressed at the Zubair oil field. The contracts have been awarded for the first expansion of the actual production capacity to double the current production level in 2014.
Social and economic projects started in the Zubair area with oil business training programs. In 2012 a total of 8 initiatives have been addressed to over 100 people with a total expenditure of euro 1.4 million. Furthermore some agriculture projects started in cooperation with local Authorities.

Pakistan
Eni has been present in Pakistan since 2000. In 2012, Eni’s production averaged 57 kboe/d mainly of gas. Activities are located onshore covering a developed and undeveloped acreage of 28,640 square kilometers (10,533 square kilometers net to Eni).
In December 2012, Eni signed an agreement with the Pakistani Authorities and the state oil and gas company OGDCL for the acquisition of a 25% stake and the operatorship of exploration license Indus Block G, located in ultra deep water offshore of the Indus Basin over an area of approximately 7,500 square kilometers.
Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).
An important program is in progress to support local communities, aiming at improving schooling, managing of natural resources, establishing medical centers and drinking water distribution facilities. In particular in the area nearby Bhit plant, first initiatives ensured to reduce infant and mother mortality rates.
Production Eni’s main permits in the Country are Bhit (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2012 accounted for 76% of Eni’s production in Pakistan.
Exploration Exploration activity yielded positive results with a relevant gas discovery in the onshore concession Badhra Area B. The discovery is estimated to hold from 300 to 400 bcf of gas in place. A further outline of the discovery will require additional wells. This exploration success benefited from the application of the Common Reflection Surface Stack (e-crsTM), an innovative proprietary algorithms application for processing seismic data that allowed to improve the reservoir structure knowledge thus successfully positioning the discovery well. The development of resources will leverage on the nearby Bhit treatment plant operated by Eni with a 40% interest.
In 2012 the Badhra B North-1 well has been linked to the Bhit plant and started-up in October 2012, flowing at approximately 14 mmcf/d of gas net to Eni.

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Russia
Eni has been present in Russia since 2007 following the acquisition of assets in the Yukos liquidation procedure. In 2012, Eni’s production averaged 11 kboe/d, mainly of gas. Activities are located in the onshore western Siberia, over a developed and undeveloped acreage of 4,996 square kilometers (1,469 square kilometers net to Eni).
The assets in joint venture with Enel (Eni 60%; Enel 40%) are managed by the subholding OOO SeverEnergia (Eni’s interest 29.4%) and own 4 exploration/development blocks located in the Yamal Nenets Region, with significant predominantly gas resources estimated in 1.6 bboe.
Production In 2012, production started-up at the Samburgskoye field located in the Yamal-Nenets area, in Siberia, by means of the first and the second train with an expected production level of 95 kboe/d (28 kboe/d net to Eni). Development activities progressed with completion expected in 2015 and production peak of 146 kboe/d (43 kboe/d net to Eni) in 2016. The gas production is sold to Gazprom under the agreement signed in September 2011 while the condensate production is sold to Novatek under the relevant agreement signed in 2012. Eni retains the right to lift its share of natural gas and sell it to any third parties in the domestic market.
Development Planned activities progressed at the sanctioned Urengoiskoye field. Start-up is expected in 2014.
In June 2012, Eni and the Authority of the Yamal-Nenets Autonomous District signed a Memorandum of Understanding which outlines a plan for implementing joint socio-economic and cultural projects in the area. The agreement includes training initiatives in the Oil&Gas sector, cultural programs and financial support.
Exploration In April 2012, Eni and Rosneft signed an agreement related to a strategic cooperation whereby the two companies will set up joint ventures (Eni 33.33%) for the exploration and development of the Fedynsky and Tsentralno-Barentsevsky licenses, located offshore Russia in the Barents Sea, and Zapadno-Cernomorsky, located offshore Russia in the Black Sea. Finalization is expected in 2013.

  Turkmenistan
Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused in the Western part of the Country over a developed area of 200 square kilometers net to Eni, splitted into four development areas. In 2012, Eni’s production averaged 11 kboe/d.
Exploration and production activities in Turkmenistan are regulated by PSAs.
Production Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap with the Turkmen Authorities, an equivalent amount of oil at the Okarem 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 Turkmenneft, via national grid.

n  America

Ecuador
Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni’s interest 100%) located in the Amazon forest over a developed acreage of 1,985 square kilometers net to Eni. In 2012, Eni’s production averaged 25 kbbl/d.
Exploration and production activities in Ecuador are regulated by a service contract, due to expire in 2023.
Production Production derives from the Villano field, started-up in 1999. Production is processed by means of a Central Production Facility and transported via a pipeline network to the Pacific Coast. Main activities provided to improve the efficiency of oil treatment and transportation facilities.

Trinidad & Tobago
Eni has been present in Trinidad and Tobago since 1970. In 2012, Eni’s production averaged approximately 59 mmcf/d (11 kboe/d). Activity is concentrated offshore North of Trinidad over a developed acreage of 382 square kilometers (66 square kilometers net to Eni).
Exploration and production activities in Trinidad and Tobago are regulated by PSAs.
Production Production is provided by the Chaconia, Ixora, Hibiscus, Poinsettia, Bougainvillea and Heliconia gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.3%). Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidad’s cost and sold under long-term contracts. LNG production is manly sold in the United States. Additional cargoes are sent to alternative destinations on a spot basis.

United States
Eni has been present in the USA since 1968. Activities are performed in the Gulf of Mexico, Alaska and more recently onshore in Texas.
Developed and undeveloped acreage covers 8,032 square kilometers (4,632 square kilometers net to Eni). In 2012, Eni’s oil and gas production averaged 88 kboe/d.
Exploration and production activities in the USA are regulated by concessions.

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Gulf of Mexico
Eni holds interests in 281 exploration and production blocks in the conventional and deep-offshore in the Gulf of Mexico, of which 172 are operated by Eni.
Production The main fields operated by Eni are Allegheny, Appaloosa and Morpeth (Eni’s interest 100%), Longhorn-Leo, Devils Towers and Triton (Eni’s interest 75%) as well as Pegasus (Eni’s interest 58%). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%) and Thunderhawk (Eni’s interest 25%) fields.
Development Development activities mainly concerned: (i) drilling activities at the Allegheny, Appaloosa and Devils Towers operated fields; (ii) production optimization of the Front Runner (Eni’s interest 37.5%), Europa, Popeye (Eni’s interest 50%) and Thunderhawk fields; (iii) the start-up of drilling programs at the Hadrian South (Eni’s interest 30%) and St. Malo (Eni’s interest 1.25%) fields.
Exploration Exploration outlining activity of the Heidelberg oil discovery (Eni’s interest 12.5%) in the Gulf of Mexico yielded positive results and increased recoverable resources up to approximately 200 mmbbl. Studies are underway for a fast track development.
In March 2013, Eni was awarded five offshore blocks, located in Mississippi Canyon and Desoto Canyon.
  Texas
Production
Development activity progressed at the Alliance area (Eni’s interest 27.5%), in the Fort Worth basin in Texas. This area, including gas shale reserves, was acquired following a strategic partnership between Eni and Quicksilver. In particular, 12 new wells entered in production and contributed to a total production of approximately 10 kboe/d net to Eni in the year.

Alaska
Eni holds interests in 111 exploration and development blocks with interests ranging from 10% to 100%, for 54 of these blocks Eni is the operator.
Production The main fields are Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) whit an overall production of 9 kbbl/d net to Eni in 2012.
Development Development activities mainly concerned drilling activities at the Nikaitchuq field and production optimization of Oooguruk field.

Venezuela
Eni has been present in Venezuela since 1998. In 2012, Eni’s production averaged 9 kbbl/d. Activity is concentrated in the Gulf of Venezuela, in the Gulf of Paria and onshore in the Orinoco Oil

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Belt, over a developed and undeveloped acreage of 2,805 square kilometers (1,066 square kilometers net to Eni).
Exploration and production of oil fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP).
Production In March 2013, production started up at the giant Junin 5 field (Eni’s interest 40%) with 35 bbbl of certified heavy oil in place, located in the Orinoco oil belt. Early production of the first phase is expected at plateau of 75 kbbl/d in 2015, targeting a long-term production plateau of 240 kbbl/d to be reached by 2018. The project provides also for the construction of a refinery with a capacity of approximately 350 kbbl/d. The drilling activity started during the year. Eni agreed to finance part of PDVSA’s development costs for the early production phase and engineering activity of refinery plant up to $1.74 billion. Eni signed a loan agreement in the fourth quarter 2012.
In 2012, the start-up of the Central Production Facility (CPF) at the Corocoro field (Eni’s interest 26%) allowed to achieve a production peak of approximately 42 kbbl/d (approximately 11 kbbl/d net to Eni).
Development Venezuelan relevant Authority sanctioned the development plan of the Perla gas discovery, located in the Cardón IV block (Eni’s interest 50%), in the Gulf of Venezuela. PDVSA exercised its 35% back-in right in 2012 and the completion of the stake transfer is expected in 2013. Eni retains the 32.5% joint controlled interest in the company. The early production phase includes the utilization of the already successfully drilled discovery/appraisal wells and the installation of production platforms linked by pipelines to the onshore treatment plant. Target production of approximately 300 mmcf/d is expected in 2015.
The development program will continue with the drilling of additional wells and the upgrading of treatment facilities to reach a production plateau of approximately 1,200 mmcf/d. In 2012 the FIDs of the further phases were sanctioned.
Exploration Exploration activity mainly concerned the Gulfo de Paria Centrale offshore oil exploration block (Eni’s interest 19.5%), where the Punta Sur oil discovery is located and the Punta Pescador and Gulfo de Paria Ovest (Eni’s interest 40%), the latter coinciding with the Corocoro oil field area.
  n  Australia and Oceania

Australia
Eni has been present in Australia since 2001. In 2012, Eni’s production of oil and natural gas averaged 37 kboe/d. Activities are focused on conventional and deep offshore fields over a developed and undeveloped area of 24,318 square kilometers (13,796 square kilometers net to Eni).
Eni’s main producing fields 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) blocks. In the appraisal/development phase Eni retains interest in the NT/P68 (Eni’s interest 50%) and NT/P48 (Eni’s interest 32.5%) areas. Eni holds interest in 9 exploration licenses.
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.

Block JPDA 06-105
Production The Kitan oil field (Eni operator with a 40% interest) started-up in 2011 and produced at peak of 38 kbbl/d in 2012 (approximately 13 kbbl/d net to Eni). Production is supported by 3 sub-sea wells and operated by an FPSO unit for the oil treatment.

Block WA-33-L
Production The Blacktip gas field (Eni’s interest 100%) started-up in 2009 and produced approximately 23 bcf/y in 2012. The project is supported by a production platform and carried by a 108-kilometer long pipeline to an onshore treatment plant with a capacity of 42 bcf/y. Natural gas extracted from this field will be sold under a 25-year contract signed with Power & Water Utility Co.

Block JPDA 03-13
Production The liquids and gas Bayu Undan field started-up in 2004 and produced 176 kboe/d (approximately 12 kboe/d net to Eni) in 2012. Liquid production is supported by 3 treatment platforms and an FSO unit. Production of natural gas is mostly carried by a 500-kilometer long pipeline and is treated at the Darwin liquefaction plant which has a capacity of 3.2 mmtonnes/y of LNG (equivalent to approximately 173 bcf/y of feed gas). LNG is sold to Japanese power generation companies under long-term contracts.

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    Estimated net proved hydrocarbons reserves by geographic area (a)  

(mmboe)

 
(at December 31)   Italy (b)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan (c)   Rest of Asia (d)   America   Australia and Oceania   Total



















                                     
2008                                    
Estimated net proved hydrocarbons reserves   681   525   1,939   1,154   1,336   579   254   132   6,600
Consolidated subsidiaries   681   525   1,922   1,146   1,336   265   235   132   6,242
Equity-accounted entities           17   8       314   19       358
Developed   465   417   1,242   831   647   212   140   62   4,016
Consolidated subsidiaries   465   417   1,229   827   647   168   133   62   3,948
Equity-accounted entities           13   4       44   7       68
Undeveloped   216   108   697   323   689   367   114   70   2,584
Consolidated subsidiaries   216   108   693   319   689   97   102   70   2,294
Equity-accounted entities           4   4       270   12       290



















2009                                    
Estimated net proved hydrocarbons reserves   703   590   1,937   1,163   1,221   545   279   133   6,571
Consolidated subsidiaries   703   590   1,922   1,141   1,221   236   263   133   6,209
Equity-accounted entities           15   22       309   16       362
Developed   490   432   1,278   804   614   183   181   122   4,104
Consolidated subsidiaries   490   432   1,266   799   614   139   168   122   4,030
Equity-accounted entities           12   5       44   13       74
Undeveloped   213   158   659   359   607   362   98   11   2,467
Consolidated subsidiaries   213   158   656   342   607   97   95   11   2,179
Equity-accounted entities           3   17       265   3       288



















2010                                    
Estimated net proved hydrocarbons reserves   724   601   2,119   1,161   1,126   612   373   127   6,843
Consolidated subsidiaries   724   601   2,096   1,133   1,126   295   230   127   6,332
Equity-accounted entities           23   28       317   143       511
Developed   554   405   1,237   817   543   182   167   117   4,022
Consolidated subsidiaries   554   405   1,215   812   543   139   141   117   3,926
Equity-accounted entities           22   5       43   26       96
Undeveloped   170   196   882   344   583   430   206   10   2,821
Consolidated subsidiaries   170   196   881   321   583   156   89   10   2,406
Equity-accounted entities           1   23       274   117       415



















2011                                    
Estimated net proved hydrocarbons reserves   707   630   2,052   1,104   950   886   624   133   7,086
Consolidated subsidiaries   707   630   2,031   1,021   950   230   238   133   5,940
Equity-accounted entities           21   83       656   386       1,146
Developed   540   374   1,194   746   482   134   188   112   3,770
Consolidated subsidiaries   540   374   1,175   742   482   129   162   112   3,716
Equity-accounted entities           19   4       5   26       54
Undeveloped   167   256   858   358   468   752   436   21   3,316
Consolidated subsidiaries   167   256   856   279   468   101   76   21   2,224
Equity-accounted entities           2   79       651   360       1,092



















2012                                    
Estimated net proved hydrocarbons reserves   524   591   1,935   1,129   1,041   852   966   128   7,166
Consolidated subsidiaries   524   591   1,915   1,048   1,041   184   236   128   5,667
Equity-accounted entities           20   81       668   730       1,499
Developed   406   349   1,100   716   458   190   190   107   3,516
Consolidated subsidiaries   406   349   1,080   716   458   108   170   107   3,394
Equity-accounted entities           20           82   20       122
Undeveloped   118   242   835   413   583   662   776   21   3,650
Consolidated subsidiaries   118   242   835   332   583   76   66   21   2,273
Equity-accounted entities               81       586   710       1,377



















(a) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,492 standard cubic feet of gas per barrel of oil equivalent.
(b) Including approximately, 749, 746, 769, 767 and 767 billion of cubic feet of natural gas held in storage at December 31, 2007, 2008, 2009, 2010 and 2011, respectively.
(c) Eni’s proved reserves of the Karachaganak field were determined based on Eni working interest of 29.25% at December 31, 2012 and 32.5% in the previous years.
(d) Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009, completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.

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    Estimated net proved liquids reserves by geographic area  

(mmbbl)

 
(at December 31)   Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan (a)   Rest of Asia (b)   America   Australia and Oceania   Total



















                                     
2008                                    
Estimated net proved liquids reserves   186   277   837   791   911   157   150   26   3,335
Consolidated subsidiaries   186   277   823   783   911   106   131   26   3,243
Equity-accounted entities           14   8       51   19       92
Developed   111   222   624   580   298   97   81   23   2,036
Consolidated subsidiaries   111   222   613   576   298   92   74   23   2,009
Equity-accounted entities           11   4       5   7       27
Undeveloped   75   55   213   211   613   60   69   3   1,299
Consolidated subsidiaries   75   55   210   207   613   14   57   3   1,234
Equity-accounted entities           3   4       46   12       65



















2009                                    
Estimated net proved liquids reserves   233   351   908   777   849   144   169   32   3,463
Consolidated subsidiaries   233   351   895   770   849   94   153   32   3,377
Equity-accounted entities           13   7       50   16       86
Developed   141   218   669   548   291   52   93   23   2,035
Consolidated subsidiaries   141   218   659   544   291   45   80   23   2,001
Equity-accounted entities           10   4       7   13       34
Undeveloped   92   133   239   229   558   92   76   9   1,428
Consolidated subsidiaries   92   133   236   226   558   49   73   9   1,376
Equity-accounted entities           3   3       43   3       52



















2010                                    
Estimated net proved liquids reserves   248   349   997   756   788   183   273   29   3,623
Consolidated subsidiaries   248   349   978   750   788   139   134   29   3,415
Equity-accounted entities           19   6       44   139       208
Developed   183   207   674   537   251   44   87   20   2,003
Consolidated subsidiaries   183   207   656   533   251   39   62   20   1,951
Equity-accounted entities           18   4       5   25       52
Undeveloped   65   142   323   219   537   139   186   9   1,620
Consolidated subsidiaries   65   142   322   217   537   100   72   9   1,464
Equity-accounted entities           1   2       39   114       156



















2011                                    
Estimated net proved liquids reserves   259   372   934   692   653   216   283   25   3,434
Consolidated subsidiaries   259   372   917   670   653   106   132   25   3,134
Equity-accounted entities           17   22       110   151       300
Developed   184   195   638   487   215   34   117   25   1,895
Consolidated subsidiaries   184   195   622   483   215   34   92   25   1,850
Equity-accounted entities           16   4           25       45
Undeveloped   75   177   296   205   438   182   166       1,539
Consolidated subsidiaries   75   177   295   187   438   72   40       1,284
Equity-accounted entities           1   18       110   126       255



















2012                                    
Estimated net proved liquids reserves   227   351   921   688   670   196   273   24   3,350
Consolidated subsidiaries   227   351   904   672   670   82   154   24   3,084
Equity-accounted entities           17   16       114   119       266
Developed   165   180   601   456   203   49   128   24   1,806
Consolidated subsidiaries   165   180   584   456   203   41   109   24   1,762
Equity-accounted entities           17           8   19       44
Undeveloped   62   171   320   232   467   147   145       1,544
Consolidated subsidiaries   62   171   320   216   467   41   45       1,322
Equity-accounted entities               16       106   100       222



















(a) Eni’s proved reserves of the Karachaganak field were determined based on Eni working interest of 29.25% at December 31, 2012 and 32.5% in the previous years.
(b) Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009, completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.

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Eni Fact Book Exploration & Production

    Estimated net proved natural gas reserves by geographic area  

(bcf)

 
(at December 31)   Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan (b)   Rest of Asia (c)   America   Australia and Oceania   Total



















                                     
2008                                    
Estimated net proved natural gas reserves   2,844   1,421   6,324   2,086   2,437   2,430   600   606   18,748
Consolidated subsidiaries   2,844   1,421   6,311   2,084   2,437   911   600   606   17,214
Equity-accounted entities           13   2       1,519           1,534
Developed   2,031   1,122   3,548   1,444   2,005   657   340   221   11,368
Consolidated subsidiaries   2,031   1,122   3,537   1,443   2,005   439   340   221   11,138
Equity-accounted entities           11   1       218           230
Undeveloped   813   299   2,776   642   432   1,773   260   385   7,380
Consolidated subsidiaries   813   299   2,774   641   432   472   260   385   6,076
Equity-accounted entities           2   1       1,301           1,304



















2009                                    
Estimated net proved natural gas reserves   2,704   1,380   5,908   2,212   2,139   2,301   631   575   17,850
Consolidated subsidiaries   2,704   1,380   5,894   2,127   2,139   814   629   575   16,262
Equity-accounted entities           14   85       1,487   2       1,588
Developed   2,001   1,231   3,498   1,468   1,859   756   506   565   11,884
Consolidated subsidiaries   2,001   1,231   3,486   1,463   1,859   539   506   565   11,650
Equity-accounted entities           12   5       217           234
Undeveloped   703   149   2,410   744   280   1,545   125   10   5,966
Consolidated subsidiaries   703   149   2,408   664   280   275   123   10   4,612
Equity-accounted entities           2   80       1,270   2       1,354



















2010                                    
Estimated net proved natural gas reserves   2,644   1,401   6,231   2,245   1,874   2,391   552   544   17,882
Consolidated subsidiaries   2,644   1,401   6,207   2,127   1,874   871   530   544   16,198
Equity-accounted entities           24   118       1,520   22       1,684
Developed   2,061   1,103   3,122   1,554   1,621   774   437   539   11,211
Consolidated subsidiaries   2,061   1,103   3,100   1,550   1,621   560   431   539   10,965
Equity-accounted entities           22   4       214   6       246
Undeveloped   583   298   3,109   691   253   1,617   115   5   6,671
Consolidated subsidiaries   583   298   3,107   577   253   311   99   5   5,233
Equity-accounted entities           2   114       1,306   16       1,438



















2011                                    
Estimated net proved natural gas reserves   2,491   1,427   6,210   2,287   1,648   3,718   1,897   604   20,282
Consolidated subsidiaries   2,491   1,425   6,190   1,949   1,648   685   590   604   15,582
Equity-accounted entities       2   20   338       3,033   1,307       4,700
Developed   1,977   995   3,087   1,441   1,480   552   393   491   10,416
Consolidated subsidiaries   1,977   995   3,070   1,437   1,480   528   385   491   10,363
Equity-accounted entities           17   4       24   8       53
Undeveloped   514   432   3,123   846   168   3,166   1,504   113   9,866
Consolidated subsidiaries   514   430   3,120   512   168   157   205   113   5,219
Equity-accounted entities       2   3   334       3,009   1,299       4,647



















2012                                    
Estimated net proved natural gas reserves   1,633   1,317   5,574   2,414   2,038   3,605   3,804   572   20,957
Consolidated subsidiaries   1,633   1,317   5,558   2,061   2,038   562   449   572   14,190
Equity-accounted entities           16   353       3,043   3,355       6,767
Developed   1,325   925   2,736   1,429   1,401   774   340   459   9,389
Consolidated subsidiaries   1,325   925   2,720   1,429   1,401   372   334   459   8,965
Equity-accounted entities           16           402   6       424
Undeveloped   308   392   2,838   985   637   2,831   3,464   113   11,568
Consolidated subsidiaries   308   392   2,838   632   637   190   115   113   5,225
Equity-accounted entities               353       2,641   3,349       6,343



















(a) Including approximately, 749, 746, 769, 767 and 767 billion of cubic feet of natural gas held in storage at December 31, 2007, 2008, 2009, 2010 and 2011, respectively.
(b) Eni’s proved reserves of the Karachaganak field were determined based on Eni working interest of 29.25% at December 31, 2012 and 32.5% in the previous years.
(c) Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009, completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.

- 34 -


Contents

Eni Fact Book Exploration & Production

   Production of oil and natural gas by Country (a) (b)

(kboe/d)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

199

 

169

 

183

 

186

 

189














Rest of Europe      

249

 

247

 

222

 

216

 

178

     Croatia      

12

 

17

 

8

 

5

 

5

     Norway      

129

 

126

 

123

 

131

 

126

     United Kingdom      

108

 

104

 

91

 

80

 

47














North Africa      

645

 

573

 

602

 

438

 

586

     Algeria      

83

 

83

 

77

 

72

 

78

     Egypt      

240

 

230

 

232

 

236

 

235

     Libya      

306

 

244

 

273

 

112

 

258

     Tunisia      

16

 

16

 

20

 

18

 

15














Sub-Saharan Africa      

335

 

360

 

400

 

370

 

345

     Angola      

126

 

130

 

118

 

102

 

87

     Congo      

87

 

102

 

110

 

108

 

104

     Nigeria      

122

 

128

 

172

 

160

 

154














Kazakhstan      

111

 

115

 

108

 

106

 

102














Rest of Asia      

124

 

135

 

131

 

112

 

129

     China      

8

 

8

 

7

 

8

 

9

     India          

1

 

8

 

4

 

2

     Indonesia      

20

 

21

 

19

 

18

 

18

     Iran      

28

 

35

 

21

 

6

 

3

     Iraq              

5

 

7

 

18

     Pakistan      

56

 

58

 

59

 

58

 

57

     Russia                      

11

     Turkmenistan      

12

 

12

 

12

 

11

 

11














America      

117

 

153

 

143

 

125

 

135

     Brazil                  

1

 

2

     Ecuador      

16

 

14

 

11

 

7

 

25

     Trinidad & Tobago      

9

 

12

 

12

 

10

 

11

     United States      

87

 

119

 

109

 

98

 

88

     Venezuela      

5

 

8

 

11

 

9

 

9














Australia and Oceania      

17

 

17

 

26

 

28

 

37

     Australia      

17

 

17

 

26

 

28

 

37

Total outside Italy      

1,598

 

1,600

 

1,632

 

1,395

 

1,512














       

1,797

 

1,769

 

1,815

 

1,581

 

1,701

of which equity-accounted entities      

20

 

23

 

25

 

26

 

35

Angola      

3

 

3

 

3

 

4

 

2

Brazil                  

1

 

2

Indonesia      

6

 

6

 

6

 

6

 

6

Russia                      

11

Tunisia      

6

 

6

 

5

 

6

 

5

Venezuela      

5

 

8

 

11

 

9

 

9

 

   Oil and natural gas production sold (a)

(mmboe)  

2008

 

2009

 

2010

 

2011

 

2012

                                   
Oil and natural gas production       657.5     645.7     662.3     577.0     622.6  
Change in inventories other       (7.6 )   (3.8 )   (3.4 )   (7.4 )   1.6  
Own consumption of gas       (17.9 )   (19.1 )   (20.9 )   (21.1 )   (25.5 )
Oil and natural gas production sold (c)       632.0     622.8     638.0     548.5     598.7  


















Oil   (mmbbl)   370.24     365.20     361.30     302.61     325.41  
- of which to R&M Division       194.64     224.98     206.41     190.65     185.48  


















Natural gas   (bcf)   1,503     1,479     1,536     1,367     1,501  
- of which to G&P Division       480     444     432     423     435  


















(a) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,492 standard cubic feet of gas per barrel of oil equivalent.
(b) Includes volumes of gas consumed in operations (383, 321, 318, 300 and 281 mmcf/d, in 2012, 2011, 2010, 2009 and 2008, respectively).
(c) Includes 11.2 mmboe of equity-accounted entities production sold in 2012 (7.7, 8, 7.1 and 5.7 mmboe in 2011, 2010, 2009 and 2008, respectively).

- 35 -


Contents

Eni Fact Book Exploration & Production

   Liquids production by Country

(kbbl/d)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

68

 

56

 

61

 

64

 

63














Rest of Europe      

140

 

133

 

121

 

120

 

95

     Norway      

83

 

78

 

74

 

80

 

74

     United Kingdom      

57

 

55

 

47

 

40

 

21














North Africa      

338

 

292

 

301

 

209

 

271

     Algeria      

80

 

80

 

74

 

69

 

71

     Egypt      

98

 

91

 

96

 

91

 

88

     Libya      

147

 

108

 

116

 

36

 

101

     Tunisia      

13

 

13

 

15

 

13

 

11














Sub-Saharan Africa      

289

 

312

 

321

 

278

 

247

     Angola      

121

 

125

 

113

 

95

 

80

     Congo      

84

 

97

 

98

 

87

 

82

     Nigeria      

84

 

90

 

110

 

96

 

85














Kazakhstan      

69

 

70

 

65

 

64

 

61














Rest of Asia      

49

 

57

 

48

 

34

 

44

     China      

6

 

7

 

6

 

7

 

8

     India              

1

       
     Indonesia      

2

 

2

 

2

 

2

 

2

     Iran      

28

 

35

 

21

 

6

 

3

     Iraq              

5

 

7

 

18

     Pakistan      

1

 

1

 

1

 

1

 

1

     Russia                      

2

     Turkmenistan      

12

 

12

 

12

 

11

 

10














America      

63

 

79

 

71

 

65

 

83

     Brazil                  

1

 

2

     Ecuador      

16

 

14

 

11

 

7

 

25

     United States      

42

 

57

 

49

 

48

 

47

     Venezuela      

5

 

8

 

11

 

9

 

9














Australia and Oceania      

10

 

8

 

9

 

11

 

18

     Australia      

10

 

8

 

9

 

11

 

18

Total outside Italy      

958

 

951

 

936

 

781

 

819














       

1,026

 

1,007

 

997

 

845

 

882

of which equity-accounted entities      

14

 

17

 

19

 

19

 

20

Angola      

3

 

3

 

3

 

3

 

2

Brazil                  

1

 

2

Indonesia      

1

 

1

 

1

 

1

 

1

Russia                      

2

Tunisia      

5

 

5

 

4

 

5

 

4

Venezuela      

5

 

8

 

11

 

9

 

9

 

   Oil and natural gas production available for sale (a) (b)

(kboe/d)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

195

 

165

 

178

 

181

 

184

Rest of Europe      

242

 

239

 

214

 

209

 

171

North Africa      

627

 

554

 

582

 

420

 

561

Sub-Saharan Africa      

325

 

349

 

386

 

354

 

327

Kazakhstan      

108

 

113

 

104

 

102

 

98

Rest of Asia      

119

 

130

 

126

 

106

 

121

America      

116

 

150

 

141

 

124

 

133

Australia and Oceania      

16

 

16

 

26

 

27

 

36














       

1,748

 

1,716

 

1,757

 

1,523

 

1,631

of which equity-accounted entities      

19

 

21

 

23

 

23

 

33

North Africa      

5

 

5

 

5

 

5

 

5

Sub-Saharan Africa      

3

 

3

 

3

 

3

 

2

Rest of Asia      

6

 

5

 

5

 

4

 

15

America      

5

 

8

 

10

 

11

 

11

(a) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,492 standard cubic feet of gas per barrel of oil equivalent.
(b) Do not include natural gas consumed in operation.

- 36 -

Contents

Eni Fact Book Exploration & Production

   Natural gas production by Country (a)

(mmcf/d)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

749.9

 

652.6

 

673.2

 

674.3

 

695.1














Rest of Europe      

626.7

 

655.5

 

559.2

 

537.9

 

458.9

     Croatia      

68.7

 

95.5

 

45.3

 

29.9

 

25.4

     Norway      

264.8

 

273.7

 

271.6

 

284.0

 

289.6

     Ukraine                      

0.5

     United Kingdom      

293.2

 

286.3

 

242.3

 

224.0

 

143.4














North Africa      

1,761.6

 

1,614.2

 

1,673.2

 

1,271.5

 

1,733.5

     Algeria      

18.5

 

19.7

 

20.2

 

19.0

 

40.1

     Egypt      

818.4

 

793.7

 

755.1

 

800.7

 

805.9

     Libya      

907.6

 

780.4

 

871.1

 

423.2

 

863.5

     Tunisia      

17.1

 

20.4

 

26.8

 

28.6

 

24.0














Sub-Saharan Africa      

260.7

 

274.3

 

441.5

 

508.0

 

538.7

     Angola      

28.1

 

29.3

 

31.9

 

34.7

 

39.2

     Congo      

12.7

 

27.3

 

67.9

 

119.1

 

120.5

     Nigeria      

219.9

 

217.7

 

341.7

 

354.2

 

379.0














Kazakhstan      

244.7

 

259.0

 

237.0

 

231.0

 

221.7














Rest of Asia      

426.2

 

444.8

 

463.9

 

430.1

 

468.5

     China      

10.9

 

8.2

 

6.7

 

5.0

 

4.4

     India          

3.7

 

36.6

 

19.6

 

10.5

     Indonesia      

99.7

 

104.8

 

94.4

 

84.3

 

84.9

     Pakistan      

315.6

 

328.1

 

326.2

 

321.2

 

310.4

     Russia                      

52.4

     Turkmenistan                      

5.9














America      

311.5

 

424.7

 

396.0

 

334.0

 

283.5

     Trinidad & Tobago      

54.6

 

67.0

 

63.6

 

56.7

 

58.5

     United States      

256.9

 

357.7

 

332.4

 

277.3

 

225.0














Australia and Oceania      

42.2

 

48.6

 

95.7

 

97.8

 

100.8

     Australia      

42.2

 

48.6

 

95.7

 

97.8

 

100.8

Total outside Italy      

3,673.6

 

3,721.1

 

3,866.5

 

3,410.3

 

3,805.6














       

4,423.5

 

4,373.7

 

4,539.7

 

4,084.6

 

4,500.7

of which equity-accounted entities      

35.6

 

38.3

 

35.6

 

34.0

 

88.6

Angola      

0.6

 

0.7

 

0.8

 

1.9

 

4.4

Indonesia      

30.5

 

32.1

 

28.9

 

25.7

 

26.0

Russia                      

52.4

Tunisia      

4.5

 

5.5

 

5.9

 

6.4

 

5.3

Ukraine                      

0.5

 

   Natural gas production available for sale (b)

(mmcf/d)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

725

 

630

 

648

 

648

 

667

Rest of Europe      

588

 

608

 

517

 

498

 

421

North Africa      

1,661

 

1,503

 

1,559

 

1,169

 

1,592

Sub-Saharan Africa      

204

 

213

 

365

 

422

 

444

Kazakhstan      

227

 

241

 

221

 

212

 

202

Rest of Asia      

396

 

417

 

436

 

398

 

423

America      

304

 

416

 

385

 

323

 

273

Australia and Oceania      

38

 

46

 

91

 

93

 

96














       

4,143

 

4,074

 

4,222

 

3,763

 

4,118

of which equity-accounted entities      

25

 

29

 

27

 

24

 

71

North Africa      

1

 

3

 

3

 

4

 

3

Rest of Asia      

24

 

26

 

24

 

20

 

68

(a) From July 1, 2012, Eni has updated the natural gas conversion factor from 5,550 to 5,492 standard cubic feet of gas per barrel of oil equivalent.
(b) Do not include natural gas consumed in operation.

- 37 -

Contents

Eni Fact Book Exploration & Production

    Average realizations  

2008

 

2009

 

2010

 

2011

 

2012

    Consolidated subsidiaries   Equity- accounted entities   Consolidated subsidiaries   Equity- accounted entities   Consolidated subsidiaries   Equity- accounted entities   Consolidated subsidiaries   Equity- accounted entities   Consolidated subsidiaries   Equity- accounted entities
Liquids  


 


 


 


 


($/bbl)                                        
Italy   84.87       56.02       72.19       101.20       100.52    
Rest of Europe   71.90       56.46       67.26       97.56   97.18   100.67   93.11
North Africa   85.38   14.70   56.42   14.60   70.96   16.09   97.63   17.98   103.63   17.93
Sub-Saharan Africa   91.58   98.40   59.75   56.85   78.23   77.78   110.09   108.92   108.34   112.28
Kazakhstan   79.06       52.34       66.74       98.68       102.25    
Rest of Asia   75.29       55.34   9.01   75.20   57.05   101.09   74.98   103.44   40.36
America   88.88   86.42   55.66   56.41   72.84   71.70   101.15   93.03   85.94   93.45
Australia and Oceania   82.80       50.40       73.00       98.05       102.06    
    84.31   56.04   57.02   44.43   72.95   58.86   102.47   84.78   103.06   77.94





 


 


 






Natural gas                                        
($/kcf)                                        
Italy   13.06       9.01       8.71       11.56       10.68    
Rest of Europe   10.55       7.06       7.40       9.72   10.65   10.13   11.64
North Africa   7.15       5.79       6.87       5.95   5.39   8.13   4.91
Sub-Saharan Africa   1.50       1.66       1.87       1.97       2.16    
Kazakhstan   0.53       0.45       0.49       0.57       0.67    
Rest of Asia   5.05   12.40   4.09   7.44   4.35   9.87   5.27   15.68   5.94   6.17
America   8.81       4.05       4.70       4.02       2.90    
Australia and Oceania   9.59       8.14       7.40       7.38       7.73    





 


 


 






    7.99   11.91   5.62   6.81   6.01   8.73   6.44   13.89   7.14   6.16





 


 


 






Hydrocarbons                                        
($/boe)                                        
Italy   78.46       53.17       56.60       77.26       73.24    
Rest of Europe   67.15       49.53       56.00       79.03   66.14   80.79   69.05
North Africa   64.91   13.86   45.47   13.19   55.06   13.53   64.85   20.87   73.06   19.45
Sub-Saharan Africa   81.77   98.40   54.61   56.85   66.35   77.78   88.02   108.92   84.93   112.28
Kazakhstan   51.30       33.65       42.24       62.87       64.92    
Rest of Asia   48.85   69.22   38.21   41.80   42.45   55.04   51.51   85.80   57.98   34.78
America   70.41   86.42   39.29   56.32   47.84   71.70   60.28   93.03   54.61   93.45
Australia and Oceania   71.43       48.63       52.51       61.00       73.82    





 


 


 






    68.21   60.50   46.90   42.82   55.59   56.10   72.20   83.15   73.65   59.25





 


 


 






ENI’s GROUP   2008   2009   2010   2011   2012



 
 
 


Liquids ($/bbl) (a)   84.05   56.95   72.76   102.11   102.58
Natural gas ($/kcf)   8.01   5.62   6.02   6.48   7.12
Hydrocarbons ($/boe)   68.13   46.90   55.60   72.26   73.39











(a) Eni’s average liquids realizations decreased by 1.50 $/bbl in 2011 (1.33 $/bbl, 0.03 $/bbl and 4.13 $/bbl in 2010, 2009 and 2008, respectively) due to the settlement of certain commodity derivatives relating to the sale of 9 mmbbl (28.5 mmbbl, 42.2 mmbbl and 46 mmbbl in 2010, 2009 and 2008, respectively). This deal terminated a multi-year derivative transaction the Company entered into in order to hedge exposure to the variability in cash flows on the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmbbl in the 2008-2011 period.

   Net developed and undeveloped acreage

(square kilometers)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Europe      

30,511

 

31,607

 

29,079

 

26,023

 

27,423

     Italy      

20,409

 

22,038

 

19,097

 

16,872

 

17,556

     Rest of Europe      

10,102

 

9,569

 

9,982

 

9,151

 

9,867

Africa      

249,672

 

158,749

 

152,671

 

137,220

 

142,796

     North Africa      

31,088

 

46,011

 

44,277

 

30,532

 

21,390

     Sub-Saharan Africa      

218,584

 

112,738

 

108,394

 

106,688

 

121,406

Asia      

93,710

 

125,641

 

112,745

 

55,284

 

58,042

     Kazakhstan      

880

 

880

 

880

 

880

 

869

     Rest of Asia      

92,830

 

124,761

 

111,865

 

54,404

 

57,173

America      

12,043

 

11,523

 

11,187

 

10,209

 

9,075

Australia and Oceania      

29,558

 

20,342

 

15,279

 

25,685

 

13,834














Total      

415,494

 

347,862

 

320,961

 

254,421

 

251,170














- 38 -


Contents

Eni Fact Book Exploration & Production

   Principal oil and natural gas interests at December 31, 2012
   

Commencement of operations

 

Number of interests

   

Gross developed (a) (b) acreage

   

Net developed (a) (b) acreage

 

Gross undeveloped (a) acreage

 

Net undeveloped (a) acreage

 

Type of fields/acreage

   

Number of producing fields

 

Number of other fields




















EUROPE       288   17,191   11,150   27,199   16,273       135   99



















Italy   1926   151   10,847   9,011   11,438   8,545   Onshore/Offshore   83   68
Rest of Europe       137   6,344   2,139   15,761   7,728       52   31
     Croatia   1996   2   1,975   987           Offshore   9   3
     Norway   1965   52   2,264   346   6,226   2,330   Offshore   17   16
     Poland   2010   3           1,968   1,968   Onshore        
     Ukraine   2011   12   50   30   3,840   1,911   Onshore   1    
     United Kingdom   1964   65   2,055   776   647   138   Offshore   25   12
     Other Countries       3           3,080   1,381   Offshore        



















AFRICA       287   64,075   19,891   192,079   122,905       272   143



















North Africa       119   31,988   14,066   17,691   7,324       103   60
     Algeria   1981   41   2,640   1,071   1,158   161   Onshore   32   11
     Egypt   1954   57   4,937   1,771   7,845   2,819   Onshore/Offshore   40   27
     Libya   1959   10   17,947   8,950   8,688   4,344   Onshore/Offshore   11   15
     Tunisia   1961   11   6,464   2,274           Onshore/Offshore   20   7
Sub-Saharan Africa       168   32,087   5,825   174,388   115,581       169   83
     Angola   1980   78   4,804   636   20,037   5,443   Onshore/Offshore   47   31
     Congo   1968   26   1,835   1,027   7,681   4,008   Onshore/Offshore   24   6
     Dem. Republic of Congo   2010   1           478   263   Onshore        
     Gabon   2008   6           7,615   7,615   Onshore/Offshore        
     Ghana   2009   2           5,144   1,885   Offshore       2
     Kenya   2012   3           35,724   35,724   Offshore        
     Liberia   2012   3           8,145   2,036   Offshore        
     Mozambique   2007   1           12,956   9,069   Offshore       8
     Nigeria   1962   41   25,448   4,162   10,838   3,484   Onshore/Offshore   98   36
     Togo   2010   2           6,192   6,192   Offshore        
     Other Countries       5           59,578   39,862   Onshore        



















ASIA       73   17,126   5,778   101,554   52,264       39   32



















Kazakhstan   1992   6   324   95   4,609   774   Onshore/Offshore   1   5
Rest of Asia       67   16,802   5,683   96,945   51,490       38   27
     China   1984   11   200   39   10,456   10,456   Offshore   11    
     India   2005   11   206   109   16,546   6,099   Onshore/Offshore   4   3
     Indonesia   2001   13   1,735   656   28,490   19,078   Onshore/Offshore   7   15
     Iran   1957   4   1,456   820           Onshore/Offshore   2    
     Iraq   2009   1   1,074   352           Onshore   1    
     Pakistan   2000   19   8,430   2,478   20,210   8,055   Onshore/Offshore   10   1
     Russia   2007   4   3,501   1,029   1,495   440   Onshore   1   8
     Timor Leste   2006   2           5,148   4,118   Offshore        
     Turkmenistan   2008   1   200   200           Onshore   2    
     Other Countries       1           14,600   3,244   Offshore        



















AMERICA       409   4,571   3,074   14,180   6,001       61   20
     Ecuador   1988   1   1,985   1,985           Onshore   1   1
     Trinidad & Tobago   1970   1   382   66           Offshore   5   2
     United States   1968   393   1,826   925   6,206   3,707   Onshore/Offshore   54   13
     Venezuela   1998   6   378   98   2,427   968   Onshore/Offshore   1   3
     Other Countries       8           5,547   1,326   Offshore       1



















AUSTRALIA AND OCEANIA       15   1,980   1,046   23,102   12,788       4   2



















     Australia   2001   14   1,980   1,046   22,338   12,750   Offshore   4   2
     Other Countries       1           764   38   Offshore        



















Total       1,072   104,943   40,939   358,114   210,231       511   296



















(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.

- 39 -

Contents

Eni Fact Book Exploration & Production

   Capital expenditure

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Acquisition of proved and unproved properties      

836

 

697

     

754

 

43

     North Africa      

626

 

351

     

57

 

14

     Sub-Saharan Africa      

210

 

73

     

697

 

27

     Rest of Asia          

94

           
     America          

179

         

2














Exploration      

1,918

 

1,228

 

1,012

 

1,210

 

1,850

     Italy      

135

 

40

 

34

 

38

 

32

     Rest of Europe      

227

 

113

 

114

 

100

 

151

     North Africa      

379

 

317

 

84

 

128

 

153

     Sub-Saharan Africa      

485

 

284

 

406

 

482

 

1,142

     Kazakhstan      

16

 

20

 

6

 

6

 

3

     Rest of Asia      

187

 

159

 

223

 

156

 

193

     America      

441

 

243

 

119

 

60

 

80

     Australia and Oceania      

48

 

52

 

26

 

240

 

96














Development      

6,429

 

7,478

 

8,578

 

7,357

 

8,304

     Italy      

570

 

689

 

630

 

720

 

744

     Rest of Europe      

598

 

673

 

863

 

1,596

 

2,008

     North Africa      

1,246

 

1,381

 

2,584

 

1,380

 

1,299

     Sub-Saharan Africa      

1,717

 

2,105

 

1,818

 

1,521

 

1,931

     Kazakhstan      

968

 

1,083

 

1,030

 

897

 

719

     Rest of Asia      

355

 

406

 

311

 

361

 

641

     America      

655

 

706

 

1,187

 

831

 

953

     Australia and Oceania      

320

 

435

 

155

 

51

 

9














Other expenditure      

98

 

83

 

100

 

114

 

110














       

9,281

 

9,486

 

9,690

 

9,435

 

10,307














 

   Reserves life index (a)

(years)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy      

9.3

 

11.4

 

10.9

 

10.4

 

7.6

Rest of Europe      

5.8

 

6.6

 

7.4

 

8.0

 

9.0

North Africa      

8.2

 

9.3

 

9.6

 

12.8

 

9.0

Sub-Saharan Africa      

9.5

 

8.9

 

7.9

 

8.2

 

8.9

Kazakhstan      

32.9

 

29.0

 

28.7

 

24.5

 

28.1

Rest of Asia      

12.8

 

11.1

 

12.8

 

21.7

 

18.1

America      

5.9

 

5.0

 

7.2

 

13.6

 

19.7

Australia and Oceania      

21.0

 

21.5

 

13.1

 

12.8

 

9.8














       

10.0

 

10.2

 

10.3

 

12.3

 

11.5














 

   Reserves replacement ratio (a)

 

2008

 

2009

 

2010

 

2011

 

2012

(%)   organic   all sources   organic   all sources   organic   all sources   organic   all sources   organic   all sources
                                         
Italy   9   10   135   136   121   107   72   75   34   -
Rest of Europe   -   -   173   174   103   102   140   136   37   37
North Africa   118   118   99   99   167   167   58   58   40   40
Sub-Saharan Africa   117   142   105   106   91   90   63   58   138   117
Kazakhstan   921   776   -   -   -   -   -   -   467   337
Rest of Asia   124   248   42   -   211   212   768   771   12   12
America   40   40   102   144   274   273   646   647   855   786
Australia and Oceania   75   75   117   112   6   5   155   163   51   51





 


 


 






    130   135   93   96   127   125   143   142   147   107





















(a) Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009, completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.
(b) Net of updating the natural gas conversion factor.

- 40 -


Contents

Eni Fact Book Exploration & Production

   Exploratory wells activity
   

Net wells completed

 

Wells in progress at Dec. 31 (a)

   
 
   

2010

 

2011

 

2012

 

2012

   
 
 
 
(units)  

Productive

 

Dry (b)

 

Productive

 

Dry (b)

 

Productive

 

Dry (b)

 

Gross

 

Net


 
 
 
 
 
 
 
 
Italy       0.5           1.0       5.0   3.4
Rest of Europe   1.7   1.1   0.3   0.7   1.0   1.0   19.0   7.2
North Africa   9.3   8.1   6.2   3.4   6.3   11.3   17.0   11.7
Sub-Saharan Africa   2.3   4.7   0.6   2.6   4.5   5.1   57.0   24.2
Kazakhstan                       0.8   8.0   1.4
Rest of Asia   1.0   2.8   0.2   7.6   0.5   0.6   27.0   11.2
America       6.3   2.5           0.1   10.0   2.4
Australia and Oceania   1.0   0.4       1.4       0.4   1.0   0.5
    15.3   23.9   9.8   15.7   13.3   19.3   144.0   62.0

















 

   Development wells activity
   

Net wells completed

 

Wells in progress at Dec. 31 (a)

   
 
   

2010

 

2011

 

2012

 

2012

   
 
 
 
(units)  

Productive

 

Dry (b)

 

Productive

 

Dry (b)

 

Productive

 

Dry (b)

 

Gross

 

Net


 
 
 
 
 
 
 
 
Italy   23.9   1.0   25.3       18.0   1.0   3.0   2.6
Rest of Europe   2.9   0.2   3.3   0.3   2.9   0.6   9.0   1.8
North Africa   44.3   0.3   55.9   1.1   46.0   1.6   19.0   8.1
Sub-Saharan Africa   28.0   2.5   28.2   1.0   27.4   0.3   19.0   4.4
Kazakhstan   1.8       1.3       1.4       16.0   2.9
Rest of Asia   41.7   1.8   39.2   2.5   41.2   0.1   36.0   14.2
America   27.6   0.5   27.6       23.1       7.0   2.9
Australia and Oceania   1.5       0.4                    
    171.7   6.3   181.2   4.9   160.0   3.6   109.0   36.9

















 

   Productive oil and gas wells (c)
   

2012

   
   

Oil wells

 

Natural gas wells

   
 
(units)  

Gross

 

Net

 

Gross

 

Net


 
 
 
 
Italy   242.0   196.1   621.0   536.6
Rest of Europe   460.0   69.7   180.0   89.2
North Africa   1,447.0   702.3   154.0   59.2
Sub-Saharan Africa   2,858.0   542.2   383.0   27.6
Kazakhstan   102.0   29.1        
Rest of Asia   642.0   404.1   889.0   336.6
America   169.0   90.5   344.0   122.8
Australia and Oceania   7.0   3.8   14.0   3.3
    5,927.0   2,037.8   2,585.0   1,175.3









(a) Includes temporary suspended wells pending further evaluation.
(b) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.
(c) Includes 2,203 gross (747.7 net) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.

- 41 -


Contents

Eni Fact Book Gas & Power

   Gas & Power

 

   Key performance indicators (*)

       

2008  

 

2009  

 

2010  

 

2011  

 

2012  














Employees injury frequency rate   (No. of accidents per million of worked hours)   4.72     3.15     3.97     2.44     1.84  
Contractors injury frequency rate       3.43     2.32     4.00     5.22     3.64  


















Net sales from operations (a)   (euro million)   36,122     29,272     27,806     33,093     36,200  
Operating profit       2,330     1,914     896     (326 )   (3,221 )
Adjusted operating profit       1,778     2,022     1,268     (247 )   354  
     Marketing       1,309     1,721     923     (657 )   45  
     International transport       469     301     345     410     309  
Adjusted net profit       784     892     1,267     252     473  
EBITDA pro-forma adjusted       2,970     2,975     2,562     949     1,314  
     Marketing       2,344     2,334     1,863     257     856  
     International transport       626     641     699     692     458  
Capital expenditure       431     207     265     192     225  


















Worldwide gas sales (b)   (bcm)   104.23     103.72     97.06     96.76     95.32  
LNG sales (c)       12.0     12.9     15.0     15.7     14.6  
Customers in Italy   (million)   6.63     6.88     6.88     7.10     7.45  
Electricity sold   (TWh)   29.93     33.96     39.54     40.28     42.58  


















Employees at year end   (units)   5,312     5,147     5,072     4,795     4,752  
Direct GHG emissions   (mmtonnes CO2 eq)   12.18     12.40     13.41     12.77     12.70  
Customer satisfaction index (PSC) (d)   (%)   75.3     83.7     87.4     88.6     89.8  
Water consumption/withdrawals per kWh eq produced   (cm/kW eq)   0.015     0.015     0.013     0.014     0.012  


















(*) Following the divestment plan of the Regulated Businesses in Italy, results of the Gas & Power Division include Marketing and International transport activities. Reference periods have been restated accordingly.
(a) Before elimination of intragroup sales.
(b) Include volumes marketed by the Exploration & Production Division of 2.73 bcm (6.00, 6.17, 5.65 and 2.86 bcm in 2008, 2009, 2010 and 2011, respectively).
(c) Refer to LNG sales of the Gas & Power Division (included in worldwide gas sales) and the Exploration & Production Division.
(d) 2012 figure is calculated as the average of the CSS detected by the AEEG in the first half of 2012 and the result detected by the Eni satisfaction survey in the second half of 2012.


Performance of the year

Commercial agreements in the Far East
In January 2013, Eni signed a trilateral agreement with Korea Gas Corporation and Japanese company Chubu Electric Power Company for the sale of 28 loads of LNG (liquefied natural gas) corresponding to 1.7 million tonnes of LNG in the 2013-2017 period.

Entry in the French and Belgian markets
I In October 2012, Eni launched its brand in the gas retail market in France and in the business and retail gas and power market in Belgium. The Eni brand substituted the local operators ones acquired in the past few years with the aim of becoming one of the major retail operators in France and Belgium while consolidating its leadership on the Belgian business market.

I In 2012, Eni’s continuous commitment and the resources dedicated to safety allowed to improve significantly the main accident frequency rates. In particular the positive trend was confirmed for employees (down 24.6% from 2011), while the rate for contractors returned to levels lower than in 2010, improving by 30% from 2011.

  I With regard to sales to residentials in Italy, Eni’s customers satisfaction score (checked twice a year by the Authority for electricity and gas) reached 89.8 (basis 100) increasing by 1.2 percentage points from 2011.

I In 2012, the water consumption rate of EniPower’s plants declined both in absolute value (down 11.2% from 2011) and per kWh eq produced (down 13.8%).

I In 2012, adjusted net profit was euro 473 million, almost doubled from 2011 due to a better performance of the Marketing business in a scenario characterized by weak demand and rising competitive pressure. This performance offset the decline in selling prices reflecting in part the benefits associated with the renegotiations of the supply contracts, certain of which have been finalized after 2011 year-end and the improvement in the supply mix also following the full recovery of Libyan supplies.

- 42 -


Contents

Eni Fact Book Gas & Power

I Worldwide gas sales decreased by 1.5% to 95.32 bcm due to lower European demand and competitive pressures. Sales in Italy were in line with 2011, while they declined slightly in European markets, in particular in Benelux due to competitive pressure and in the Iberian Peninsula due to the divestment of Galp.   I Electricity sales of 42.58 TWh increased by 2.30 TWh from 2011, up 5.7%.

I Capital expenditure of euro 225 million concerned essentially flexibility and upgrading of combined cycle power stations (euro 131 million) and initiatives in gas marketing (euro 81 million).

Eni’s Gas & Power segment engages in all phases of the natural gas value chain: supply, trading and marketing of natural gas and LNG. This segment also includes power generation and marketing of electricity.
Eni’s leading position in the European gas market is ensured by a set of competitive advantages, including our multi-Country approach, long-term gas availability, access to infrastructures, market knowledge and a strong customer base, in addition to long-term relations with producing Countries. Furthermore, integration with our upstream operations provides valuable growth options whereby the Company targets to monetize its large gas reserves.

1. Marketing

1.1 Natural gas

Supply
The supply of natural gas is a free activity where prices are determined by free negotiations of demand and supply involving natural gas resellers and producers.
In order to secure long-term access to gas availability, Eni has signed a number of long-term gas supply contracts with key producing countries that supply the European gas markets. These contracts have been ensuring approximately 80 bcm of gas availability from 2010 (including the Eni Gas & Power NV portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 16 years and a pricing mechanism that indexed the cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.).
Eni could also leverage on the availability of natural gas deriving from equity production, the access to all phases of the LNG chain (liquefaction, shipping and regasification) and to other gas infrastructures, and by trading and risk management activity.
Eni’s long-term gas requirements are met by natural gas from a total

 

of 18 Countries, where Eni also holds upstream activities and by access to European spot markets.
In 2012, Eni’s consolidated subsidiaries supplied 86.74 bcm of natural gas, representing an increase of 3.36 bcm, or 4% from 2011. Gas volumes supplied outside Italy (79.19 bcm from consolidated companies), imported in Italy or sold outside Italy, represented approximately 91% of total supplies, an increase of 3.03 bcm, or 4%, from 2011, mainly reflecting higher volumes purchased from Libya (up 4.23 bcm), almost tripled from 2011 when the GreenStream gas pipeline had been shutdown. Increased volumes were purchased also from the Netherlands (up 0.95 bcm) and from Algeria (up 0.51 bcm). Declines were recorded in gas purchases from Russia (down 1.17 bcm) due to the recovery of Libyan supplies, the UK (down 0.37 bcm) and Norway (down 0.17 bcm).

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Contents

Eni Fact Book Gas & Power

Supplies in Italy (7.55 bcm) increased slightly from 2011 also due to higher domestic production that offset the decline of mature fields. In 2012, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (1.9 bcm); (iii) Libyan fields (1.8 bcm) increasing by almost 1.2 bcm due to the effect of force majeure recorded in 2011; (iv) the United States (1.6 bcm); (v) other European areas (Croatia with 0.2 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 18 bcm representing 18% of total volumes available for sale.

Marketing in Italy
Eni operates in a liberalized market where energy customers are allowed to choose the supplier of gas and, according to their specific needs, to evaluate the quality of services and offers. In Italy, the Authority for Electricity and Gas regulates and defines the tariff system for the sole retail market, in particular for those customers who have not chosen their supplier on the free market (when the liberalization of the sector occurred, in 2010), mainly residentials and small enterprises. The Italian market includes four segments of customers: large businesses, the power generation sector, wholesalers and residential customers.
Large businesses and power generation utilities are directly

  linked to the national and regional natural gas network. Wholesalers mainly include local selling companies that resell natural gas to residential customers through low pressure distribution networks as well as distributors of natural gas for automotive use. Residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and small businesses (also referred to as the middle market) located in large metropolitan areas and urban centers. Overall, Eni supplies approximately 2,600 clients including large businesses, power generation utilities, wholesalers and distributors of natural gas for automotive use. Residential users are 7.45 million and include households, professionals, small and medium sized enterprises, and public bodies located all over Italy.
Despite a 4% decline in natural gas demand, sales volumes on the Italian market were substantially stable at 34.78 bcm (up 0.10 bcm, or 0.3% from 2011). Lower sales to the power generation segment (down 1.76 bcm), industrial customers (down 0.51 bcm) and wholesalers (down 0.28 bcm), due to the negative scenario and increasing competitive pressure, were offset by higher sales on the Italian exchange for gas and spot markets (up 2.28 bcm) and, at a lower extent, to the residential segment (up 0.22 bcm) reflecting efficient commercial initiatives. Sales to shippers were down 0.51 bcm, or 15.7%, due to the discontinuance of certain supply contracts despite the recovery of Libyan supplies.

 

    Sales and market shares on the Italian gas market  

(bcm)

 

2011

 

2012

   
    Volumes sold   Market share (%)   Volumes sold   Market share (%)   % Ch. 2012
vs 2011












Italy to third parties   28.47   36.5   28.35   37.8   (0.4 )
     Wholesalers   5.16       4.65       (9.9 )
     Italian gas exchange and spot markets   5.24       7.52       43.5  
     Industries   7.21       6.93       (3.9 )
     Medium-sized enterprises and services   0.88       0.81       (8.0 )
     Power generation   4.31       2.55       (40.8 )
     Residential   5.67       5.89       3.9  
Own consumption   6.21       6.43       3.5  
TOTAL SALES IN ITALY   34.68   44.5   34.78   46.4   0.3  
Gas demand (a)   77.92       74.91       (3.9 )












(a) Source: Italian Ministry of Economic Development.

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Contents

Eni Fact Book Gas & Power

Marketing outside Italy
Despite a challenging market scenario and rising competitive pressures, Eni intends to organically grow in particular in certain European key market such as Germany/Austria and Benelux, leveraging on our brand awareness, our multi-Country approach and on a pan-European commercial platform as well as delivering innovative and tailor-made offering structures to best suit customers’ needs by providing complex pricing formulas with flexibility on volumes and different ways to manage pricing.

In 2012, sales of natural gas were 95.32 bcm, down 1.44 bcm or 1.5% from 2011. Sales included Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and Exploration

  & Production sales in Europe and in the Gulf of Mexico.
Sales on target markets in Europe of 48.29 bcm showed a slight decline from 2011 (down 2.9%). This decline was mainly due to a decline in sales in Benelux (down 3.53 bcm) due to rising competitive pressure and in the Iberian Peninsula (down 1.19 bcm) due to the exclusion of Galp sales after the loss of control offset only in part by increases recorded in France (up 1.35 bcm) and Germany/Austria (up 1.31 bcm) due to commercial initiatives performed.
Sales to markets outside Europe increased by 0.55 bcm due to higher LNG sales in the Far East, in particular in Japan. Exploration & Production sales in Northern Europe and in the United States (2.73 bcm) declined by 0.13 bcm due to lower sales in the North Sea.

 

   Gas sales by market

(bcm)  

2008

 

2009

 

2010

 

2011

 

2012

                         
ITALY       52.87   40.04   34.29   34.68   34.78
Wholesalers       7.52   5.92   4.84   5.16   4.65
Gas release       3.28   1.30   0.68        
Italian gas exchange and spot markets       1.89   2.37   4.65   5.24   7.52
Industries       9.59   7.58   6.41   7.21   6.93
Medium-sized enterprises and services       1.05   1.08   1.09   0.88   0.81
Power generation       17.69   9.68   4.04   4.31   2.55
Residential       6.22   6.30   6.39   5.67   5.89
Own consumption       5.63   5.81   6.19   6.21   6.43













INTERNATIONAL SALES       51.36   63.68   62.77   62.08   60.54













Rest of Europe       43.03   55.45   54.52   52.98   51.02
Importers in Italy       11.25   10.48   8.44   3.24   2.73
European markets       31.78   44.97   46.08   49.74   48.29
Iberian Peninsula       7.44   6.81   7.11   7.48   6.29
Germany/Austria       5.29   5.36   5.67   6.47   7.78
Benelux       4.77   15.72   15.64   13.84   10.31
Hungary       2.82   2.58   2.36   2.24   2.02
UK/Northern Europe       3.21   4.31   4.45   4.21   4.75
Turkey       4.93   4.79   3.95   6.86   7.22
France       2.66   4.91   6.09   7.01   8.36
Other       0.66   0.49   0.81   1.63   1.56













Extra European markets       2.33   2.06   2.60   6.24   6.79













E&P in Europe and in the Gulf of Mexico       6.00   6.17   5.65   2.86   2.73













WORLDWIDE GAS SALES       104.23   103.72   97.06   96.76   95.32













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Contents

Eni Fact Book Gas & Power

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

Benelux
Through a direct presence and the integration with its affiliate Eni Gas & Power NV, Eni holds a key position in the Benelux Countries (Belgium, the Netherlands and Luxembourg), in particular in Belgium, which are a strategic hub of the continental gas spot market in Western Europe, thanks to their central position and high level of interconnectivity with the gas transit networks of Central and Northern Europe. In 2012, sales in Benelux were mainly directed to industrial companies, wholesalers and power generation and amounted to 10.31 bcm, down by 3.53 bcm, or 25.5%, due to rising competitive pressure, in particular in the wholesalers segment.
In October 2012, Eni launched its brand in the retail gas and power market in Belgium. The Eni brand substituted the local operators ones acquired in the past few years with the aim of becoming one of the major retail operators in the Country while consolidating its leadership on the Belgian business market.

France
Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the retail and middle market segments. Eni is present in the French market through its direct commercial activities and through its subsidiary Eni Gas & Power France SA. In 2012, sales in France amounted to 8.36 bcm (7.01 bcm in 2011), an increase of 1.35 bcm, or 19.3%, from a year ago.
In October 2012, Eni launched its brand in the gas retail market in France. The Eni brand substituted the local operators ones acquired in the past few years with the aim of becoming one of the major retail operators in the Country.

Germany/Austria
Eni is present in the German natural gas market through a direct marketing structure which sold in 2012 approximately 4.40 bcm in Germany and 0.94 bcm in Austria and its associate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.48 bcm in 2012 (2.24 bcm being Eni’s share).
In 2012, sales in the Germany/Austria market amounted to 7.78 bcm, an increase of 1.31 bcm, or 20.2%, from a year ago.

  Spain
Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2012, UFG gas sales in Europe amounted to 4.82 bcm (2.41 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 2012, Eni sales in Spain amounted to 5.24 bcm representing a slight decrease from a year ago. In 2012, total sales in the region amounted to 6.29 bcm, a decrease of 1.19 bcm, or 15.9% from a year ago.

Turkey
Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2012, sales amounted to 7.22 bcm, an increase of 0.36 bcm, or 5.2% from a year ago.

UK
Eni, through its subsidiary ETS, markets in the UK the equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2012, sales amounted to 4.75 bcm, an increase of 12.8% from a year ago.

Deborah Gas Storage Project in the Hewett area, UK
The Deborah Gas Storage Project concerns the development of an offshore storage site on the Deborah field in block UKCS 48/30 in the North Sea, which will be connected to the National Transmission System at Bacton, via the Company’s existing production terminal. In the 2010-2011 period significant progress has been made by completing the Front End Engineering Design ("FEED"), obtaining most of the necessary approvals for the performing of storage activity. In 2011 the company structure has been changed with Eni selling part of its interest in the project. Project FID depends on ongoing negotiations with potential buyers for the allocation of the long-term storage capacity.

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Contents

Eni Fact Book Gas & Power

1.2 LNG
Eni is present in all phases of the LNG business: liquefaction, shipping, re-gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa and elsewhere in the world. The LNG business has been deeply impacted by the economic downturn and oversupply affecting the European gas market, as well as by structural modifications in the US market where large availability of gas from unconventional sources has reduced the Country’s dependence on gas imports via LNG. In expansion the activity on Far East premium markets.
Eni’s main assets and projects in the LNG business are described below.

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

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

Spain
Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto re-gasification plant, near Valencia, with a capacity of 8.8 bcm/y and a LNG storage capacity of 450,000 cm which will be increased to 600,000 cm after the ongoing construction of a fourth tank. At present, Eni’s re-gasification capacity entitlement amounts to 1.9 bcm/y of gas.
Eni through Unión Fenosa Gas also holds a 9.45% interest in the El Ferrol re-gasification plant, located in Galicia, with a treatment capacity of approximately 3.6 bcm/y, of which 0.34 bcm/y being Eni’s capacity entitlements. the LNG storage capacity of the plant is 300,000 cm in two tanks.

United States
Eni owns a capacity entitlement to treat LNG on Cameron terminal in Louisiana (USA) where operations commenced in the third quarter of 2009. In consideration of a changed demand outlook, on March 1, 2010, Eni renegotiated certain terms of the contract with US company Cameron LNG, relating to the farming out of

  a share of re-gasification capacity of the Cameron terminal. The new agreement provides that Eni will be entitled to a daily send-out of 572,000 mmbtu (approximately 5.7 bcm/y) and a dedicated storage capacity of 160 kcm, giving Eni more flexibility in managing seasonal swings in gas demand. Furthermore, keeping account of the current oversupply of the US gas market, the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant has been rescheduled with start-up in 2017.

Pascagoula. This project is part of an upstream development project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 bcm/y) destined to the North American market in order to monetize part of the Company’s gas reserves. As part of the downstream leg of the project, Eni signed a 20 year contract with Gulf LNG to buy 5.8 bcm/y of the re-gasification capacity of the plant near Pascagoula in Mississippi. The start-up of the re-gasification facility commenced in the fourth quarter of 2012.
At the same time Eni USA Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 bcm/y of re-gasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG. Due to the negative prospects for marketing in the USA, Eni, through its subsidiary and the other shareholders have drafted a new development plan for the contract that minimizes the supplies to the US market and directs them to other more profitable markets.

1.3 Power generation
Eni’s power generation activity is conducted in the Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and Bolgiano plants, as well as in certain photovoltaic sites in Italy.
In 2012, power production was 25.67 TWh, up 0.44 TWh, or 1.7% from 2011, mainly due to higher production at the Ferrara plant, offset in part by decreases registered at the Ferrera Erbognone and Ravenna plants.
In 2012 electricity sales (42.58 TWh) were directed to the free market (75%), the Italian power exchange (14%), industrial sites (8%) and others (3%). The 5.7% increase was due to growth in the client base as a result of effective marketing policies, despite weak domestic demand.
As of December 31, 2012, installed operational capacity was 5.3 GW (5.3 GW as of December 31, 2011).
Power availability in 2012 was supported by the growth in electricity trading activities (up 1.86 TWh, or 12.4%) due to higher volumes traded on the Italian power Exchange benefiting from lower purchase prices.
The power generation development plan mainly refers to the upgrading and flexibilization of combined cycle plants and the revamping of the Bolgiano plant.

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Contents

Eni Fact Book Gas & Power

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

  Eni owns capacity entitlements in an extensive network of international high pressure pipelines enabling the Company to import natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya to Italy. The Company participates to both entities which operate the pipelines and entities which manage transport rights. A description of the main international pipelines currently participated or operated by Eni is provided below:
- the TTPC pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. In 2009 the pipeline was upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 bcm/y;
- the TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;
- the GreenStream pipeline, jointly-owned with the Libyan National Oil Company, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y (expandable to 11 bcm/y) and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system;
- 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.

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Contents

Eni Fact Book Gas & Power

   Supply of natural gas

(bcm)  

2008

 

2009

 

2010

 

2011

 

2012

                                   
Italy       8.00     6.86     7.29     7.22     7.55  


















Outside Italy                                  
     Russia       22.91     22.02     14.29     21.00     19.83  
     Algeria (including LNG)       19.22     13.82     16.23     13.94     14.45  
     Libya       9.87     9.14     9.36     2.32     6.55  
     Netherlands       9.83     11.73     10.16     11.02     11.97  
     Norway       6.97     12.65     11.48     12.30     12.13  
     United Kingdom       3.12     3.06     4.14     3.57     3.20  
     Hungary       2.84     0.63     0.66     0.61     0.61  
     Qatar (LNG)       0.71     2.91     2.90     2.90     2.88  
     Other supplies of natural gas       4.07     4.49     4.42     6.16     5.43  
     Other supplies of LNG       2.11     1.34     1.56     2.34     2.14  
        81.65     81.79     75.20     76.16     79.19  


















Total supplies of Eni’s own companies       89.65     88.65     82.49     83.38     86.74  


















Offtake from (input to) storage       (0.08 )   1.25     (0.20 )   1.79     (1.35 )
Network losses, measurement differences and other changes       (0.25 )   (0.30 )   (0.11 )   (0.21 )   (0.28 )


















AVAILABLE FOR SALE ENI’S CONSOLIDATES SUBSIDIARIES       89.32     89.60     82.18     84.96     85.11  
Available for sale of Eni’s affiliates       8.91     7.95     9.23     8.94     7.48  
E&P volumes in Europe and Gulf of Mexico       6.00     6.17     5.65     2.86     2.73  
GAS VOLUMES AVAILABLE FOR SALE       104.23     103.72     97.06     96.76     95.32  


















 

   Gas sales by entity

(bcm)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Sales of consolidated companies       89.32   89.60   82.00   84.37   84.67













Italy (including own consumption)       52.82   40.04   34.23   34.60   34.66
Rest of Europe       35.61   48.65   46.74   45.16   44.94
Outside Europe       0.89   0.91   1.03   4.61   5.07













Sales of Eni’s affiliates (net to Eni)       8.91   7.95   9.41   9.53   7.92













Italy       0.05       0.06   0.08   0.12
Rest of Europe       7.42   6.80   7.78   7.82   6.08
Outside Europe       1.44   1.15   1.57   1.63   1.72













E&P in Europe and in the Gulf of Mexico       6.00   6.17   5.65   2.86   2.73













Worldwide gas sales       104.23   103.72   97.06   96.76   95.32













 

   LNG sales

(bcm)  

2008

 

2009

 

2010

 

2011

 

2012

                         
G&P sales       8.4   9.8   11.2   11.8   10.5













Italy       0.3   0.1   0.2        
Rest of Europe       7.0   8.9   9.8   9.8   7.6
Extra European markets       1.1   0.8   1.2   2.0   2.9
E&P sales       3.6   3.1   3.8   3.9   4.1













Liquefaction plants:                        
Bontang (Indonesia)       0.7   0.8   0.7   0.6   0.6
Point Fortin (Trinidad & Tobago)       0.5   0.5   0.6   0.4   0.5
Bonny (Nigeria)       2.0   1.4   2.2   2.5   2.7
Darwin (Australia)       0.4   0.4   0.3   0.4   0.3













Total LNG sales       12.0   12.9   15.0   15.7   14.6













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Contents

Eni Fact Book Gas & Power

   Electricity sales

(TWh)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Free market (a)       23.37   25.07   27.84   27.25   31.84
Italian Exchange for electricity       3.82   4.70   7.13   8.67   6.1
Industrial plants       2.71   2.92   3.21   3.23   3.3
Other (a) (b)       0.03   1.27   1.36   1.13   1.34













Power sales       29.93   33.96   39.54   40.28   42.58
Power generation       23.33   24.09   25.63   25.23   25.67
Trading of electricity (b)       6.60   9.87   13.91   15.05   16.91













(a) Network losses have been restated from the item "Other" to "Free Market".
(b) Include positive and negative imbalances.
  
   EniPower power stations   Installed capacity as of December 31, 2012 (a)   Full installed capacity (2016) (b)   Effective/planned start-up   Tecnology   Fuel 
                     
Power stations   (MW)   (GW)            
Brindisi   1,321   1.3   2006   CCGT   Gas
Ferrera Erbognone   1,030   1.0   2004   CCGT   Gas/syngas
Livorno   199   0.2   2000   Power Station   Gas/fuel oil
Mantova   836   0.9   2005   CCGT   Gas
Ravenna   972   1.0   2004   CCGT   Gas
Taranto   75   0.1   2000   Power Station   Gas/fuel oil
Ferrara   841   0.8   2008   CCGT   Gas
Bolgiano   30   0.1   2012   Power Station   Gas
Photovoltaic sites   4       2011-2015   Photovoltaic   Photovoltaic











    5,308   5.4            











(a) Capacity available after completion of dismantling of obsolete plants.
(b) Installed and operational generation capacity.
  

   Power generation

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Purchases                        
Purchases of natural gas   (mmcm)   4,530   4,790   5,154   5,008   5,206
Purchases of other fuels   (ktoe)   560   569   547   528   462
- of which steam cracking       131   82   103   99   98













Production                        
Power generation   (TWh)   23.33   24.09   25.63   25.23   25.67
Steam   (ktonnes)   10,584   10,048   10,983   14,401   12,603













Installed generation capacity   (GW)   4.9   5.3   5.3   5.3   5.3













  
    Transport infrastructure
OUTSIDE ITALY  

Lines
(units)

 

Length of
main line

(km)

 

Diameter
(inch)

 

Transport capacity (a)
(bcm/y)

 

Transport capacity (b)
(bcm/y)

 

Compression stations
(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













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

   Capital expenditure

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       123   85   155   132   174
Outside Italy       308   122   110   60   51
        431   207   265   192   225
Market       198   175   248   184   212
Market       91   102   133   97   81
     Italy       16   12   40   45   43
     Outside Italy       75   90   93   52   38
Power generation       107   73   115   87   131
International transport       233   32   17   8   13
        431   207   265   192   225













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Contents

Eni Fact Book Refining & Marketing

 

   Refining & Marketing

 

   Key performance indicators

       

2008  

 

2009  

 

2010  

 

2011  

 

2012  














Employees injury frequency rate   (No. of accidents per million of worked hours)   2.88     3.18     1.77     1.96     1.08  
Contractors injury frequency rate       3.45     4.35     3.59     3.21     2.32  


















Net sales from operations (a)   (euro million)   45,017     31,769     43,190     51,219     62,656  
Operating profit       (988 )   (102 )   149     (273 )   (1,303 )
Adjusted operating profit       580     (357 )   (181 )   (539 )   (328 )
Adjusted net profit       521     (197 )   (56 )   (264 )   (179 )
Capital expenditure       965     635     711     866     842  


















Refinery throughputs on own account   (mmtonnes)   35.84     34.55     34.80     31.96     30.01  
Conversion index   (%)   58     60     61     61     61  
Balanced capacity of refineries   (kbbl/d)   737     747     757     767     767  


















Retail sales of petroleum products in Europe   (mmtonnes)   12.03     12.02     11.73     11.37     10.87  
Service stations in Europe at year end   (units)   5,956     5,986     6,167     6,287     6,384  
Average throughput per service station in Europe   (kliters)   2,502     2,477     2,353     2,206     2,064  
Retail efficiency index   (%)   1.56     1.61     1.53     1.50     1.48  


















Employees at year end   (units)   8,327     8,166     8,022     7,591     7,125  
Direct GHG emissions   (mmtonnes CO2 eq)   7.74     7.29     7.76     7.23     6.03  
SOx (sulphur oxide) emissions   (ktonnes SO2 eq)   23.18     21.98     28.05     23.07     16.99  
NOx (nitrogen oxide) emissions   (ktonnes NO2 eq)   7.38     7.35     7.96     6.74     5.87  
Water consumption rate (refineries)/refinery throughputs   (cm/tonnes)   36.29     35.99     28.36     30.98     25.33  
Biofuels marketed   (mmtonnes)   9.90     18.15     17.79     13.26     14.83  
Customer satisfaction index   (likert scale)   8.14     7.93     7.84     7.74     7.90  


















(a) Before elimination of intragroup sales.


Performance of the year

I The injury frequency rates decreased from 2011(down 45% for employees and 27.7% for contractors).

I In 2012 continued the declining trend of GHG, NOx and SOx emissions, benefiting from energy saving measures and increasing use of natural gas to replace fuel oil.

I The 2012 scenario was weighted down by a steep fall in fuel demand in Italy and continued deteriorating fundamentals in the refining activity amidst volatile margins. Against this backdrop, Eni’s Refining & Marketing Division managed to reduce adjusted operating loss by euro 85 million from 2011 (down euro 179 million). This result reflects the better operating performances and improved efficiency and performance of refineries. Results posted by the Marketing activity were impacted by falling demand for fuel, high competitive pressure and increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends.

  I In 2012 refining throughputs were 30.01 mmtonnes, down 6.1% from 2011. In Italy, processed volumes decreased by 7.8% due to scheduled standstills in order to mitigate the negative impact of the trading environment mainly at the Taranto and Gela refineries. Outside Italy, Eni’s refining throughputs increased by 3.2% in particular in the Czech Republic.

I Retail sales in Italy of 7.83 mmtonnes decreased by 6.3% from 2011. This decline was driven by sharply lower consumption of gasoil and gasoline in Italy (down 8.3% from 2011) and increased competitive pressure. In 2012 Eni’s average retail market share was 31.2% increasing by 0.7 percentage points from 2011 benefiting from the commercial initiatives made in the third quarter of 2012.

I Retail sales in the rest of Europe of 3.04 mmtonnes improved slightly from 2011 (up 1%). Volume additions in Austria and Switzerland, reflecting successful commercial initiatives were offset by lower sales in Eastern Europe due to declining demand.

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Eni Fact Book Refining & Marketing

I Capital expenditure of euro 842 million related mainly to refining, supply and logistics (euro 583 million) to improve plants flexibility and yields, in particular at the Sannazzaro Refinery, and marketing for the streamlining and rebranding of the retail distribution network (euro 223 million).

  I In 2012 total expenditure in R&D in the Refining & Marketing Division amounted to approximately euro 34 million, net of general and administrative costs. In the year 7 patent applications were filed.
  

Activities

1. Refining

Eni, through its Refining & Marketing Division, is the leader operator in Italy in refining, with its five wholly owned refineries (Sannazzaro, Livorno, Porto Marghera, Taranto and Gela), and in marketing of petroleum products. In the rest of Europe Eni also holds interests in certain refining poles and is active in retail and wholesale sales in Central/Eastern European Countries.

As of December 31, 2012, Eni’s refining system had total refinery capacity (balanced with conversion capacity) of approximately 38.3 mmtonnes (equal to 767 kbbl/d) and a conversion index of 61%.
In 2012, total refinery throughputs were 30.01 mmtonnes, of which 24.89 mmtonnes in Italy and 5.12 outside Italy. Total throughputs in wholly-owned refineries were 20.84 mmtonnes, down by 1.91 mmtonnes or 8.4% from 2011 determining a refinery utilization rate of 73%, declining by six percentage points from 2011 consistent with the unfavorable scenario. Approximately 22.8% of volumes of processed crude was supplied by Eni’s Exploration & Production segment representing a 0.5 percentage point increase from 2011 (22.3%).

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

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  Eni refining system in 2012
    Ownership share
(%)
  Distillation capacity (total)
(kbbl/d)
  Distillation capacity (Eni’s share)
(kbbl/d)
 
Primary balanced refining capacity (Eni’s share)
(kbbl/d)
  Conversion index
(%)
  Fluid catalytic cracking - FCC
(kbbl/d)
  Residue conversion
(kbbl/d)
  Go-Finer
(kbbl/d)
  Mild Hydro- cracking/ Hydro- cracking
(kbbl/d)
  Visbreaking/ Thermal Cracking
(kbbl/d)
  Coking
(kbbl/d)
  Distillation capacity utilization rate (Eni’s share)
(%)
  Balanced refining capacity utilization rate (Eni’s share)
(%)
Wholly-owned refineries      

685

 

685

 

574

 

64

 

69

 

42

 

37

 

29

 

89

 

46

 

61

 

73

Italy                                                    
     Sannazzaro  

100

 

223

 

223

 

190

 

59

 

34

  12      

29

 

29

     

75

 

88

     Gela  

100

 

129

 

129

 

100

 

142

 

35

     

37

         

46

 

33

 

42

     Taranto  

100

 

120

 

120

 

120

 

72

     

30

         

38

     

66

 

66

     Livorno  

100

 

106

 

106

 

84

 

11

                         

76

 

96

     Porto Marghera  

100

 

107

 

107

 

80

 

20

                 

22

     

44

 

59

Partially owned refineries (a)      

874

 

245

 

193

 

51

 

167

 

25

     

99

 

27

     

79

 

100

Italy                                                    
     Milazzo  

50

 

248

 

124

 

80

 

76

 

45

 

25

     

32

         

73

 

113

Germany                                                    
     Vohburg/Neustadt
     (Bayernoil)
 

20

 

215

 

43

 

41

 

36

 

49

         

43

         

92

 

96

     Schwedt  

8.33

 

231

 

19

 

19

 

42

 

49

             

27

     

101

 

104

Czech Republic                                                    
     Kralupy and Litvinov
     (Ceská Rafinerska)
 

32.4

 

180

 

58

 

53

 

30

 

24

         

24

         

75

 

83

TOTAL      

1,559

 

930

 

767

 

61

 

236

 

67

 

37

 

128

 

116

 

46

 

72

 

80

(a) Capacity of conversion plant is 100%.

Sannazzaro: the refinery has balanced refining capacity of 190 kbbl/d and a conversion index of 59%. Management believes that this unit is among the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-Western Italy and Switzerland. The high degree of flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdCK), which enable middle distillate conversion and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. Eni is developing a conversion plant employing the Eni Slurry Technology with a 23 kbbl/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled in 2013. In addition the Short Contact Time-Catalytic Partial Oxidation project is underway for the production of hydrogen. In addition, Eni is developing a conversion technology by means of Slurry Dual Catalyst (an evolution of EST) that is based on the combination of two nanocatalysts and could lead to a relevant breakthrough in the EST process, increasing its productivity and improving product quality, reducing expenditure and operating costs. In addition at the Sannazzaro Refinery the detailed design of a project for the production of hydrogen by means of the proprietary Hydrogen SCT-CPO (Short Contact Time-Catalytic Partial Oxidation) process is nearing completion. This reforming technology transforms gaseous and liquid hydrocarbons (also derived from biomass) into synthetic gas (carbon monoxide and hydrogen) at competitive costs.

Taranto: the refinery has balanced refining capacity of 120 kbbl/d and a conversion index of 72%. This refinery can process a wide range of

  crude and other feedstock. It principally produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2012, a total of 2.26 mmtonnes of this oil were processed).

Gela: the refinery has balanced refining capacity of 100 kbbl/d and a conversion index of 142%. This refinery is located on the southern coast of Sicily and is integrated with upstream operations as it processes heavy crude produced from Eni’s nearby offshore and onshore fields in Sicily. Its high conversion level is ensured by an FCC unit with go-finer for feedstocks upgrading and two coking plants enabling conversion of heavy residues, topping or vacuum residues. The power plant of this refinery also contains residue and exhaust fume treatment plants (so-called SNOx) which allow full compliance with the tightest environmental standards, removing almost all sulphur and nitrogen composites coming from the coke burning-process. An upgrade of the Gela refinery is underway by means of a refurbishment of its power plant, substantially renewing pet-coke boilers, aimed at increasing profitability maximizing synergies deriving from the integration of refining and power generation.

Livorno: the refinery, with balanced refining capacity of 84 kbbl/d and a conversion index of 11%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its pipeline links with the local harbor and with the Florence storage sites by means of two pipelines and optimizes intake, handling and distribution of products.

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Porto Marghera: the refinery, with balanced refining capacity of 80 kbbl/d and a conversion index of 20%, supplies mainly markets in North-Eastern Italy and Austria. Besides its primary distillation plants, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) designed to increase yields of valuable products. Eni intends to convert this plant into a bio-refinery based on an established proprietary technology (Ecofinig) for the production of bio-diesel. The conversion process is scheduled to start in the second quarter of 2013 while production is expected in early 2014 when the conversion is completed.

Milazzo: jointly-owned by Eni and Kuwait Petroleum Italy, the refinery has balanced primary refining capacity of 80 kbbl/d (Eni’s share) and a conversion rate of 76%. It is located on the northern

  coast of Sicily and is provided with two primary distillation plants, one unit of fluid catalytic cracking (FCC), one hydrocracking unit for the conversion of middle distillates (HdCK) and one unit devoted to the residue treatment process (LC-Finer).

n  Outside Italy
In Germany, Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that includes the Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 60 kbbl/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. Eni holds a 32.4% stake in Ceská Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to about 53 kbbl/d.

2. Logistics

Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 20 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude. Eni’s logistics model is organized in a hub structure including five main areas. These hubs monitor and centralize the handling of product flows aiming to drive forward more efficiency particularly in cost control of collection and delivery of orders. Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic cost and increasing efficiency. Eni operates in the transport of oil and refined products: (i) by sea through spot and long-term lease contracts of tanker ships; and

  (ii) on land through the ownership of a pipeline network extending approximately 1,447 kilometers. Secondary distribution to retail and wholesale markets is effected through third parties who also own their means of transportation.

3. Marketing

n  Retail Italy
In Italy Eni is leader in retail marketing of refined products with a 31.2% market share, up 0.7 percentage points from 2011.
In 2012, retail sales in Italy of 7.83 mmtonnes decreased by approximately 530 ktonnes, down 6.3%, from 2011 driven by lower consumption of gasoil and gasoline, in particular in highway service station related to the decline in freight transportation. Average gasoline and gasoil throughput (1,976 kliters) decreased

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by approximately 197 kliters from 2011.
At December 31, 2012, Eni’s retail network in Italy consisted of 4,780 service stations, 79 more than at December 31, 2011 (4,701 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (92 units), the opening of new service stations (10 units), partly offset by the closing of service stations with low throughput (23 units).

Premium fuels
In 2012 even sales of premium fuels (fuels of the "eni blu+" line with high performance and lower environmental impact) were affected by the decline in domestic consumption and were lower than the previous year. In particular, sales of eni bludiesel+ amounted to approximately 292 mmtonnes (approximately 350 mmliters) with a decline of approximately 201 ktonnes from 2011 and represented 6% of volumes of gasoil marketed by Eni’s retail network. At December 31, 2012, service stations marketing bludiesel+ totaled 4,123 units (4,130 at 2011 year-end) covering approximately 86% of Eni’s network. Retail sales of blusuper+ amounted to approximately 35 ktonnes (approximately 47 mmliters), decreasing by 27 ktonnes from 2011, and covered 1.5% of gasoline sales on Eni’s retail network (down 0.9% from a year ago). At December 31, 2012, service stations marketing blusuper+ totaled 2,505 units (2,703 at December 31, 2011), covering approximately 52% of Eni’s network.

In 2012 Eni continued the development of innovative fuels and biofuels with proprietary additives and detergents that provide better gasoline and gasoil with a "keep clean" component. Eni also continues its activity in the area of special fuels for racing (Aprilia racing, Ducati, Moto 2, Moto 3, Superbike).

Promotional actions
Within the initiatives aimed at favoring consumption in a negative economic scenario and at creating a sounder customer relationship, Eni launched the following campaigns:

"riparti con eni"
In the summer of 2012 for twelve week-ends in Eni stations the "riparti con eni" initiative provided customers in the hyperself mode of service an exceptionally lower price equal all over the Country. In a scenario of weak demand and increasing price elasticity, this initiative led to the sale of over a million liters of

  fuels and a relevant increase in monthly market share (along with the iperself 24h initiative on over 3,280 service stations): June was up 5.4%, July up 8.3%, August up 8.2% and September up 4.7%.

Co-marketing
In the first months of 2013 Eni signed a number of agreements with partners in the large distribution and telecommunications in order to provide immediate advantages to customers provided with Eni loyalty cards aimed at providing greater value to Italian families purchasing goods.

New loyalty and payment cards
In November 2012 Eni launched its campaign for the diffusion of a new line of "loyalty card", available in reloadable, prepaid and credit card versions, through which customers can accumulate even more points in the Eni and Agip branded service stations that can be used for all daily purchases made outside of the Eni network in over 30 million stores.
Cards offered come in four different versions:
- basic prepaid with an annual expense ceiling of euro 2,500;
- prepaid with contract for an annual expense ceiling at euro 12,500;
- credit card;
- young, for customers aged between 14 and 23 and half.

Routex Multicard
The Routex Multicard paying card is addressed to professional transport (transporters and car fleets) and provides users with services ranging from delayed payment to discounts on fuel prices, centralized invoicing, reports on consumption and distances covered, in addition to toll paying in highways. This initiative aims at gaining loyalty from customers across Europe as the card can be used in Italy on all Agip branded service stations and, in its international version, on the service stations of all members of the Routex consortium (Aral, BP, OMV and Statoil).

Non-oil
In 2012, Eni continued to be engaged in increasing its supply of non-oil products and services in its service stations in Italy by developing a chain of franchised outlets, in particular:
- "enicafé", which is a format deployed at 610 stations following the upgrading of existing bars and stores where foods and other services (wifi connection, payments, etc.) are marketed;
- "enishop24", Eni launched a new self-service option h24 of food, non-food and personal care products by means of the installation of eni branded vending machines in 550 outlets;
- "eni carwash", areas for car washing, mainly automatic, which are present in 180 service stations.
In 2012, non-oil returns on retail network, including lubricants margins, were euro 61.2 million.

n  Retail rest of Europe
Retail sales in the rest of Europe of 3.04 mmtonnes were basically stable (up 1% or 10 ktonnes). Volume additions in Austria and Switzerland reflecting successful commercial policies were almost completely offset by lower sales in Eastern Europe due to declining demand.
At December 31, 2012, Eni’s retail network in the rest of Europe consisted of 1,604 service stations, an increase of 18 units from December 31, 2011 (1,586 service stations). The network evolution was as follows: (i) the closing of 28 low throughput service stations mainly in Austria and France; (ii) the positive balance of acquisitions/

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releases of lease concessions (33 units) in particular in Austria; (iii) the purchase of 11 service stations, in particular in Austria; (iv) the opening of 2 new outlets. Average throughput (2,319 kliters) increased by 20 kliters from 2011 (2,299 kliters).
Eni’s strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany, Austria and Eastern Countries (e.g. Czech Republic) leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistics facilities.

4. Wholesale Business

Fuels
Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Along with traditional products provided with the Eni high quality standard, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization present all over Italy and articulated in local marketing offices and a network of agents and concessionaires.
Wholesale sales in Italy (8.62 mmtonnes) declined by approximately 740 ktonnes, down 7.9%, mainly due to lower sales of gasoline and gasoil related to a decline in demand from transports and industrial customers due to a generalized slowdown and lower jet fuel sales reflecting falling demand. Bitumen sales increased due to higher product availability of Eni products related to downtime in competitors’ refineries, in particular in the final part of the year. Average market share in 2012 was 29.5% (28.6% in 2011). Supplies of feedstock to the petrochemical industry (1.26 mmtonnes) dropped from 2011 (down 450 ktonnes) due to lower demand from industrial customers.
Wholesale sales in the rest of Europe of approximately 3.96

  mmtonnes increased by 3.1% from 2011 due to higher sales in Switzerland, the Czech Republic, Slovenia and France. Sales declined in Hungary, Austria and Germany. Other sales (23.20 mmtonnes) increased by 4.89 mmtonnes, or 27%, mainly due to higher sales volumes to oil companies.
Eni is also active in the international market of bunkering, marketing marine fuel mainly in 106 ports, of which 72 are in Italy. In 2012, marine fuel sales were 1.75 mmtonnes of which 1.67 mmtonnes in Italy.

LPG
In Italy, Eni is leader in LPG production, marketing and sale with 614 ktonnes sold for heating and automotive use equal to a 19.8% market share. An additional 206 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna.
Outside Italy, LPG sales in 2012 amounted to 515 ktonnes of which 389 ktonnes in Ecuador where LPG market share was around 37.8%.

Lubricants
Eni operates six (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state-of-the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero. In 2012, retail and wholesale sales in Italy amounted to 96 ktonnes with a 24.3% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 140 ktonnes, of these about 60% were registered in Europe (mainly in Spain, Germany, Austria and France).

Oxygenates
Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sold approximately 1.7 mmtonnes/y of oxygenates mainly ethers (approximately 5.3% of world demand) and methanol (approximately 0.9% of world demand). About 80% of products are manufactured in Italy in Eni’s plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 20% is bought and resold. Eni also distributes bio-ETBE (Ethyl-Tertiary-Butyl-Ether) on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio-ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. Starting from March 1, 2010, Italian regulation on bio-fuels content has been changed from 3% to 3.5%.
Through Bio-ETBE and FAME blending into fossil fuels Eni covered the compliance within 109.6% in 2011. From January 1, 2012, the compulsory content of bio-fuels increases to 4.5% from 4% in 2011, Eni plans to cover compliance through Bio-ETBE, FAME and biodiesel in its Porto Marghera refinery and direct blending of ethanol in gasolines in particular in some plants of the Sannazzaro refinery.

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   Supply of oil

(mmtonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                                   
Equity crude oil                                  
Production outside Italy       26.14     29.84     26.90     24.29     23.57  
Production in Italy       3.57     2.91     3.24     3.35     3.35  


















        29.71     32.75     30.14     27.64     26.92  


















Other crude oil                                  
Purchases on spot markets       12.09     14.94     20.95     20.44     24.95  
Purchases under long-term contracts       16.11     19.71     17.16     10.94     10.34  


















        28.20     34.65     38.11     31.38     35.29  


















Total crude oil purchases       57.91     67.40     68.25     59.02     62.21  


















Purchases of intermediate products       3.39     2.92     3.05     4.26     4.53  
Purchase of products       17.42     13.98     15.28     15.85     20.52  


















TOTAL PURCHASES       78.72     84.30     86.58     79.13     87.26  


















Consumption for power generation       (1.00 )   (0.96 )   (0.92 )   (0.89 )   (0.75 )
Other changes (a)       (1.04 )   (1.64 )   (2.69 )   (1.12 )   (1.63 )


















        76.68     81.70     82.97     77.12     84.88  


















(a) Include changes in inventories, transport declines, consumption and losses.
  

   Refinery capacity

   

2008

 

2009

 

2010

 

2011

 

2012

Primary distillation capacity (a)   (kbbl/d)   930   930   930   930   930
Balanced capacity (a)       737   747   757   767   767
Refinery throughputs on own account       717   480   514   455   417
Distillation capacity utilization rate   (%)   81   73   73   72   72













(a) Eni’s share.
  

   Availability of refined products

(mmtonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                                   
ITALY                                  
At wholly-owned refineries       25.59     24.02     25.70     22.75     20.84  
Less input on account of third parties       (1.37 )   (0.49 )   (0.50 )   (0.49 )   (0.47 )
At affiliate refineries       6.17     5.87     4.36     4.74     4.52  


















Refinery throughputs on own account       30.39     29.40     29.56     27.00     24.89  
Consumption and losses       (1.61 )   (1.60 )   (1.69 )   (1.55 )   (1.34 )


















Products available for sale       28.78     27.80     27.87     25.45     23.55  
Purchases of refined products and change in inventories       2.56     3.73     4.24     3.22     3.35  
Products transferred to operations outside Italy       (1.42 )   (3.89 )   (4.18 )   (1.77 )   (2.36 )
Consumption for power generation       (1.00 )   (0.96 )   (0.92 )   (0.89 )   (0.75 )


















Sales of products       28.92     26.68     27.01     26.01     23.79  


















OUTSIDE ITALY                                  
Refinery throughputs on own account       5.45     5.15     5.24     4.96     5.12  
Consumption and losses       (0.25 )   (0.25 )   (0.24 )   (0.23 )   (0.23 )


















Products available for sale       5.20     4.90     5.00     4.73     4.89  
Purchases of finished products and change in inventories       15.14     10.12     10.61     12.51     17.29  
Products transferred from Italian operations       1.42     3.89     4.18     1.77     2.36  


















Sales of products       21.76     18.91     19.79     19.01     24.54  


















Refinery throughputs on own account       35.84     34.55     34.80     31.96     30.01  
of which: refinery throughputs of equity crude on own account       6.98     5.11     5.02     6.54     6.39  


















Total sales of refined products       50.68     45.59     46.80     45.02     48.33  
Crude oil sales       26.00     36.11     36.17     32.10     36.56  


















TOTAL SALES       76.68     81.70     82.97     77.12     84.89  


















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   Production and sales

(mmtonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Products:                        
     Gasoline       8.32   8.43   7.81   7.24   6.88
     Gasoil       13.44   13.33   13.63   12.95   12.24
     Jet fuel/kerosene       1.54   1.42   1.46   1.41   1.35
     Fuel oil       4.34   4.01   3.75   2.65   2.77
     LPG       0.71   0.66   0.50   0.57   0.51
     Lubricants       0.60   0.49   0.67   0.54   0.62
     Petrochemical feedstock       2.16   2.08   2.59   2.49   2.06
     Other       2.86   2.28   2.46   2.33   2.00













Total products       33.97   32.70   32.87   30.18   28.43













Sales:                        
Italy       28.92   26.68   27.01   26.01   23.79
     Gasoline       3.26   3.17   2.91   2.78   2.61
     Gasoil       10.03   10.04   9.94   9.63   9.14
     Jet fuel/kerosene       1.94   1.42   1.45   1.64   1.56
     Fuel oil       0.85   0.72   0.44   0.46   0.33
     LPG       0.57   0.57   0.59   0.60   0.61
     Lubricants       0.13   0.09   0.11   0.10   0.10
     Petrochemical feedstock       1.70   1.33   1.72   1.71   1.26
     Other       10.44   9.34   9.85   9.09   8.18













Rest of Europe       19.63   16.02   16.66   15.88   16.08
     Gasoline       2.21   1.89   1.85   1.79   1.81
     Gasoil       5.11   3.55   3.95   3.71   3.96
     Jet fuel/kerosene       0.47   0.35   0.38   0.48   0.44
     Fuel oil       0.23   0.29   0.25   0.23   0.19
     LPG       0.16   0.14   0.12   0.12   0.13
     Lubricants       0.11   0.08   0.10   0.09   0.08
     Other       11.34   9.72   10.01   9.46   9.47













Extra Europe       2.13   2.89   3.13   3.13   8.46
     Gasoline       1.63   2.51   2.74   2.62   8.00
     LPG       0.37   0.36   0.37   0.38   0.39
     Lubricants       0.03   0.02   0.02   0.02   0.01
     Other       0.10   0.00   0.00   0.11   0.06













Worldwide                        
     Gasoline       7.10   7.57   7.50   7.19   12.42
     Gasoil       15.14   13.59   13.89   13.34   13.10
     Jet fuel/kerosene       2.41   1.77   1.83   2.12   2.00
     Fuel oil       1.08   1.01   0.69   0.69   0.52
     LPG       1.10   1.07   1.08   1.10   1.13
     Lubricants       0.27   0.19   0.23   0.21   0.19
     Petrochemical feedstock       1.70   1.33   1.72   1.71   1.26
     Other       21.88   19.06   19.86   18.66   17.71













Total sales       50.68   45.59   46.80   45.02   48.33













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   Sales in Italy and outside Italy by market

(mmtonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Retail       8.81   9.03   8.63   8.36   7.83
Wholesale       11.15   9.56   9.45   9.36   8.62













        19.96   18.59   18.08   17.72   16.45
Petrochemicals       1.70   1.33   1.72   1.71   1.26
Other markets       7.26   6.76   7.21   6.58   6.08













Sales in Italy       28.92   26.68   27.01   26.01   23.79
Retail rest of Europe       3.22   2.99   3.10   3.01   3.04
Wholesale rest of Europe       3.94   3.66   3.88   3.84   3.96
Wholesale outside Europe       0.56   0.41   0.42   0.43   0.42













        7.72   7.06   7.40   7.28   7.42
Other markets       12.52   11.85   12.39   11.73   17.12
Sales outside Italy       20.24   18.91   19.79   19.01   24.54













Total sales       49.16   45.59   46.80   45.02   48.33













  

   Retail and wholesale sales of refined products

(mmtonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       19.96   18.59   18.08   17.72   16.45













Retail sales       8.81   9.03   8.63   8.36   7.83
     Gasoline       3.11   3.05   2.76   2.60   2.41
     Gasoil       5.50   5.74   5.58   5.45   5.08
     LPG       0.19   0.22   0.26   0.29   0.31
     Other       0.01   0.02   0.03   0.02   0.03













Wholesale sales       11.15   9.56   9.45   9.36   8.62
     Gasoil       4.52   4.30   4.36   4.18   4.07
     Fuel oil       0.85   0.72   0.44   0.46   0.33
     LPG       0.38   0.35   0.33   0.31   0.30
     Gasoline       0.15   0.12   0.16   0.19   0.20
     Lubricants       0.12   0.09   0.10   0.10   0.09
     Bunker       1.70   1.38   1.35   1.26   1.19
     Jet fuel       1.94   1.43   1.46   1.65   1.56
     Other       1.49   1.17   1.25   1.21   0.88













Outside Italy (retail + wholesale)       7.72   7.06   7.40   7.28   7.42
     Gasoline       2.12   1.89   1.85   1.79   1.81
     Gasoil       3.80   3.54   3.95   3.82   3.96
     Jet fuel       0.47   0.35   0.40   0.49   0.44
     Fuel oil       0.23   0.28   0.25   0.23   0.19
     Lubricants       0.11   0.10   0.10   0.10   0.09
     LPG       0.52   0.50   0.49   0.50   0.52
     Other       0.47   0.40   0.36   0.35   0.41













Total       27.68   25.65   25.48   25.00   23.87













  

   Number of service stations

(units)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       4,409   4,474   4,542   4,701   4,780













     Ordinary stations       4,273   4,344   4,415   4,574   4,653
     Highway stations       136   130   127   127   127













Outside Italy       1,547   1,512   1,625   1,586   1,604
     Germany       521   478   455   454   445
     France       199   196   188   181   173
     Austria/Switzerland       458   446   582   547   575
     Eastern Europe       369   392   400   404   411













     Service stations selling Blu products       4,445   4,822   4,994   5,179   5,226
     "Multi-Energy" service stations       4   4   5   5   6
     Service stations selling LPG and natural gas       537   690   657   864   1,031
     Non-oil sales   (euro million)   153   147   136.9   156   159













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   Average throughput

(kliters/No. of service stations)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       2,470   2,482   2,322   2,173   1,976
Germany       2,868   3,167   3,360   3,237   3,226
France       2,152   2,193   2,310   2,209   2,121
Iberian Peninsula (a)       2,519   -   -   -   -
Austria/Switzerland       1,763   1,691   1,711   1,645   1,879
Eastern Europe       2,832   2,642   2,508   2,591   2,145













Average throughput       2,502   2,477   2,352   2,206   2,064













(a) Refers to the first nine months of 2008. In October 2008 downstream activities including 371 service stations were sold to Galp.

   Market shares in Italy

(%)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Retail       30.6   31.5   30.4   30.5   31.2
Gasoline       28.5   29.0   27.9   27.8   28.8
Gasoil       32.7   33.8   32.5   32.6   33.2
LPG (automotive)       19.1   20.2   21.4   22.7   23.1
Lubricants       23.7   21.5   35.7   27.6   35.4













Wholesale       30.4   27.5   29.2   28.3   29.5
Gasoil       31.8   32.0   33.5   30.8   33.0
Fuel oil       16.3   17.2   17.8   25.5   23.3
Bunker       44.6   40.1   40.4   33.6   37.6
Lubricants       25.0   23.3   24.0   23.6   24.1













Domestic market share       31.0   29.3   29.8   29.3   30.3













 

   Retail market shares outside Italy

(%)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Central Europe                        
Austria       7.0   7.3   7.0   9.6   11.7
Switzerland       6.4   6.4   6.5   6.6   7.1
Germany       3.8   3.4   3.4   3.1   3.2
France       1.1   1.1   1.1   1.0   0.9













Eastern Europe                        
Hungary       11.6   11.6   11.9   11.9   11.9
Czech Republic       11.4   11.3   11.8   11.6   10.8
Slovakia       10.2   9.2   9.7   9.8   9.7
Slovenia       2.1   2.4   2.3   2.2   2.2
Romania           1.2   1.5   1.7   1.8













 

   Capital expenditure

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       850   581   633   803   781
Outside Italy       115   54   78   63   61













        965   635   711   866   842













Refining, supply and logistic       630   436   446   629   622
Italy       630   436   444   626   618
Outside Italy               2   3   4
Marketing       298   172   246   228   220
Italy       183   118   170   168   163
Outside Italy       115   54   76   60   57
Other       37   27   19   9    













        965   635   711   866   842













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Eni Fact Book Chemicals

   Chemicals

 

   Key performance indicators

       

2008  

 

2009  

 

2010  

 

2011  

 

2012  














Employees injury frequency rate   (No. of accidents per million of worked hours)   2.57     2.34     1.54     1.47     0.76  
Contractors injury frequency rate       9.95     8.12     5.94     4.60     1.66  


















Net sales from operations (a)   (euro million)   6,303     4,203     6,141     6,491     6,418  
     Intermediates       3,060     1,832     2,833     2,987     3,110  
     Polymers       2,961     2,185     3,126     3,299     3,128  
     Other sales       282     186     182     205     180  
Operating profit       (845 )   (675 )   (86 )   (424 )   (683 )
Adjusted operating profit       (398 )   (426 )   (96 )   (273 )   (485 )
Adjusted net profit       (323 )   (340 )   (73 )   (206 )   (395 )
Capital expenditure       212     145     251     216     172  


















Production   (ktonnes)   7,372     6,521     7,220     6,245     6,090  
Sales of petrochemical products       4,684     4,265     4,731     4,040     3,953  
Average plant utilization rate   (%)   68.6     65.4     72.9     65.3     66.7  


















Employees at year end   (units)   6,274     6,068     5,972     5,804     5,668  
Direct GHG emissions   (mmtonnes CO2 eq)   4.90     4.63     4.69     4.12     3.69  
NMVOC (Non-Methane Volatile Organic Compound) emissions   (ktonnes)   3.61     3.83     4.71     4.18     4.40  
SOx emissions (sulphur oxide)   (ktonnes SO2 eq)   5.12     4.59     3.30     3.17     2.19  
NOx emissions (nitrogen oxide)   (ktonnes NO2 eq)   5.27     4.78     4.87     4.14     3.43  
Recycled/reused water   (%)   79.6     81.6     82.7     81.8     81.5  


















(a) Before elimination of intragroup sales.

Performance of the year

I In 2012 injury rates of employees and contractors continued to follow the positive trends of previous years (down 48.3% and 63.9%, respectively).

I In 2012 emissions of greenhouse gases, NOX and SOX decreased due to lower production volumes and energy saving interventions performed in the year. NMVOC emissions increased mainly at the Dunkerque site due to the unavailability of the plant collecting NMVOC emissions from polyethylene silos.

I In 2012 the sector reported a significant increase in adjusted net loss (euro 395 million, down euro 189 million) from 2011, due to weak trends in demand for commodities resulting from the economic slowdown and collapsing unit margins.

I Sales of petrochemical products were 3,953 ktonnes, down 87 ktonnes, or 2.1%, from 2011 due to lower consumption.

I Chemical production volumes were 6,090 ktonnes, decreasing by 155 ktonnes, down 2.48%, due to a decline in demand for chemical products in all businesses, in particular polyethylene.

  I In 2012 overall expenditure in R&D amounted to approximately euro 38 million in line with the previous year. A total of 18 new patent applications were filed, one of these jointly with the Exploration & Production Division.

Expansion on international markets
I With the aim of international expansion of chemical activities, in October 2012, Versalis signed two agreements with major chemical operators in South Korea and Malaysia to build and operate facilities for the production of elastomers incorporating Versalis proprietary technologies and know-how. These initiatives are in line with Eni’s strategy of international expansion in Asian markets with interesting growth prospects, where Versalis has a leading position.

Green Chemistry
I In January 2013, Versalis and Yulex, an agricultural-based biomaterials company, signed a strategic partnership to manufacture guayule-based bio-rubber materials in a production complex in Southern Europe. The partnership will cover the entire manufacturing chain from crop science to bio-rubber extraction

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Eni Fact Book Chemicals

to the construction of a biomass power station. Versalis will manufacture materials for consumer and medical specialty markets with hypoallergenic qualities that are expected to generate higher margins. The partnership will leverage Yulex’s core competencies including crop science and bio-rubber extraction technologies, to boost Versalis’ bio-based portfolio.
The investment will include an ambitious research project to develop technologies targeting the tire industry.
With its market leading position in the elastomer industry Versalis plans to expand its leading-edge technologies in
  the synthetic rubber business by including guayule rubber as a supplementary business opportunity and an increased commercial offering. In June 2012, a Memorandum of Understanding has been signed with Genomatica and Novamont to establish a technological joint venture in Italy governing a four-year research project aimed at developing a new technology for the production of butadiene from renewable feedstocks. This joint venture will also hold exclusive right for the industrial application of the research results, including licensing it to third parties.


Activities

Eni through Versalis performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies, advanced production facilities, as well as a large and efficient retail network present in 18 European Countries.
Versalis’ portfolio of proprietary technologies covers the whole field of basic petrochemicals and polymers: phenol and its derivatives, polyethylene, styrenes and elastomers as well as catalysts and specialty products.
As a producer of intermediates, all types of polyethylene and a wide range of elastomers/lattices and of the complete line of styrenic products, Versalis continues in the development of its proprietary technologies supported by the experience it gained in production and R&D. This approach favored the optimization of the design of equipment and plants, of their performance, of proprietary catalysts and other products that allowed it to achieve excellence
  in all technologies in the specific business areas in order to compete in markets worldwide. A key role is played by the most innovative proprietary catalysts, such as those based on zeolites developed by Versalis as building blocks of some of its most advanced technologies and available worldwide.
The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibers and polystyrene. In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

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Eni Fact Book Chemicals

Business areas

Intermediates    
Basic petrochemicals are one of the pillars of the petrochemical activities of Versalis, whose products have a range of important industrial uses, such as the production of polyethylene, polypropylene, PVC and polystyrene. They are also used in the production of petrochemical intermediates that converge, in turn, into a range of other productive processes: plastics, rubbers, fibers, solvents and lubricants.

In 2012 basic petrochemicals revenues (euro 3,110 million) increased by euro 123 million from 2011 (up 4%) due to the positive performance of derivatives reflecting increased volumes (up 21%) and average unit prices (up 10%) as a result of an improved scenario and product availability. Olefin and aromatics sales volumes declined (down 2% and 4.5%, respectively) mainly due to facility downtimes at the polyethylene plants in Sicily due to low profitability and declining demand. Average unit prices of olefins were stable, while aromatics process increased (up 12%) driven by increased benzene prices (up 18.7%).

Production of intermediates (4,112 ktonnes) was in line with 2011 (up 0.3%). Derivatives production increased by 12% as phenol derivatives and styrene monomer had been affected in 2011 by the planned facility downtimes in the Mantova plant.
Production of olefins and aromatics decreased by 2.7% and 5.4%, respectively affected by planned facility downtimes in Sarroch and the slowdown of the Priolo cracker aimed at dampening the effects of the negative scenario.

Polymers
In the polymers business Versalis is active in the production of:
- Polyethylene that accounts for approximately 40% of the total volume of world production of plastic materials. It is a basic plastic material, used as a raw material by companies that transform it into a range of finished goods;
- Styrenics that are polymeric materials based on styrenes that are used in a very large number of sectors through a range of

  transformation technologies. The most common applications are for industrial packaging and in the food industry, small and large electrical appliances, building isolation, electrical and electronic devices, household appliances, car components and toys;
- Elastomers that are polymers characterized by high elasticity that allow them to regain their original shape even after having been subjected to extensive deformation. Versalis has a leading position in this sector and produces a wide range of products for the following sectors: tyres, footwear, adhesives, building components, pipes, electrical cables, car components and sealing, household appliances; they can be used as modifiers for plastics and bitumens, as additives for lubricating oils (solid elastomers); paper coating and saturation, carpet backing, molded foams, adhesives (synthetic latex). Versalis is one of the world’s major producers of elastomers and synthetic latex.

In 2012 polymer revenues (euro 3,128 million) decreased by euro 171 million from 2011 (down 5.2%) mainly due to decreasing sales volumes (down 5.8%) due to a steep decline in demand in particular in Europe and Italy, offset in part, by a modest rise in demand in Eastern Europe.
Average unit prices of elastomers decreased by 1.3% due to lower unit prices of SBF/BR rubber affected by the downfall of the vehicle industry and of polyethylene (down 0.4%) despite a recovery recorded in the second half of the year. Average unit prices of styrene increased on average by 6% supported by the price of expandable polystyrene.
Polymer production (1,978 ktonnes) decreased by 167 ktonnes from 2011 (down 7.8%), due mainly to lower elastomer production (down 9.4%) at Ravenna and Ferrara due to the downfall of the vehicle industry and of polyethylene (down 6%). In the early part of the year, facility downtimes were recorded Sicilian plants, including the cracker, due to a sharp decline in demand for polyethylene. Lower styrene production (down 10.3%) was due to the divestment of the compact and expandable polystyrene plant at Feluy (Belgium).

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   Product availability

(ktonnes)  

2008

 

2009

 

2010

 

2011

 

2012

                                   
Intermediates       5,110     4,350     4,860     4,101     4,112  
Polymers       2,262     2,171     2,360     2,144     1,978  


















Production       7,372     6,521     7,220     6,245     6,090  


















Consumption and losses       (3,539 )   (2,701 )   (2,912 )   (2,631 )   (2,545 )
Purchases and change in inventories       851     445     423     426     408  


















        4,684     4,265     4,731     4,040     3,953  


















 

   Revenues by geographic area

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       3,290   2,215   3,131   3,364   3,172
Rest of Europe       2,646   1,701   2,632   2,747   2,826
Asia       200   169   139   182   271
Africa       88   76   127   101   84
Americas       75   39   108   93   61
Other areas       4   3   4   4   4













        6,303   4,203   6,141   6,491   6,418













 

   Revenues by product

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Olefins       1,763   1,059   1,705   1,754   1,792
Aromatics       679   486   704   835   819
Intermediates       618   287   424   398   499
Elastomers       754   579   834   1,062   979
Styrenics       633   465   695   741   715
Polyethylene       1,574   1,140   1,597   1,496   1,434
Other       282   187   182   205   180













        6,303   4,203   6,141   6,491   6,418













 

   Capital expenditure

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
        212   145   251   216   172













of which:                        
- upkeeping       84   28   59   59   25
- plant upgrades       51   58   116   53   53
- HSE       41   28   29   46   38
- energy recovery               45   42   41
- maintenance and rationalization       24   20            













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   Engineering & Construction

 

   Key performance indicators

       

2008

 

2009

 

2010

 

2011

 

2012














Employees injury frequency rate   (No. of accidents per million of worked hours)   0.70   0.40   0.45   0.44   0.54
Contractors injury frequency rate       0.38   0.57   0.33   0.21   0.17
Fatality index   (No. of fatalities per 100 million of worked hours)   2.83   0.86   2.14   1.82   0.93













Net sales from operations (a)   (euro million)   9,176   9,664   10,581   11,834   12,771
Operating profit       1,045   881   1,302   1,422   1,433
Adjusted operating profit       1,041   1,120   1,326   1,443   1,465
Adjusted net profit       784   892   994   1,098   1,109
Capital expenditure       2,027   1,630   1,552   1,090   1,011













Orders acquired   (euro million)   13,860   9,917   12,935   12,505   13,391
Order backlog       19,105   18,730   20,505   20,417   19,739













Employees at year end   (units)   35,629   35,969   38,826   38,561   43,387
Employees outside Italy rate   (%)   84.8   85.6   87.3   86.5   89.2
Local managers rate       n.a   41.1   45.3   43.0   42.3
Local procurement rate       35.0   47.0   61.3   56.4   51.8
Healthcare expenditure   (euro thousand)   15,436   25,205   19,506   32,410   21,236
Security expenditure       57,477   68,954   26,403   50,541   81,777













Direct GHG emissions   (mmtonnes CO2 eq)   1.36   1.28   1.11   1.32   1.54













(a) Before elimination of intragroup sales.

Performance of the year

I The percentage of manager positions covered by local personnel is constantly higher than 40% of total managerial positions, except for Italy and France, reflecting however fluctuations due to the opening of new yards and short-term projects.

I The overall amount of procurement was euro 9,584 million in 2012, of which euro 7,802 million related to operating projects, 51.8% of which was procured with local suppliers.

I In 2012 the injury frequency rate for employees worsened from 2011 (by 22.7%), while it improved for contractors by 19%. Saipem continues to strive to mitigate and reduce accidents and injuries to its employees and contractors by means of training and awareness campaigns, such as the "Working at height", the dedicated HSE training portal and training courses for crane operators.

I Safety and environment expenditure for individual protection equipment and medical assistance increased by 24% from 2011 (from euro 83 million to euro 103 million).
  

  I In 2012, the Engineering & Construction sector reported adjusted net profit amounting to euro 1,109 million, in line with 2011 (up 1%). This result reflects the good operating performance recorded mainly in the drilling business deriving from the full operations of Scarabeo 9 and greater profitability from the Saipem 10000 vessel, totally offset by the decline in performance of the Engineering & Construction business due to falling demand for oilfield services and lower margins at certain works related to the general downturn especially in the second half of the year.

I Capital expenditure amounted to euro 1,011 million (euro 1,090 million in 2011) and mainly regarded the upgrading of the drilling and construction fleet.

I In 2012 overall expenditure in R&D amounted approximately to euro 15 million in line with 2011. A total of 13 new patent applications were filed.

     
Engineering & Construction Offshore

Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported

  by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years (such as Bouygues Offshore). Saipem intends to consolidate its market share strengthening its EPIC oriented business model and

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Contents

Eni Fact Book Engineering & Construction

leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies. Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a large fabrication yard in Brazil and buying other supporting assets for drilling activity.
In 2012 revenues amounted to euro 5,207 million, increasing by 5.5% from 2011, due to higher levels of activity in Middle and Far East. Orders acquired amounted to euro 7,477 million (euro 6,131 million in 2011).
Among the main orders acquired were: (i) an EPCI contract with INPEX for the installation of an underwater pipeline 889-kilometer long linking the offshore Ichthys field with the onshore shut-off valves in the area of Darwin, Australia; (ii) an EPCI contract with Lukoil-Nizhnevolzhskneft in Russia for the installation of two underwater pipelines linking the offshore Vladimir Filanovsky block with the onshore facility at a maximum depth of 6 meters; (iii) an EPCI contract for Petrobras in Brazil at Sapinoa Norte and Cemambi concerning engineering, procurement, fabrication, installation and test runs of a vertical underwater riser (Steel Lazy Wave Riser) for the collection system of the Sapinoa Norte field and of the Free Standing Hybrid Risers for exporting gas from the Sapinoa Norte and Cemambi Sul fields.
In 2012, Saipem continued to pursue the development of state of the art technologies for working in deep and ultra-deep waters, the design of floating liquefaction facilities, the development of new techniques for the installation and grounding of underwater pipes in extreme conditions. In particular, the main activities concerned: (i) the design of a system for the transfer of liquefied natural gas between two floating LNG units; (ii) design and development of underwater solutions for the separation of gas/liquid and liquid/liquid and the treatment of sea water and discharge water; (iii) research in innovative materials for pipes and the adjustment of techniques for laying such pipes; (iv) studies on the technologies for heating pipes; (v) studies on technologies for monitoring pipes during installation and fixing techniques and emergency interventions. In addition, during the year monitoring continued for the reduction of the environmental impact of installation and the development of renewable sources both onshore and offshore.

Engineering & Construction Onshore

In the Engineering & Construction Onshore construction business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the Oil & Gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through its technology excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the

  medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of Middle East, Caspian Sea, Northern and Western Africa and Russia.
In 2012 revenues amounted to euro 5,745 million, increasing by 3.9% from 2011, due to higher levels of activity in the Middle East and North America. Orders acquired amounted to euro 3,972 million (euro 5,006 million in 2011), declining mainly as a result of the cancellation of the Jurassic contract in the third quarter of 2012.
Among the main orders acquired were: (i) a turn-key contract for Shell concerning the SSAGS (Southern Swamp Associated Gas) project concerning the construction of four compression stations and new production facilities for the treatment of collected gas in various areas of the Delta State in Nigeria; (ii) an EPC contract for Saudi Aramco and Sumitomo Chemical for the Naphtha and Aromatics Package (RP 2) of the Rabigh II project which provides for the expansion of the integrated petrochemical and refining complex of Rabigh, a city located on the western coast of Saudi Arabia; (iii) an EPC contract for Transportadora de Gas Natural de Norte Noroeste. Transcanada in Mexico for the engineering, procurement and construction of a gas pipeline connecting El Encino (Chihuahua state) and Topolobambo (Silanoa state).

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Eni Fact Book Engineering & Construction

Offshore drilling

Saipem is the only engineering and construction contractor that provides both offshore and onshore drilling services to oil companies. In the offshore drilling segment, Saipem mainly operates in West Africa, the North Sea, the Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum water depth of 3,600 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-the-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In particular, in the next years, Saipem intends to complete the building of the Scarabeo 8 and 9, new generation semi-submersible platforms that have been already rented to Eni through multi-year contracts. In parallel, investments are ongoing to renew and to keep-up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment).
In 2012 revenues amounted to euro 1,089 million, increasing by 30.6% from 2011. Revenues deriving from the entry in full activity of the semisubmersible rigs Scarabeo 8 and Scarabeo 9 in 2012 were offset in part by the planned facility downtime of the Scarabeo 3 and Scarabeo 6 semisubmersible rigs.
Orders acquired amounted to euro 1,025 million (euro 780 million in 2011).

  Among the main orders acquired were: (i) the 15-month extension of the drilling contract of the Scarabeo 7 operating in Indonesian waters; (ii) the 24-month extension of the contract of the Perro Negro jack-up operating in Italian waters; (iii) for Statoil a contract for the lease of the semisubmersible drilling rig Scarabeo 5 for three years starting from the third quarter of 2014 to perform drilling activities in the Norwegian section of the North Sea.

Onshore drilling

Saipem operates in this area as a main contractor for the major international and national oil companies executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In these areas Saipem can leverage its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments.
In 2012 revenues amounted to euro 730 million, increasing slightly from 2011. Orders acquired amounted to euro 917 million (euro 588 million in 2011).
Among the main orders acquired were: (i) the leasing contract to Saudi Aramco of 15 facilities for a term of five years in Saudi Arabia; (ii) the contracts for 8 facilities to be employed in South America, Saudi Arabia, Kazakhstan, Algeria, Mauritania and Italy for periods ranging from 2 months and two years.

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Eni Fact Book Engineering & Construction

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Contents

Eni Fact Book Engineering & Construction

   Main operating data

   

2008

 

2009

 

2010

 

2011

 

2012

                         
Offshore pipelines laid   (km)   815   1,000   1,365   1,682   1,435
Onshore pipelines laid   (km)   683   716   385   889   543













Offshore structures installed   (t)   24,835   62,333   46,606   105,033   122,765
Onshore structures installed   (t)   163,137   76,543   874,428   353,480   261,410













Offshore drilling   (km)   150   140   130   178   194
Onshore drilling   (km)   622   719   881   985   953













Offshore wells drilled   (units)   50   54   44   64   104
Onshore wells drilled   (units)   241   241   279   307   373













 

   Drilling vessels
Name   Type   Drilling plant   Maximum depth
(m)
  Drilling maximum
(m)
  Other











Perro Negro 2   Jack up   Oilwell E 2000   90   6,500   Heliport provided
Perro Negro 3   Jack up   Ideco E 2100   90   6,000   Heliport provided
Perro Negro 4   Jack up   National 110 UE   45   5,000   Heliport provided
Perro Negro 5   Jack up   National 1320 UE   90   6,500   Heliport provided
Perro Negro 6   Jack up   National SSDG 3000   107   9,150   Heliport provided
Perro Negro 7   Jack up   National 1625 UE   115   9,150   Heliport provided
Perro Negro 8   Jack up   NOV SSDG 3000   107   9,100    
Scarabeo 3   Semi-submersible drilling platform helped propulsion system   National 1625 DE   550   7,600   Heliport provided
Scarabeo 4   Semi-submersible drilling platform helped propulsion system   National 1625 DE   550   7,600   Heliport provided
Scarabeo 5   Semi-submersible drilling platform, self-propelled   Emco C 3   1,900   8,000   Heliport provided
Scarabeo 6   Semi-submersible drilling platform, self-propelled   Oilwell E 3000   500   7,600   Heliport provided
Scarabeo 7   Semi-submersible drilling platform, self-propelled   Wirth SH 3000 EG   1,500   8,000   Heliport provided
Scarabeo 8   Semi-submersible drilling platform, self-propelled   NOV AHD 500 4600   3,000   10,660   Heliport provided
Scarabeo 9   Semi-submersible drilling platform, self-propelled   Aker Maritime Rem Prig   3,650   11,500   Heliport provided
Saipem 10000   Ultra deep waters drillship, self-propelled, dynamic positioning   Wirth GH 4500 EG   3,000   9,200   Oil storage capacity: 140,000 bbl; heliport provided
Saipem 12000   Ultra deep waters drillship, self-propelled, dynamic positioning   NOV SSDG 5750   3,650   10,000   Heliport provided
Saipem TAD   Tender assisted drilling barge   Bentec 1500 Hp   150   4,877   Heliport provided











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Eni Fact Book Engineering & Construction

   Construction vessels
Name   Type   Laying technique   Transport/lifting capability (t)   Maximum laying depth (m)   Pipelaying maximum diameter (inches)











Saipem 7000   Semi-submersible, self-propelled pipelay and DP vessel capable of lifting structures and J-laying pipelines in deep waters   J   14,000   3,000   32
Saipem FDS   Multipurpose monohull dynamically positioned crane and pipelay (J-lay) vessel utilized for the development of hydrocarbon fields in deep waters   J   600   2,100   22
Saipem FDS 2   Multipurpose monohull dynamically positioned crane and pipelay (J-lay) vessel utilized for the development of hydrocarbon fields in deep waters. The vessel is equipped with a J-lay tower   J, S   2,000   3,000   36
Castoro Sei   Semi-submersible pipelay vessel capable of laying large diameter pipe   S   300   1,000   60
Castoro Sette   Semi-submersible pipelay vessel capable of laying large diameter pipe   S       1,000   60
Castoro Otto   Crane and pipelay vessel   S   2,200   600   60
Saipem 3000   Mono hull, self-propelled DP crane ship, capable of laying flexible pipes and umbilicals in deep waters and lifting structures   Reel, J, S   2,200        
Bar Protector   Dynamically positioned dive support vessel used for deep waters diving operations and works on platforms                
Semac 1   Semi-submersible pipelay vessel capable of laying pipes in deep waters   S   318   600   58
Castoro II   Derrick/lay barge   S   1,000       60
Castoro 10   Trench/lay barge   S       300   60
Castoro 12   Shallow waters pipelay barge   S       1.4   40
S355   Derrick/lay barge   S   600       42
Crawler   Derrick/lay barge   S   540       60
Castoro 16   Post-trenching and back-filling barge of pipelines operating in ultra-shallow waters           1.4   40
Saibos 230   Derrick pipelay barge equipped with a mobile crane for piling, marine terminals and fixed platforms   S           30
Ersai 1 (a)   Technical pontoon equipped with two crawler cranes, capable of carrying out installations whilst grounded on the seabed       2,100        
Ersai 2 (a)   Work barge equipped with a fixed crane capable of lifting structures       200        
Ersai 3 (a)   Self-propelled workshop/storage barge used as support vessel, with storage space and office space for 50 people                
Ersai 4 (a)   Self-propelled workshop/storage barge used as support vessel, with storage space and office space for 150 people                
Ersai 400 (a)   Accommodation barge for up to 400 people, equipped with antigas shelter for H2S leaks                
Castoro 9   Launching/cargo barge       5,000        
Castoro XI   Heavy duty cargo barge       15,000        
Castoro 14   Deck cargo barge       10,000        
Castoro 15   Deck cargo barge       6,200        
S42   Deck cargo barge       8,000        
S43   Deck cargo barge                
S44   Launching/cargo barge       30,000        
S45   Launching/cargo barge       20,000        
S46   Deck cargo barge                
S47   Deck cargo barge                
S600   Light duty cargo barge       30,000        
FPSO - Cidade de Vitoria   FPSO unit with a production capacity of up to 100,000 barrels a day                
FPSO - Gimboa   FPSO unit with a production capacity of up to 60,000 barrels a day                
Firenze FPSO   FPSO unit with a production capacity of up to 12,000 barrels a day                











(a) Owned by the Saipem-managed joint venture ER SAI Caspian Contractor Llc.

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Eni Fact Book Financial Data

   Profit and loss account

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Net sales from operations       106,978     81,932     96,617     107,690     127,220  
Other income and revenues       696     1,094     967     926     1,546  


















Total revenues       107,674     83,026     97,584     108,616     128,766  
Purchases, services and other       (76,119 )   (58,091 )   (68,774 )   (78,795 )   (95,363 )
Payroll and related costs       (3,747 )   (3,928 )   (4,428 )   (4,404 )   (4,658 )


















Total operating expenses       (79,866 )   (62,019 )   (73,202 )   (83,199 )   (100,021 )
Other operating income (expense)       (124 )   55     131     171     (158 )
Depreciation, depletion, amortization and impairments       (9,302 )   (9,267 )   (9,031 )   (8,785 )   (13,561 )


















Operating profit       18,382     11,795     15,482     16,803     15,026  
Finance (expense) income       (661 )   (565 )   (749 )   (1,146 )   (1,307 )
Net income from investments       1,346     534     1,112     2,123     2,881  


















Profit before income taxes       19,067     11,764     15,845     17,780     16,600  
Income taxes       (9,269 )   (6,258 )   (8,581 )   (9,903 )   (11,659 )
Tax rate (%)       48.6     53.2     54.2     55.7     70.2  


















Net profit - continuing operations       9,798     5,506     7,264     7,877     4,941  
Attributable to:                                  
- Eni’s shareholders       8,996     4,488     6,252     6,902     4,198  
- Non-controlling interest       802     1,018     1,012     975     743  


















Net profit - discontinued operations       (240 )   (189 )   119     (74 )   3,732  
Attributable to:                                  
- Eni’s shareholders       (171 )   (121 )   66     (42 )   3,590  
- Non-controlling interest       (69 )   (68 )   53     (32 )   142  


















Net profit       9,558     5,317     7,383     7,803     8,673  
Attributable to:                                  
- Eni’s shareholders       8,825     4,367     6,318     6,860     7,788  
- Non-controlling interest       733     950     1,065     943     885  


















Net profit attributable to Eni's shareholders - continuing operations       8,996     4,488     6,252     6,902     4,198  
Exclusion of inventory holding (gains) losses       723     (191 )   (610 )   (724 )   (23 )
Exclusion of special items       596     1,024     1,128     760     2,953  
of which:                                  
- non-recurring items       (21 )   250     (246 )   69        
- other special items       617     774     1,374     691     2,953  


















Adjusted net profit attributable to Eni’s shareholders - continuing operations       10,315     5,321     6,770     6,938     7,128  


















Adjusted net profit attributable to Eni’s shareholders - discontinued operations       (151 )   (114 )   99     31     195  


















Adjusted net profit attributable to Eni’s shareholders       10,164     5,207     6,869     6,969     7,323  


















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Contents

Eni Fact Book Financial Data

   Summarized Group Balance Sheet

(euro million)  

Dec. 31, 2008  

 

Dec. 31, 2009  

 

Dec. 31, 2010   

 

Dec. 31, 2011   

 

Dec. 31, 2012   

                               
Fixed assets                              
Property, plant and equipment   55,933     59,765     67,404     73,578     63,466  
Inventories - Compulsory stock   1,196     1,736     2,024     2,433     2,538  
Intangible assets   11,019     11,469     11,172     10,950     4,487  
Equity-accounted investments and other investments   5,881     6,244     6,090     6,242     9,350  
Receivables and securities held for operating purposes   1,219     1,261     1,743     1,740     1,457  
Net payables related to capital expenditure   (787 )   (749 )   (970 )   (1,576 )   (1,142 )
















    74,461     79,726     87,463     93,367     80,156  
Net working capital                              
Inventories   6,082     5,495     6,589     7,575     8,496  
Trade receivables   16,444     14,916     17,221     17,709     19,966  
Trade payables   (12,590 )   (10,078 )   (13,111 )   (13,436 )   (14,993 )
Tax payables and provisions for net deferred tax liabilities   (5,323 )   (1,988 )   (2,684 )   (3,503 )   (3,318 )
Provisions   (9,506 )   (10,319 )   (11,792 )   (12,735 )   (13,603 )
Other current assets and liabilities   (4,544 )   (3,968 )   (1,286 )   281     2,347  
















    (9,437 )   (5,942 )   (5,063 )   (4,109 )   (1,105 )
Equity instruments   2,741                          
Provisions for employee post-retirement benefits   (947 )   (944 )   (1,032 )   (1,039 )   (982 )
Discontinued operations and assets held for sale including related liabilities   68     266     479     206     155  
















CAPITAL EMPLOYED, NET   66,886     73,106     81,847     88,425     78,224  
















Shareholders’ equity                              
attributable to: - Eni's shareholders   44,436     46,073     51,206     55,472     59,199  
attributable to: - Non-controlling interest   4,074     3,978     4,522     4,921     3,514  
















    48,510     50,051     55,728     60,393     62,713  
Net borrowings   18,376     23,055     26,119     28,032     15,511  
















TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   66,886     73,106     81,847     88,425     78,224  
















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Contents

Eni Fact Book Financial Data

   Summarized Group Cash Flow Statement

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Net profit - continuing operations       9,798     5,506     7,264     7,877     4,941  
Adjustments to reconcile net profit to net cash provided by operating activities:                                  
- depreciation, depletion and amortization and other non-monetary items       8,312     8,607     8,521     8,606     11,354  
- net gains on disposal of assets       (229 )   (226 )   (558 )   (1,176 )   (875 )
- dividends, interest, taxes and other changes       9,024     6,379     8,829     9,918     11,923  
Changes in working capital related to operations       4,756     (874 )   (1,158 )   (1,696 )   (3,373 )
Dividends received, taxes paid, interest (paid) received during the period       (10,155 )   (8,637 )   (8,758 )   (9,766 )   (11,614 )


















Net cash provided by operating activities - continuing operations       21,506     10,755     14,140     13,763     12,356  
Net cash provided by operating activities - discontinued operations       295     381     554     619     15  
Net cash provided by operating activities       21,801     11,136     14,694     14,382     12,371  


















Capital expenditure - continuing operations       (12,935 )   (12,216 )   (12,450 )   (11,909 )   (12,761 )
Capital expenditure - discontinued operations       (1,627 )   (1,479 )   (1,420 )   (1,529 )   (756 )
Capital expenditure       (14,562 )   (13,695 )   (13,870 )   (13,438 )   (13,517 )
Investments and purchase of consolidated subsidiaries and businesses       (4,019 )   (2,323 )   (410 )   (360 )   (569 )
Disposals       979     3,595     1,113     1,912     6,014  
Other cash flow related to capital expenditure, investments and disposals       (267 )   (295 )   228     627     (136 )


















Free cash flow       3,932     (1,582 )   1,755     3,123     4,163  
Borrowings (repayment) of debt related to financing activities       911     396     (26 )   41     (83 )
Changes in short and long-term financial debt       980     3,841     2,272     1,104     5,947  
Dividends paid and changes in non-controlling interests and reserves       (6,005 )   (2,956 )   (4,099 )   (4,327 )   (3,746 )
Effect of changes in consolidation and exchange differences       7     (30 )   39     10     (16 )


















NET CASH FLOW FOR THE PERIOD       (175 )   (331 )   (59 )   (49 )   6,265  


















 

   Changes in net borrowings

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Free cash flow       3,932     (1,582 )   1,755     3,123     4,163  
Net borrowings of acquired companies       (286 )         (33 )         (2 )
Net borrowings of divested companies       181                 (192 )   12,446  
Exchange differences on net borrowings and other changes       129     (141 )   (687 )   (517 )   (340 )
Dividends paid and changes in non-controlling interest and reserves       (6,005 )   (2,956 )   (4,099 )   (4,327 )   (3,746 )
CHANGE IN NET BORROWINGS       (2,049 )   (4,679 )   (3,064 )   (1,913 )   12,521  

 

   Net sales from operations

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       33,042     23,801     29,497     29,121     35,881  
Gas & Power       36,122     29,272     27,806     33,093     36,200  
Refining & Marketing       45,017     31,769     43,190     51,219     62,656  
Chemicals       6,303     4,203     6,141     6,491     6,418  
Engineering & Construction       9,176     9,664     10,581     11,834     12,771  
Other activities       185     88     105     85     119  
Corporate and financial companies       1,331     1,280     1,386     1,365     1,369  
Impact of unrealized intragroup profit elimination (a)       75     (66 )   100     (54 )   (75 )
Consolidation adjustment       (24,273 )   (18,079 )   (22,189 )   (25,464 )   (28,119 )
        106,978     81,932     96,617     107,690     127,220  

(a) This item concerned mainly intragroup sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period.

   Net sales to customers

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       14,125     10,171     12,947     10,677     15,559  
Gas & Power       35,085     28,517     26,837     31,749     34,169  
Refining & Marketing       43,521     30,804     41,845     48,428     59,690  
Chemicals       5,905     3,965     5,898     6,202     6,007  
Engineering & Construction       7,957     8,349     8,779     10,510     11,664  
Other activities       156     64     80     62     79  
Corporate and financial companies       154     128     131     116     127  
Impact of unrealized intragroup profit elimination       75     (66 )   100     (54 )   (75 )
        106,978     81,932     96,617     107,690     127,220  

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Eni Fact Book Financial Data

   Net sales by geographic area of destination

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       41,739   26,655   45,896   31,906   33,998
Other EU Countries       29,341   24,331   21,125   35,536   35,578
Rest of Europe       7,125   5,213   4,172   7,537   9,940
Africa       12,331   10,174   13,068   11,333   14,681
Americas       7,218   7,080   6,282   9,612   15,282
Asia       8,916   8,208   5,785   10,258   16,394
Other areas       308   271   289   1,508   1,347
Total outside Italy       65,239   55,277   50,721   75,784   93,222
        106,978   81,932   96,617   107,690   127,220
                         

   Purchases, services and other

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Production costs - raw, ancillary and consumable materials and goods       58,419     40,093     48,407     60,826     74,767  
Production costs - services       13,137     13,296     14,939     13,551     15,354  
Operating leases and other       2,496     2,505     2,997     3,045     3,434  
Net provisions       874     1,025     1,401     527     871  
Other expenses       1,590     1,466     1,252     1,140     1,342  
less:                                  
capitalized direct costs associated with self-constructed tangible and intangible assets       (397 )   (294 )   (222 )   (294 )   (405 )
        76,119     58,091     68,774     78,795     95,363  
                                   

   Principal accountant fees and services

(euro thousand)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Audit fees       27,962   30,748   21,114   22,031   23,042
Audit-related fees       152   276   183   1,113   1,351
Tax fees       46   51   166   323   25
All other fees       1               3
        28,161   31,075   21,463   23,467   24,421
                         

   Payroll and related costs

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Wages and salaries       2,938     3,064     3,299     3,435     3,886  
Social security contributions       612     620     631     675     674  
Cost related to defined benefit plans and defined contribution plans       91     128     154     148     148  
Other costs       257     307     557     334     187  
less:                                  
capitalized direct costs associated with self-constructed tangible and intangible assets       (151 )   (191 )   (213 )   (188 )   (237 )
        3,747     3,928     4,428     4,404     4,658  
                                   

   Depreciation, depletion, amortization and impairments

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       6,678     6,789     6,928     6,251     7,988  
Gas & Power       284     435     425     413     405  
Refining & Marketing       430     408     333     351     331  
Chemicals       116     83     83     90     90  
Engineering & Construction       335     433     513     596     683  
Other activities       4     2     2     2     1  
Corporate and financial companies       76     83     79     75     65  
Impact of unrealized intragroup profit elimination       (14 )   (17 )   (20 )   (23 )   (25 )
Total depreciation, depletion and amortization       7,909     8,216     8,343     7,755     9,538  
Impairments       1,393     1,051     688     1,030     4,023  
        9,302     9,267     9,031     8,785     13,561  
                                   

   Operating profit by Division

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       16,239     9,120     13,866     15,887     18,451  
Gas & Power       2,330     1,914     896     (326 )   (3,221 )
Refining & Marketing       (988 )   (102 )   149     (273 )   (1,303 )
Chemicals       (845 )   (675 )   (86 )   (424 )   (683 )
Engineering & Construction       1,045     881     1,302     1,422     1,433  
Other activities       (466 )   (436 )   (1,384 )   (427 )   (302 )
Corporate and financial companies       (623 )   (420 )   (361 )   (319 )   (345 )
Impact of unrealized intragroup profit elimination       1,690     1,513     1,100     1,263     996  
        18,382     11,795     15,482     16,803     15,026  

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Contents

Eni Fact Book Financial Data

NON-GAAP measures

Reconciliation of reported operating profit and reported net profit to results on an adjusted basis

Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses, special items and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates which impact industrial margins and translation of commercial payables and receivables. Accordingly also currency translation effects recorded through profit and loss are reported within business segments’ adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (38% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models.

The following is a description of items that are excluded from the calculation of adjusted results.
Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting.

Special items include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges,

  asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones; or (iii) exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency. Those items are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency Exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the exchange rate market. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (Consob), non recurring material income or charges are to be clearly reported in the management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non hedging commodity derivatives, including the ineffective portion of cash flow hedges and certain derivatives financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production Division.

Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment-operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production Division). Finance charges or interest income and related taxation effects excluded from the adjusted net profit of the business segments are allocated on the aggregate Corporate and financial companies.

For a reconciliation of adjusted operating profit and adjusted net profit to reported operating profit and reported net profit see tables below.

 

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Contents

Eni Fact Book Financial Data

    2008

(euro million)

    Other activities(a)   Discontinued operations  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   Group   Snam   Consolidation adjustments   Total   Continuing operations

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reported operating profit   16,239     2,330     (988 )   (845 )   1,045     (623 )   1,700     (466 )   125     18,517     (1,700 )   1,565     (135 )   18,382  
Exclusion of inventory holding (gains) losses         (429 )   1,199     166                                   936                       936  
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges               (21 )                                       (21 )                     (21 )
Other special (income) charges:   927     (123 )   365     297     (4 )   341     30     222           2,055     (30 )         (30 )   2,025  
  environmental charges         4     76                       8     221           309     (8 )         (8 )   301  
  asset impairments   989     1     299     278                       5           1,572                       1,572  
  gains on disposal of assets   4     (1 )   13     (5 )   (4 )   (9 )   8     (14 )         (8 )   (8 )         (8 )   (16 )
  risk provisions                                             4           4                       4  
  provision for redundancy
  incentives
  8     6     23     8           28     14     4           91     (14 )         (14 )   77  
  re-measurement gains/losses
  on commodity derivatives
  (18 )   (74 )   (21 )               52                       (61 )                     (61 )
  exchange rate differences
  and derivatives
  (56 )   (56 )   (25 )   16                                   (121 )                     (121 )
  other         (3 )                     270           2           269                       269  
Special items of operating profit   927     (123 )   344     297     (4 )   341     30     222           2,034     (30 )         (30 )   2,004  
Adjusted operating profit   17,166     1,778     555     (382 )   1,041     (282 )   1,730     (244 )   125     21,487     (1,730 )   1,565     (165 )   21,322  
Net finance (expense) income (b)   70     3     1     1     1     (577 )   21     (39 )         (519 )   (21 )         (21 )   (540 )
Net income (expense) from investments (b)   609     393     174     (9 )   49     5     27     4           1,252     (27 )         (27 )   1,225  
Income taxes (b)   (9,983 )   (738 )   (225 )   79     (307 )   352     (554 )         (49 )   (11,425 )   554     (121 )   433     (10,992 )
Tax rate (%)   55.9     33.9     30.8           28.1           31.2                 51.4                       49.9  
Adjusted net profit   7,862     1,436     505     (311 )   784     (502 )   1,224     (279 )   76     10,795     (1,224 )   1,444     220     11,015  
of which attributable to:                                                                                    
- non-controlling interest                                                         631                 69     700  
- Eni’s shareholders                                                         10,164                 151     10,315  
Reported net profit attributable to Eni’s shareholders                                   8,825                 171     8,996  
Exclusion of inventory holding (gains) losses                                   723                       723  
Exclusion of special items:                                   616                 (20 )   596  
- non-recurring charges                                   (21 )                     (21 )
- other special (income) charges                                   637                 (20 )   617  
Adjusted net profit attributable to Eni’s shareholders                                   10,164                 151     10,315  

(a) Following the announced divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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Contents

Eni Fact Book Financial Data

    2009

(euro million)

    Other activities(a)   Discontinued operations  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   Group   Snam   Consolidation adjustments   Total   Continuing operations

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reported operating profit   9,120     1,914     (102 )   (675 )   881     (420 )   1,773     (436 )         12,055     (1,773 )   1,513     (260 )   11,795  
Exclusion of inventory holding (gains) losses         326     (792 )   121                                   (345 )                     (345 )
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges                           250                             250                       250  
Other special (income) charges:   369     (218 )   513     113     (11 )   78     23     178           1,045     (23 )         (23 )   1,022  
   environmental charges         7     72                       12     207           298     (12 )         (12 )   286  
   asset impairments   618     27     389     121     2                 5           1,162                       1,162  
   gains on disposal of assets   (270 )   (1 )   (2 )         3           (5 )   (2 )         (277 )   5           5     (272 )
   risk provisions         115     17                             (4 )         128                       128  
   provision for redundancy
   incentives
  31     9     22     10           38     16     8           134     (16 )         (16 )   118  
   re-measurement gains/losses
   on commodity derivatives
  (15 )   (292 )   39     (3 )   (16 )                           (287 )                     (287 )
   exchange rate differences
   and derivatives
  5     (83 )   (24 )   (15 )                                 (117 )                     (117 )
   other                                 40           (36 )         4                       4  
Special items of operating profit   369     (218 )   513     113     239     78     23     178           1,295     (23 )         (23 )   1,272  
Adjusted operating profit   9,489     2,022     (381 )   (441 )   1,120     (342 )   1,796     (258 )         13,005     (1,796 )   1,513     (283 )   12,722  
Net finance (expense) income (b)   (23 )   6                       (443 )   14     12           (434 )   (14 )         (14 )   (448 )
Net income(expense) from investments (b)   243     297     75           49           35     1           700     (35 )         (35 )   665  
Income taxes (b)   (5,828 )   (670 )   94     90     (277 )   77     (597 )         (3 )   (7,114 )   597     (83 )   514     (6,600 )
Tax rate (%)   60.0     28.8     ..           23.7           32.4                 53.6                       51.0  
Adjusted net profit   3,881     1,655     (212 )   (351 )   892     (708 )   1,248     (245 )   (3 )   6,157     (1,248 )   1,430     182     6,339  
of which attributable to:                                                                                    
- non-controlling interest                                                         950                 68     1,018  
- Eni’s shareholders                                                         5,207                 114     5,321  
Reported net profit attributable to Eni’s shareholders                                   4,367                 121     4,488  
Exclusion of inventory holding (gains) losses                                   (191 )                     (191 )
Exclusion of special items:                                   1,031                 (7 )   1,024  
- non-recurring charges                                   250                       250  
- other special (income) charges                                   781                 (7 )   774  
Adjusted net profit attributable to Eni’s shareholders                                   5,207                 114     5,321  

(a) Following the announced divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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Contents

Eni Fact Book Financial Data

    2010

(euro million)

    Other activities(a)   Discontinued operations  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   Group   Snam   Consolidation adjustments   Total   Continuing operations

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reported operating profit   13,866     896     149     (86 )   1,302     (361 )   2,000     (1,384 )   (271 )   16,111     (2,000 )   1,371     (629 )   15,482  
Exclusion of inventory holding (gains) losses         (117 )   (659 )   (105 )                                 (881 )                     (881 )
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges         (270 )               24                             (246 )                     (246 )
Other special (income) charges:   32     759     329     95           96     46     1,179           2,536     (46 )         (46 )   2,490  
   environmental charges   30     16     169                       9     1,145           1,369     (9 )         (9 )   1,360  
   asset impairments   127     426     76     52     3           10     8           702     (10 )         (10 )   692  
   gains on disposal of assets   (241 )         (16 )         5           4                 (248 )   (4 )         (4 )   (252 )
   risk provisions         78     2                 8           7           95                       95  
   provision for redundancy
   incentives
  97     52     113     26     14     88     23     10           423     (23 )         (23 )   400  
   re-measurement gains/losses
   on commodity derivatives
        30     (10 )         (22 )                           (2 )                     (2 )
   exchange rate differences
   and derivatives
  14     195     (10 )   17                                   216                       216  
    other   5     (38 )   5                             9           (19 )                     (19 )
Special items of operating profit   32     489     329     95     24     96     46     1,179           2,290     (46 )         (46 )   2,244  
Adjusted operating profit   13,898     1,268     (181 )   (96 )   1,326     (265 )   2,046     (205 )   (271 )   17,520     (2,046 )   1,371     (675 )   16,845  
Net finance (expense) income (b)   (205 )   34                 33     (783 )   22     (9 )         (908 )   (22 )         (22 )   (930 )
Net income (expense) from investments (b)   274     362     92     1     10           44     (2 )         781     (44 )         (44 )   737  
Income taxes (b)   (8,358 )   (397 )   33     22     (375 )   181     (667 )         102     (9,459 )   667     (78 )   589     (8,870 )
Tax rate (%)   59.8     23.9     ..           27.4           31.6                 54.4                       53.3  
Adjusted net profit   5,609     1,267     (56 )   (73 )   994     (867 )   1,445     (216 )   (169 )   7,934     (1,445 )   1,293     (152 )   7,782  
of which attributable to:                                                                                    
- non-controlling interest                                                         1,065                 (53 )   1,012  
- Eni’s shareholders                                                         6,869                 (99 )   6,770  
Reported net profit attributable to Eni’s shareholders                             6,318                 (66 )   6,252  
Exclusion of inventory holding (gains) losses                             (610 )                     (610 )
Exclusion of special items:                             1,161                 (33 )   1,128  
- non-recurring charges                             (246 )                     (246 )
- other special (income) charges                             1,407                 (33 )   1,374  
Adjusted net profit attributable to Eni’s shareholders                             6,869                 (99 )   6,770  

(a) Following the announced divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

- 78 -


Contents

Eni Fact Book Financial Data

    2011

(euro million)

    Other activities(a)   Discontinued operations  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   Group   Snam   Consolidation adjustments   Total   Continuing operations

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reported operating profit   15,887     (326 )   (273 )   (424 )   1,422     (319 )   2,084     (427 )   (189 )   17,435     (2,084 )   1,452     (632 )   16,803  
Exclusion of inventory holding (gains) losses         (166 )   (907 )   (40 )                                 (1,113 )                     (1,113 )
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges                     10                       59           69                       69  
Other special (income) charges:   188     245     641     181     21     53     27     142           1,498     (27 )         (27 )   1,471  
   environmental charges               34     1                 10     141           186     (10 )         (10 )   176  
   asset impairments   190     154     488     160     35           (9 )   4           1,022     9           9     1,031  
   gains on disposal of assets   (63 )         10           4     (1 )   (4 )   (7 )         (61 )   4           4     (57 )
   risk provisions         77     8                 (6 )         9           88                       88  
   provision for redundancy
   incentives
  44     34     81     17     10     9     6     8           209     (6 )         (6 )   203  
   re-measurement gains/losses
   on commodity derivatives
  1     45     (3 )         (28 )                           15                       15  
   exchange rate differences
   and derivatives
  (2 )   (82 )   (4 )   3                                   (85 )                     (85 )
   other   18     17     27                 51     24     (13 )         124     (24 )         (24 )   100  
Special items of operating profit   188     245     641     191     21     53     27     201           1,567     (27 )         (27 )   1,540  
Adjusted operating profit   16,075     (247 )   (539 )   (273 )   1,443     (266 )   2,111     (226 )   (189 )   17,889     (2,111 )   1,452     (659 )   17,230  
Net finance (expense) income (b)   (231 )   43                       (876 )   19     5           (1,040 )   (19 )         (19 )   (1,059 )
Net income (expense) from investments (b)   624     363     99           95     1     44     (3 )         1,223     (44 )         (44 )   1,179  
Income taxes (b)   (9,603 )   93     176     67     (440 )   388     (918 )   (1 )   78     (10,160 )   918     (195 )   723     (9,437 )
Tax rate (%)   58.3     ..     ..           28.6           42.2                 56.2                       54.4  
Adjusted net profit   6,865     252     (264 )   (206 )   1,098     (753 )   1,256     (225 )   (111 )   7,912     (1,256 )   1,257     1     7,913  
of which attributable to:                                                                                    
- non-controlling interest                                                         943                 32     975  
- Eni’s shareholders                                                         6,969                 (31 )   6,938  
Reported net profit attributable to Eni’s shareholders                             6,860                 42     6,902  
Exclusion of inventory holding (gains) losses                             (724 )                     (724 )
Exclusion of special items:                             833                 (73 )   760  
- non-recurring charges                             69                       69  
- other special (income) charges                             764                 (73 )   691  
Adjusted net profit attributable to Eni’s shareholders                             6,969                 (31 )   6,938  

(a) Following the announced divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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Contents

Eni Fact Book Financial Data

    2012

(euro million)

    Other activities(a)   Discontinued operations  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   Group   Snam   Consolidation adjustments   Total   Continuing operations

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reported operating profit   18,451     (3,221 )   (1,303 )   (683 )   1,433     (345 )   1,676     (302 )   208     15,914     (1,676 )   788     (888 )   15,026  
Exclusion of inventory holding (gains) losses         163     (29 )   63                             (214 )   (17 )                     (17 )
Exclusion of special items:                                                                                    
   environmental charges         (2 )   40                       71     25           134     (71 )         (71 )   63  
   asset impairments   550     2,494     846     112     25                 2           4,029                       4,029  
   gains on disposal of assets   (542 )   (3 )   5     1     3           (22 )   (12 )         (570 )   22           22     (548 )
   risk provisions   7     831     49     18           5           35           945                       945  
   provision for redundancy
   incentives
  6     5     19     14     7     11     2     2           66     (2 )         (2 )   64  
   re-measurement gains/losses
   on commodity derivatives
  1                 1     (3 )                           (1 )                     (1 )
   exchange rate differences
   and derivatives
  (9 )   (51 )   (8 )   (11 )                                 (79 )                     (79 )
   other   54     138     53                             26           271                       271  
Special items of operating profit   67     3,412     1,004     135     32     16     51     78           4,795     (51 )         (51 )   4,744  
Adjusted operating profit   18,518     354     (328 )   (485 )   1,465     (329 )   1,727     (224 )   (6 )   20,692     (1,727 )   788     (939 )   19,753  
Net finance (expense) income (b)   (248 )   31     (4 )   (1 )         (861 )   (51 )   (22 )         (1,156 )   51           51     (1,105 )
Net income (expense) from investments (b)   436     261     63     2     55     99     38     (1 )         953     (38 )         (38 )   915  
Income taxes (b)   (11,281 )   (173 )   90     89     (411 )   115     (712 )         2     (12,281 )   712     (123 )   589     (11,692 )
Tax rate (%)   60.3     26.8     ..           27.0           41.5                 59.9                       59.8  
Adjusted net profit   7,425     473     (179 )   (395 )   1,109     (976 )   1,002     (247 )   (4 )   8,208     (1,002 )   665     (337 )   7,871  
of which attributable to:                                                                                    
- non-controlling interest                                                         885                 (142 )   743  
- Eni’s shareholders                                                         7,323                 (195 )   7,128  
Reported net profit attributable to Eni’s shareholders                                   7,788                 (3,590 )   4,198  
Exclusion of inventory holding (gains) losses                                   (23 )                     (23 )
Exclusion of special items                                   (442 )               3,395     2,953  
Adjusted net profit attributable to Eni’s shareholders                                   7,323                 (195 )   7,128  

(a) Following the announced divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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Contents

Eni Fact Book Financial Data

   Breakdown of special items (a)

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Non-recurring charges (income)       (21 )   250     (246 )   69        
of which: estimated charge from the possible resolution of the TSKJ matter             250                    
of which: settlement/payments on antitrust and other Authorities proceedings       (21 )         (246 )   69        
Other special charges (income):       2,055     1,045     2,536     1,498     4,795  
- environmental charges       309     298     1,369     186     134  
- asset impairments       1,572     1,162     702     1,022     4,029  
- gains on disposal of assets       (8 )   (277 )   (248 )   (61 )   (570 )
- risk provisions       4     128     95     88     945  
- provision for redundancy incentives       91     134     423     209     66  
- re-measurement gains/losses on commodity derivatives       (61 )   (287 )   (2 )   15     (1 )
- exchange rate differences and derivatives       (121 )   (117 )   216     (85 )   (79 )
- other       269     4     (19 )   124     271  


















Special items of operating profit       2,034     1,295     2,290     1,567     4,795  


















Net finance (expense) income       121     117     (181 )   89     202  
of which:                                  
     exchange rate differences and derivatives       121     117     (216 )   85     79  
Net income from investments       (239 )   179     (324 )   (883 )   (5,408 )
of which:                                  
     gains from disposals       (217 )         (332 )   (1,118 )   (2,354 )
          of which: international transport                         (1,044 )      
          of which: Galp                               (311 )
          of which: Snam                               (2,019 )
          of which: Padana Energia                   (169 )            
          of which: GreenStream                   (93 )            
          of which: GTT (Gaztransport et Technigaz SAS)       (185 )                        
     gains from revaluation of investments                               (3,151 )
          of which: Galp                               (1,700 )
          of which: Snam                               (1,451 )
     impairments             179     28     191     156  
Income taxes       (1,402 )   (560 )   (624 )   60     (31 )
of which:                                  
     tax impact of Law Decree. No. 112 of June 25, 2008       (270 )                        
     tax impact of 2008 Budget Law       (290 )                        
     adjustment to deferred tax for Libyan assets       (173 )                        
     impairment on deferred tax assets E&P             72                    
     deferred tax liability on Italian subsidiaries                               803  
     deferred tax adjustment in a Production Sharing Agreement                         552        
     re-allocation of tax impact on Eni SpA dividends and other special items       (46 )   (219 )   29     29     147  
     taxes on special items of operating profit       (623 )   (413 )   (653 )   (521 )   (981 )


















Total special items of net profit       514     1,031     1,161     833     (442 )


















attributable to:                                  
- Non-controlling interest       (102 )                        
- Eni’s shareholders       616     1,031     1,161     833     (442 )


















(a) Including discontinued operations.

   Adjusted operating profit by Division

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       17,166     9,489     13,898     16,075     18,518  
Gas & Power       1,778     2,022     1,268     (247 )   354  
Refining & Marketing       555     (381 )   (181 )   (539 )   (328 )
Chemicals       (382 )   (441 )   (96 )   (273 )   (485 )
Engineering & Construction       1,041     1,120     1,326     1,443     1,465  
Other activities       (244 )   (258 )   (205 )   (226 )   (224 )
Corporate and financial companies       (282 )   (342 )   (265 )   (266 )   (329 )
Impact of unrealized intragroup profit elimination       1,690     1,513     1,100     1,263     782  
        21,322     12,722     16,845     17,230     19,753  

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Contents

Eni Fact Book Financial Data

   Adjusted net profit by Division

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       7,862     3,881     5,609     6,865     7,425  
Gas & Power       1,436     1,655     1,267     252     473  
Refining & Marketing       505     (212 )   (56 )   (264 )   (179 )
Chemicals       (311 )   (351 )   (73 )   (206 )   (395 )
Engineering & Construction       784     892     994     1,098     1,109  
Other activities       (279 )   (245 )   (216 )   (225 )   (247 )
Corporate and financial companies       (502 )   (708 )   (867 )   (753 )   (976 )
Impact of unrealized intragroup profit elimination       1,520     1,427     1,124     1,146     661  


















        11,015     6,339     7,782     7,913     7,871  


















Attributable to:                                  
Non-controlling interest       700     1,018     1,012     975     743  
Eni's shareholders       10,315     5,321     6,770     6,938     7,128  


















 

   Finance income (expense)

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Income from equity instruments       241     163                    
Exchange differences, net       206     (106 )   92     (111 )   131  
Finance income (expense) related to net borrowings and other       (667 )   (614 )   (634 )   (809 )   (1,038 )
Net income from securities       21     3     10     9     9  
Financial expense due to the passage of time (accretion discount)       (233 )   (197 )   (236 )   (235 )   (308 )
Income (expense) on derivatives       (427 )   (6 )   (131 )   (112 )   (251 )
less:                                  
Finance expense capitalized       198     192     150     112     150  


















        (661 )   (565 )   (749 )   (1,146 )   (1,307 )


















of which, net income from receivables and securities held for financing operating activities and interest on tax credits       78     40     64     67     61  


















 

   Income (expense on) from investments

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Share of profit of equity-accounted investments       734     655     673     634     526  
Share of loss of equity-accounted investments       (105 )   (241 )   (149 )   (106 )   (233 )
Gains on disposals       218     16     332     1,121     349  
Losses on disposals       (1 )                        
Dividends       510     164     264     659     431  
Decreases (increases) in the provision for losses on investments       (16 )   (59 )   (31 )   (28 )   (15 )
Other income (expense), net       6     (1 )   23     (157 )   1,823  
        1,346     534     1,112     2,123     2,881  

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Contents

Eni Fact Book Financial Data

   Property, plant and equipment by Division (at year end)

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Property, plant and equipment by segment, gross                                  
Exploration & Production       64,338     71,189     85,494     96,561     103,369  
Gas & Power       4,623     4,750     4,155     4,206     4,373  
Refining & Marketing       12,899     13,378     14,177     14,884     15,744  
Chemicals       5,036     5,174     5,226     5,438     5,589  
Engineering & Construction       7,702     9,163     10,714     11,809     12,621  
Other activities - Snam (*)       16,106     17,290     18,355     19,449        
Other activities       1,550     1,592     1,614     1,617     1,617  
Corporate and financial companies       391     373     372     422     470  
Impact of unrealized intragroup profit elimination       (355 )   (343 )   (495 )   (523 )   (486 )


















        112,290     122,566     139,612     153,863     143,297  


















Property, plant and equipment by segment, net                                  
Exploration & Production       32,355     34,462     40,521     45,527     47,533  
Gas & Power       3,314     3,235     2,614     2,501     2,412  
Refining & Marketing       4,496     4,397     4,766     4,758     4,439  
Chemicals       912     853     990     960     928  
Engineering & Construction       5,154     6,305     7,422     7,969     8,213  
Other activities - Snam (*)       9,724     10,543     11,262     12,016        
Other activities       83     79     78     76     76  
Corporate and financial companies       212     179     171     196     227  
Impact of unrealized intragroup profit elimination       (317 )   (288 )   (420 )   (425 )   (362 )


















        55,933     59,765     67,404     73,578     63,466  


















(*) Property, plant and equipment pertaining to the segment Other activities - Snam has been reclassified from the Gas & Power segment.

   Capital expenditure by Division

(euro million)  

2008  

 

2009  

 

2010  

 

2011  

 

2012  

                                   
Exploration & Production       9,281     9,486     9,690     9,435     10,307  
Gas & Power       431     207     265     192     225  
Refining & Marketing       965     635     711     866     842  
Chemicals       212     145     251     216     172  
Engineering & Construction       2,027     1,630     1,552     1,090     1,011  
Other activities       52     44     22     10     14  
Corporate and financial companies       95     57     109     128     152  
Impact of unrealized intragroup profit elimination       (128 )   12     (150 )   (28 )   38  
Capital expenditure - continuing operations       12,935     12,216     12,450     11,909     12,761  
Capital expenditure - discontinued operations       1,627     1,479     1,420     1,529     756  
Capital expenditure       14,562     13,695     13,870     13,438     13,517  
Investments       4,305     2,323     410     360     569  
Capital expenditure and investments       18,867     16,018     14,280     13,798     14,086  

 

   Capital expenditure by geographic area of origin

(euro million)  

2008

 

2009

 

2010

 

2011

 

2012

                         
Italy       2,047   1,719   1,624   2,058   2,130
Other European Union Countries       1,660   1,454   1,710   1,337   1,255
Rest of Europe       582   574   724   1,174   1,630
Africa       5,153   4,645   5,083   4,369   4,725
Americas       1,240   1,207   1,156   978   1,184
Asia       1,777   2,033   1,941   1,608   1,663
Other areas       476   584   212   385   174
Total outside Italy       10,888   10,497   10,826   9,851   10,631













Capital expenditure - continuing operations       12,935   12,216   12,450   11,909   12,761













Capital expenditure - discontinued operations                        
Italy       1,627   1,479   1,420   1,529   756













Capital expenditure       14,562   13,695   13,870   13,438   13,517













- 83 -


Contents

Eni Fact Book Financial Data

   Net borrowings (euro million)
    Debt and bonds   Cash and cash equivalents   Securities held for non-operating purposes   Financing receivables held for non-operating purposes   Total











2008                              
Short-term debt   6,908     (1,939 )   (185 )   (337 )   4,447  
Long-term debt   13,929                       13,929  
    20,837     (1,939 )   (185 )   (337 )   18,376  
2009                              
Short-term debt   6,736     (1,608 )   (64 )   (73 )   4,991  
Long-term debt   18,064                       18,064  
    24,800     (1,608 )   (64 )   (73 )   23,055  
2010                              
Short-term debt   7,478     (1,549 )   (109 )   (6 )   5,814  
Long-term debt   20,305                       20,305  
    27,783     (1,549 )   (109 )   (6 )   26,119  
2011                              
Short-term debt   6,495     (1,500 )   (37 )   (28 )   4,930  
Long-term debt   23,102                       23,102  
    29,597     (1,500 )   (37 )   (28 )   28,032  
2012                              
Short-term debt   5,184     (7,765 )   (34 )   (1,153 )   (3,768 )
Long-term debt   19,279                       19,279  
    24,463     (7,765 )   (34 )   (1,153 )   15,511  











 

 

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Contents

Eni Fact Book Employees

Employees

   Employees at year end (a)

(units)  

2008

 

2009

 

2010

 

2011

 

2012

                         
    Italy   4,054   3,883   3,906   3,797   3,933
Exploration & Production   Outside Italy   6,182   6,388   6,370   6,628   7,371
        10,236   10,271   10,276   10,425   11,304
    Italy   2,649   2,585   2,479   2,310   2,126
Gas & Power   Outside Italy   2,663   2,562   2,593   2,485   2,626
        5,312   5,147   5,072   4,795   4,752
    Italy   6,609   6,467   6,162   5,790   5,505
Refining & Marketing   Outside Italy   1,718   1,699   1,860   1,801   1,620
        8,327   8,166   8,022   7,591   7,125
    Italy   5,224   5,045   4,903   4,750   4,606
Chemicals   Outside Italy   1,050   1,023   1,069   1,054   1,062
        6,274   6,068   5,972   5,804   5,668
    Italy   5,420   5,174   4,915   5,197   5,186
Engineering & Construction   Outside Italy   30,209   30,795   33,911   33,364   38,201
        35,629   35,969   38,826   38,561   43,387
    Italy   1,070   968   939   880   871
Other activities   Outside Italy   -   -   -   -   -
        1,070   968   939   880   871
    Italy   4,717   4,706   4,497   4,334   4,577
Corporate and financial companies   Outside Italy   149   166   164   184   154
        4,866   4,872   4,661   4,518   4,731
    Italy   36,123   35,085   27,801   27,058   26,804
Total employees at year end   Outside Italy   41,971   42,633   45,967   45,516   51,034
        71,714   71,461   73,768   72,574   77,838
of which: senior managers       1,471   1,438   1,454   1,468   1,474













(a) Following the divestment of controlling interest and consequent exclusion from consolidation of Snam, starting from 2012, payroll of the Gas & Power Division includes the Marketing and International Transport businesses only. Prior year data have been reclassified accordingly.

 

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Contents

Eni Fact Book Supplemental oil and gas information

Supplemental oil and gas information

Oil and natural gas reserves

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - oil&gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences 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. In 2012, the average price for the marker Brent crude oil was $111 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation1 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report.
In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price

  adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2012, Ryder Scott Company and DeGolyer and MacNaughton2 provided an independent evaluation of almost 33% of Eni’s total proved reserves as of December 31, 20123, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three year period from 2010 to 2012, 92% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2012, the principal properties not subjected to independent evaluation in the last three years are Bouri and Bu Attifel (Libya) and M’Boundi (Congo).
Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 55%, 49% and 47% of total proved reserves as of December 31, 2010, 2011 and 2012, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 3%, 1% and 2% of total proved reserves on an oil-equivalent basis as of December 31, 2010, 2011 and 2012, respectively.
Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 0.6%, 0.8% and 1.1% of total proved reserves as of December 31, 2010, 2011 and 2012, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant.
Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced. The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of hydrocarbons, liquids (including crude oil, condensate and natural gas liquids) and natural gas as of December 31, 2010, 2011 and 2012.

(1) From 1991 to 2002 DeGolyer and MacNaughton, from 2003 also Ryder Scott.
(2) The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2012.
(3) Including reserves of equity-accounted entities.

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Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved hydrocarbons reserves (mmboe)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2010                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2009   703     590     1,922     1,141     1,221     236     263     133     6,209  
     of which:                                                      
     developed   490     432     1,266     799     614     139     168     122     4,030  
     undeveloped   213     158     656     342     607     97     95     11     2,179  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   97     34     353     116     (56 )   104     13           661  
     Improved recovery               1     1                             2  
     Extensions and discoveries         57     39     22           1     2     4     125  
     Production   (67 )   (80 )   (218 )   (145 )   (39 )   (46 )   (48 )   (10 )   (653 )
     Sales of minerals in place   (9 )         (1 )   (2 )                           (12 )




























     Reserves at December 31, 2010   724     601     2,096     1,133     1,126     295     230     127     6,332  




























Equity-accounted entities                                                      
     Reserves at December 31, 2009               15     22           309     16           362  
     of which:                                                      
     developed               12     5           44     13           74  
     undeveloped               3     17           265     3           288  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates               9     1           10     (1 )         19  
     Improved recovery                                       12           12  
     Extensions and discoveries               1     6                 120           127  
     Production               (2 )   (1 )         (2 )   (4 )         (9 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2010               23     28           317     143           511  




























Reserves at December 31, 2010   724     601     2,119     1,161     1,126     612     373     127     6,843  
Developed   554     405     1,237     817     543     182     167     117     4,022  
     consolidated subsidiaries   554     405     1,215     812     543     139     141     117     3,926  
     equity-accounted entities               22     5           43     26           96  
Undeveloped   170     196     882     344     583     430     206     10     2,821  
     consolidated subsidiaries   170     196     881     321     583     156     89     10     2,406  
     equity-accounted entities               1     23           274     117           415  




























(a) Including approximately 769 and 767 billion cubic feet of natural gas held in storage at December 31, 2009 and 2010, respectively.

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Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved hydrocarbons reserves (mmboe)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2011                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2010   724     601     2,096     1,133     1,126     295     230     127     6,332  
     of which:                                                      
     developed   554     405     1,215     812     543     139     141     117     3,926  
     undeveloped   170     196     881     321     583     156     89     10     2,406  




























     Purchase of minerals in place   2                                               2  
     Revisions of previous estimates   48     94     88     12     (137 )   (26 )   10     17     106  
     Improved recovery         2     2     2                             6  
     Extensions and discoveries   1     13     3     14                 40           71  
     Production   (68 )   (78 )   (158 )   (133 )   (39 )   (39 )   (42 )   (11 )   (568 )
     Sales of minerals in place         (2 )         (7 )                           (9 )




























     Reserves at December 31, 2011   707     630     2,031     1,021     950     230     238     133     5,940  




























Equity-accounted entities                                                      
     Reserves at December 31, 2010               23     28           317     143           511  
     of which:                                                      
     developed               22     5           43     26           96  
     undeveloped               1     23           274     117           415  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates                     37           73     13           123  
     Improved recovery                                       1           1  
     Extensions and discoveries                     19           268     233           520  
     Production               (2 )   (1 )         (2 )   (4 )         (9 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2011               21     83           656     386           1,146  




























Reserves at December 31, 2011   707     630     2,052     1,104     950     886     624     133     7,086  
Developed   540     374     1,194     746     482     134     188     112     3,770  
     consolidated subsidiaries   540     374     1,175     742     482     129     162     112     3,716  
     equity-accounted entities               19     4           5     26           54  
Undeveloped   167     256     858     358     468     752     436     21     3,316  
     consolidated subsidiaries   167     256     856     279     468     101     76     21     2,224  
     equity-accounted entities               2     79           651     360           1,092  




























(a) Including, approximately, 767 and 767 billion cubic feet of natural gas held in storage at December 31, 2010 and 2011, respectively.

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Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved hydrocarbons reserves (mmboe)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2012                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2011   707     630     2,031     1,021     950     230     238     133     5,940  
     of which:                                                      
     developed   540     374     1,175     742     482     129     162     112     3,716  
     undeveloped   167     256     856     279     468     101     76     21     2,224  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   24     20     67     82     91     (5 )   34     8     321  
     Improved recovery         1     20     7                             28  
     Extensions and discoveries   4     6     10     86     85           9           200  
     Production   (69 )   (66 )   (213 )   (126 )   (37 )   (41 )   (45 )   (13 )   (610 )
     Sales of minerals in place   (142 )               (22 )   (48 )                     (212 )




























     Reserves at December 31, 2012   524     591     1,915     1,048     1,041     184     236     128     5,667  




























Equity-accounted entities                                                      
     Reserves at December 31, 2011               21     83           656     386           1,146  
     of which:                                                      
      developed               19     4           5     26           54  
     undeveloped               2     79           651     360           1,092  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates                                 8     247           255  
     Improved recovery                                                      
     Extensions and discoveries               1     3           10     135           149  
     Production               (2 )   (1 )         (6 )   (4 )         (13 )
     Sales of minerals in place                     (4 )               (34 )         (38 )




























     Reserves at December 31, 2012               20     81           668     730           1,499  




























Reserves at December 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  
     consolidated subsidiaries   406     349     1,080     716     458     108     170     107     3,394  
     equity-accounted entities               20                 82     20           122  
Undeveloped   118     242     835     413     583     662     776     21     3,650  
     consolidated subsidiaries   118     242     835     332     583     76     66     21     2,273  
     equity-accounted entities                     81           586     710           1,377  




























(a) Including, approximately, 767 billion cubic feet of natural gas held in storage at December 31, 2011.

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Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved liquids reserves (mmbbl)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2010                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2009   233     351     895     770     849     94     153     32     3,377  
     of which:                                                      
     developed   141     218     659     544     291     45     80     23     2,001  
     undeveloped   92     133     236     226     558     49     73     9     1,376  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   38     17     178     75     (37 )   62     2           335  
     Improved recovery               1     1                             2  
     Extensions and discoveries         25     13     22                 1           61  
     Production   (23 )   (44 )   (108 )   (116 )   (24 )   (17 )   (22 )   (3 )   (357 )
     Sales of minerals in place               (1 )   (2 )                           (3 )




























     Reserves at December 31, 2010   248     349     978     750     788     139     134     29     3,415  




























Equity-accounted entities                                                      
     Reserves at December 31, 2009               13     7           50     16           86  
     of which:                                                      
     developed               10     4           7     13           34  
     undeveloped               3     3           43     3           52  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates               8                 (6 )   (2 )            
     Improved recovery                                       12           12  
     Extensions and discoveries                                       117           117  
     Production               (2 )   (1 )               (4 )         (7 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2010               19     6           44     139           208  




























Reserves at December 31, 2010   248     349     997     756     788     183     273     29     3,623  
Developed   183     207     674     537     251     44     87     20     2,003  
     consolidated subsidiaries   183     207     656     533     251     39     62     20     1,951  
     equity-accounted entities               18     4           5     25           52  
Undeveloped   65     142     323     219     537     139     186     9     1,620  
     consolidated subsidiaries   65     142     322     217     537     100     72     9     1,464  
     equity-accounted entities               1     2           39     114           156  




























- 90 -


Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved liquids reserves (mmbbl)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2011                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2010   248     349     978     750     788     139     134     29     3,415  
     of which:                                                      
     developed   183     207     656     533     251     39     62     20     1,951  
     undeveloped   65     142     322     217     537     100     72     9     1,464  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   34     58     10     14     (112 )   (20 )   1           (15 )
     Improved recovery         2     2     2                             6  
     Extensions and discoveries         9     2     11                 17           39  
     Production   (23 )   (44 )   (75 )   (100 )   (23 )   (13 )   (20 )   (4 )   (302 )
     Sales of minerals in place         (2 )         (7 )                           (9 )




























     Reserves at December 31, 2011   259     372     917     670     653     106     132     25     3,134  




























Equity-accounted entities                                                      
     Reserves at December 31, 2010               19     6           44     139           208  
     of which:                                                      
     developed               18     4           5     25           52  
     undeveloped               1     2           39     114           156  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates                     11           6     11           28  
     Improved recovery                                       1           1  
     Extensions and discoveries                     6           60     4           70  
     Production               (2 )   (1 )               (4 )         (7 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2011               17     22           110     151           300  




























Reserves at December 31, 2011   259     372     934     692     653     216     283     25     3,434  
Developed   184     195     638     487     215     34     117     25     1,895  
     consolidated subsidiaries   184     195     622     483     215     34     92     25     1,850  
     equity-accounted entities               16     4                 25           45  
Undeveloped   75     177     296     205     438     182     166           1,539  
     consolidated subsidiaries   75     177     295     187     438     72     40           1,284  
     equity-accounted entities               1     18           110     126           255  




























- 91 -


Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved liquids reserves (mmbbl)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2012                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2011   259     372     917     670     653     106     132     25     3,134  
     of which:                                                      
     developed   184     195     622     483     215     34     92     25     1,850  
     undeveloped   75     177     295     187     438     72     40           1,284  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   (9 )   10     55     26     62     (9 )   40     6     181  
     Improved recovery         1     20     7                             28  
     Extensions and discoveries         3     10     65                 8           86  
     Production   (23 )   (35 )   (98 )   (90 )   (22 )   (15 )   (26 )   (7 )   (316 )
     Sales of minerals in place                     (6 )   (23 )                     (29 )




























     Reserves at December 31, 2012   227     351     904     672     670     82     154     24     3,084  




























Equity-accounted entities                                                      
     Reserves at December 31, 2011               17     22           110     151           300  
     of which:                                                      
     developed               16     4                 25           45  
     undeveloped               1     18           110     126           255  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates                     (1 )         2                 1  
     Improved recovery                                                      
     Extensions and discoveries               1                 3                 4  
     Production               (1 )   (1 )         (1 )   (4 )         (7 )
     Sales of minerals in place                     (4 )               (28 )         (32 )




























     Reserves at December 31, 2012               17     16           114     119           266  




























Reserves at December 31, 2012   227     351     921     688     670     196     273     24     3,350  
Developed   165     180     601     456     203     49     128     24     1,806  
     consolidated subsidiaries   165     180     584     456     203     41     109     24     1,762  
     equity-accounted entities               17                 8     19           44  
Undeveloped   62     171     320     232     467     147     145           1,544  
     consolidated subsidiaries   62     171     320     216     467     41     45           1,322  
     equity-accounted entities                     16           106     100           222  




























- 92 -


Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved natural gas reserves (bcf)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2010                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2009   2,704     1,380     5,894     2,127     2,139     814     629     575     16,262  
     of which:                                                      
     developed   2,001     1,231     3,486     1,463     1,859     539     506     565     11,650  
     undeveloped   703     149     2,408     664     280     275     123     10     4,612  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   234     48     778     161     (179 )   211     41     (18 )   1,276  
     Improved recovery                                                      
     Extensions and discoveries         177     146                 4     5     22     354  
     Production   (246 )   (204 )   (609 )   (161 )   (86 )   (158 )   (145 )   (35 )   (1,644 )
     Sales of minerals in place   (48 )         (2 )                                 (50 )




























     Reserves at December 31, 2010   2,644     1,401     6,207     2,127     1,874     871     530     544     16,198  




























Equity-accounted entities                                                      
     Reserves at December 31, 2009               14     85           1,487     2           1,588  
     of which:                                                      
     developed               12     5           217                 234  
     undeveloped               2     80           1,270     2           1,354  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates               6     (1 )         44     2           51  
     Improved recovery                                                      
     Extensions and discoveries               6     34                 18           58  
     Production               (2 )               (11 )               (13 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2010               24     118           1,520     22           1,684  




























Reserves at December 31, 2010   2,644     1,401     6,231     2,245     1,874     2,391     552     544     17,882  
Developed   2,061     1,103     3,122     1,554     1,621     774     437     539     11,211  
     consolidated subsidiaries   2,061     1,103     3,100     1,550     1,621     560     431     539     10,965  
     equity-accounted entities               22     4           214     6           246  
Undeveloped   583     298     3,109     691     253     1,617     115     5     6,671  
     consolidated subsidiaries   583     298     3,107     577     253     311     99     5     5,233  
     equity-accounted entities               2     114           1,306     16           1,438  




























(a) Including, approximately, 769 and 767 billion cubic feet of natural gas held in storage at December 31, 2009 and 2010, respectively.

- 93 -


Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved natural gas reserves (bcf)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2011                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2010   2,644     1,401     6,207     2,127     1,874     871     530     544     16,198  
     of which:                                                      
     developed   2,061     1,103     3,100     1,550     1,621     560     431     539     10,965  
     undeveloped   583     298     3,107     577     253     311     99     5     5,233  




























     Purchase of minerals in place   9                                               9  
     Revisions of previous estimates   80     199     436     (11 )   (142 )   (38 )   51     96     671  
     Improved recovery         3                                         3  
     Extensions and discoveries   4     18     9     18                 131           180  
     Production   (246 )   (196 )   (462 )   (185 )   (84 )   (148 )   (122 )   (36 )   (1,479 )
     Sales of minerals in place                                                      




























     Reserves at December 31, 2011   2,491     1,425     6,190     1,949     1,648     685     590     604     15,582  




























Equity-accounted entities                                                      
     Reserves at December 31, 2010               24     118           1,520     22           1,684  
     of which:                                                      
     developed               22     4           214     6           246  
     undeveloped               2     114           1,306     16           1,438  




























     Purchase of minerals in place         2                                         2  
     Revisions of previous estimates               (2 )   147           372     11           528  
     Improved recovery                                                      
     Extensions and discoveries                     74           1,150     1,274           2,498  
     Production               (2 )   (1 )         (9 )               (12 )
     Sales of minerals in place                                                      




























Reserves at December 31, 2011         2     20     338           3,033     1,307           4,700  




























Reserves at December 31, 2011   2,491     1,427     6,210     2,287     1,648     3,718     1,897     604     20,282  
Developed   1,977     995     3,087     1,441     1,480     552     393     491     10,416  
     consolidated subsidiaries   1,977     995     3,070     1,437     1,480     528     385     491     10,363  
     equity-accounted entities               17     4           24     8           53  
Undeveloped   514     432     3,123     846     168     3,166     1,504     113     9,866  
     consolidated subsidiaries   514     430     3,120     512     168     157     205     113     5,219  
     equity-accounted entities         2     3     334           3,009     1,299           4,647  




























(a) Including, approximately, 767 and 767 billion cubic feet of natural gas held in storage at December 31, 2010 and 2011, respectively.

- 94 -


Contents

Eni Fact Book Supplemental oil and gas information

   Movements in net proved natural gas reserves (bcf)
    Italy (a)   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2012                                                      




























Consolidated subsidiaries                                                      
     Reserves at December 31, 2011   2,491     1,425     6,190     1,949     1,648     685     590     604     15,582  
     of which:                                                      
     developed   1,977     995     3,070     1,437     1,480     528     385     491     10,363  
     undeveloped   514     430     3,120     512     168     157     205     113     5,219  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates   154     45           284     141     18     (41 )   5     606  
     Improved recovery                                                      
     Extensions and discoveries   24     15     1     113     469     2     4           628  
     Production   (254 )   (168 )   (633 )   (196 )   (81 )   (143 )   (104 )   (37 )   (1,616 )
     Sales of minerals in place   (782 )               (89 )   (139 )                     (1,010 )




























     Reserves at December 31, 2012   1,633     1,317     5,558     2,061     2,038     562     449     572     14,190  




























Equity-accounted entities                                                      
     Reserves at December 31, 2011         2     20     338           3,033     1,307           4,700  
     of which:                                                      
     developed               17     4           24     8           53  
     undeveloped         2     3     334           3,009     1,299           4,647  




























     Purchase of minerals in place                                                      
     Revisions of previous estimates         (2 )   (2 )   3           1     1,340           1,340  
     Improved recovery                                                      
     Extensions and discoveries                     17           38     739           794  
     Production               (2 )   (2 )         (29 )               (33 )
     Sales of minerals in place                     (3 )               (31 )         (34 )




























     Reserves at December 31, 2012               16     353           3,043     3,355           6,767  




























Reserves at December 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  
     consolidated subsidiaries   1,325     925     2,720     1,429     1,401     372     334     459     8,965  
     equity-accounted entities               16                 402     6           424  
Undeveloped   308     392     2,838     985     637     2,831     3,464     113     11,568  
     consolidated subsidiaries   308     392     2,838     632     637     190     115     113     5,225  
     equity-accounted entities                     353           2,641     3,349           6,343  




























(a) Including, approximately, 767 billion cubic feet of natural gas held in storage at December 31, 2011.

- 95 -


Contents

Eni Fact Book Supplemental oil and gas information

   Results of operations from oil and gas producing activities (a) (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2010                                                      




























Consolidated subsidiaries                                                      
Revenues:                                                      
- sales to consolidated entities   2,725     3,006     2,094     5,314     324     34     1,139     69     14,705  
- sales to third parties         263     6,604     1,696     890     1,429     562     289     11,733  
Total revenues   2,725     3,269     8,698     7,010     1,214     1,463     1,701     358     26,438  
Operations costs   (278 )   (555 )   (593 )   (902 )   (184 )   (150 )   (292 )   (69 )   (3,023 )
Production taxes   (184 )         (300 )   (700 )         (37 )               (1,221 )
Exploration expenses   (35 )   (116 )   (85 )   (465 )   (6 )   (263 )   (204 )   (25 )   (1,199 )
D.D. & A. and provision for abandonment (b)   (621 )   (615 )   (1,063 )   (1,739 )   (84 )   (696 )   (872 )   (84 )   (5,774 )
Other income (expenses)   (560 )   254     (392 )   (219 )   (161 )   (138 )   (45 )   (25 )   (1,286 )
Pretax income from producing activities   1,047     2,237     6,265     2,985     779     179     288     155     13,935  
Income taxes   (382 )   (1,296 )   (4,037 )   (1,962 )   (291 )   (119 )   (154 )   (36 )   (8,277 )
Results of operations from E&P activities of consolidated subsidiaries (c)   665     941     2,228     1,023     488     60     134     119     5,658  
Equity-accounted entities                                                      
Revenues:                                                      
- sales to consolidated entities                                                      
- sales to third parties               16     65           69     206           356  
Total revenues               16     65           69     206           356  
Operations costs               (16 )   (9 )         (7 )   (9 )         (41 )
Production taxes               (3 )                     (69 )         (72 )
Exploration expenses               (4 )   (2 )         (4 )   (35 )         (45 )
D.D. & A. and provision for abandonment               (4 )   (26 )         (25 )   (17 )         (72 )
Other income (expenses)               6     12           (10 )   (67 )         (59 )
Pretax income from producing activities               (5 )   40           23     9           67  
Income taxes               4     (20 )         (17 )   (33 )         (66 )
Results of operations from E&P activities of equity-accounted entities (c)               (1 )   20           6     (24 )         1  




























(a) Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.
(b) Includes asset impairments amounting to euro 123 million in 2010.
(c) The "Successful Effort Method" application would have led to a decrease of result of operations of euro 385 million in 2010 for the consolidated subsidiaries and a decrease of euro 5 million in 2010 for equity-accounted entities.

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Contents

Eni Fact Book Supplemental oil and gas information

   Results of operations from oil and gas producing activities (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2011                                                      




























Consolidated subsidiaries                                                      
Revenues:                                                      
- sales to consolidated entities   3,583     3,695     1,956     5,945     411     178     1,634     93     17,495  
- sales to third parties         514     5,090     1,937     1,268     1,233     132     344     10,518  
Total revenues   3,583     4,209     7,046     7,882     1,679     1,411     1,766     437     28,013  
Operations costs   (284 )   (566 )   (483 )   (830 )   (171 )   (183 )   (364 )   (88 )   (2,969 )
Production taxes   (245 )         (165 )   (853 )         (37 )               (1,300 )
Exploration expenses   (38 )   (113 )   (128 )   (509 )   (6 )   (177 )   (136 )   (58 )   (1,165 )
D.D. & A. and provision for abandonment (a)   (606 )   (704 )   (843 )   (1,435 )   (112 )   (486 )   (901 )   (103 )   (5,190 )
Other income (expenses)   (562 )   142     (508 )   (314 )   (160 )   (151 )   125     8     (1,420 )
Pretax income from producing activities   1,848     2,968     4,919     3,941     1,230     377     490     196     15,969  
Income taxes   (761 )   (2,043 )   (3,013 )   (2,680 )   (413 )   (157 )   (184 )   (120 )   (9,371 )
Results of operations from E&P activities of consolidated subsidiaries (b)   1,087     925     1,906     1,261     817     220     306     76     6,598  
Equity-accounted entities                                                      
Revenues:                                                      
- sales to consolidated entities                                                      
- sales to third parties         2     19     93           89     262           465  
Total revenues         2     19     93           89     262           465  
Operations costs               (11 )   (10 )         (9 )   (17 )         (47 )
Production taxes         (1 )   (4 )                     (113 )         (118 )
Exploration expenses         (6 )         (5 )         (8 )   (9 )         (28 )
D.D. & A. and provision for abandonment               (1 )   (24 )         (23 )   (21 )         (69 )
Other income (expenses)         (4 )   6     11           (20 )   (51 )         (58 )
Pretax income from producing activities         (9 )   9     65           29     51           145  
Income taxes               (4 )   (35 )         (32 )   (4 )         (75 )
Results of operations from E&P activities of equity-accounted entities (b)         (9 )   5     30           (3 )   47           70  




























(a) Includes asset impairments amounting to euro 189 million in 2011.
(b) The "Successful Effort Method" application would have led to an increase of result of operations of euro 118 million in 2011 for the consolidated subsidiaries and an increase of euro 20 million in 2011 for equity-accounted entities.

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Eni Fact Book Supplemental oil and gas information

   Results of operations from oil and gas producing activities (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2012                                                      




























Consolidated subsidiaries                                                      
Revenues:                                                      
- sales to consolidated entities   3,712     3,177     2,338     6,040     459     425     1,614     425     18,190  
- sales to third parties   50     715     9,129     2,243     1,368     1,387     106     333     15,331  
Total revenues   3,762     3,892     11,467     8,283     1,827     1,812     1,720     758     33,521  
Operations costs   (302 )   (655 )   (606 )   (913 )   (188 )   (209 )   (361 )   (134 )   (3,368 )
Production taxes   (307 )         (390 )   (818 )         (43 )               (1,558 )
Exploration expenses   (32 )   (154 )   (153 )   (993 )   (3 )   (230 )   (147 )   (123 )   (1,835 )
D.D. & A. and provision for abandonment (a)   (779 )   (683 )   (1,137 )   (1,750 )   (120 )   (720 )   (1,256 )   (167 )   (6,612 )
Other income (expenses)   (202 )   (120 )   (937 )   (447 )   206     (151 )   74     (42 )   (1,619 )
Pretax income from producing activities   2,140     2,280     8,244     3,362     1,722     459     30     292     18,529  
Income taxes   (918 )   (1,524 )   (5,194 )   (2,508 )   (736 )   (176 )   (14 )   (164 )   (11,234 )
Results of operations from E&P activities of consolidated subsidiaries (b)   1,222     756     3,050     854     986     283     16     128     7,295  
Equity-accounted entities                                                      
Revenues:                                                      
- sales to consolidated entities                                                      
- sales to third parties         2     20     44           144     300           510  
Total revenues         2     20     44           144     300           510  
Operations costs               (10 )   (5 )         (14 )   (20 )         (49 )
Production taxes         (1 )   (3 )               (4 )   (128 )         (136 )
Exploration expenses         (5 )   (2 )   (11 )         (4 )               (22 )
D.D. & A. and provision for abandonment         (50 )   (2 )   (13 )         (41 )   (35 )         (141 )
Other income (expenses)         (7 )   2     (48 )         (6 )   (55 )         (114 )
Pretax income from producing activities         (61 )   5     (33 )         75     62           48  
Income taxes               (3 )   4           (36 )   (38 )         (73 )
Results of operations from E&P activities of equity-accounted entities (b)         (61 )   2     (29 )         39     24           (25 )




























(a) Includes asset impairments amounting to euro 547 million in 2012.
(b) The "Successful Effort Method" application would have led to a decrease of result of operations of euro 189 million in 2012 for the consolidated subsidiaries and a decrease of euro 2 million in 2012 for equity-accounted entities.

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Eni Fact Book Supplemental oil and gas information

   Capitalized cost (a) (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















December 31, 2011                                                      




























Consolidated subsidiaries                                                      
Proved mineral interests   11,356     11,481     15,519     19,539     2,523     6,136     8,976     1,889     77,419  
Unproved mineral interests   31     325     582     2,893     40     1,543     1,409     204     7,027  
Support equipment and facilities   285     34     1,442     923     85     41     61     13     2,884  
Incomplete wells and other   956     1,778     2,755     898     5,333     136     1,029           12,885  




























Gross Capitalized Costs   12,628     13,618     20,298     24,253     7,981     7,856     11,475     2,106     100,215  




























Accumulated depreciation, depletion and amortization   (8,633 )   (8,582 )   (9,750 )   (13,069 )   (906 )   (5,411 )   (6,806 )   (650 )   (53,807 )
Net Capitalized Costs consolidated subsidiaries (b) (c)   3,995     5,036     10,548     11,184     7,075     2,445     4,669     1,456     46,408  
Equity-accounted entities                                                      
Proved mineral interests         2     80     240           698     330           1,350  
Unproved mineral interests         44                       271                 315  
Support equipment and facilities               8                 6     3           17  
Incomplete wells and other         2     1     1,011           185     223           1,422  




























Gross Capitalized Costs         48     89     1,251           1,160     556           3,104  




























Accumulated depreciation, depletion and amortization         (2 )   (74 )   (131 )         (388 )   (89 )         (684 )
Net Capitalized Costs equity-accounted entities (b) (c)         46     15     1,120           772     467           2,420  
December 31, 2012                                                      




























Consolidated subsidiaries                                                      
Proved mineral interests   12,579     12,428     16,240     20,875     2,451     6,477     10,018     1,894     82,962  
Unproved mineral interests   31     324     411     3,047     39     1,467     1,249     200     6,768  
Support equipment and facilities   267     39     1,421     961     75     78     59     12     2,912  
Incomplete wells and other   732     3,347     3,181     974     5,746     358     876     1     15,215  




























Gross Capitalized Costs   13,609     16,138     21,253     25,857     8,311     8,380     12,202     2,107     107,857  




























Accumulated depreciation, depletion and amortization   (9,364 )   (9,346 )   (10,671 )   (14,225 )   (928 )   (6,002 )   (7,879 )   (832 )   (59,247 )
Net Capitalized Costs consolidated subsidiaries (b) (c)   4,245     6,792     10,582     11,632     7,383     2,378     4,323     1,275     48,610  
Equity-accounted entities                                                      
Proved mineral interests         1     83     52           964     322           1,422  
Unproved mineral interests         54                       279                 333  
Support equipment and facilities               7                 6     3           16  
Incomplete wells and other         22     1     1,052           114     200           1,389  




























Gross Capitalized Costs         77     91     1,104           1,363     525           3,160  




























Accumulated depreciation, depletion and amortization         (55 )   (72 )               (421 )   (111 )         (659 )
Net Capitalized Costs equity-accounted entities (b) (c)         22     19     1,104           942     414           2,501  




























(a) Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.
(b) The amounts include net capitalized financial charges totaling euro 614 million in 2011 and euro 672 million in 2012 for the consolidated subsidiaries and euro 11 million in 2011 and euro 24 million in 2012 for equity-accounted entities.
(c) The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application would have led to an increase in net capitalized costs of euro 3,608 million in 2011 e euro 4,071 million in 2012 for the consolidated subsidiaries and of euro 101 million in 2011 and euro 74 million in 2012 for equity-accounted entities.

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Contents

Eni Fact Book Supplemental oil and gas information

   Cost incurred (a) (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















2010                                                      




























Consolidated subsidiaries                                                      
Proved property acquisitions                                                      
Unproved property acquisitions                                                      
Exploration   34     114     84     406     6     223     119     26     1,012  
Development (b)   579     890     2,674     1,909     1,031     359     1,309     160     8,911  
Total costs incurred consolidated subsidiaries   613     1,004     2,758     2,315     1,037     582     1,428     186     9,923  
Equity-accounted entities                                                      
Proved property acquisitions                                                      
Unproved property acquisitions                                                      
Exploration               4     2           4     35           45  
Development (c)               7     200           46     114           367  
Total costs incurred equity-accounted entities               11     202           50     149           412  
2011                                                      




























Consolidated subsidiaries                                                      
Proved property acquisitions                                                      
Unproved property acquisitions               57     697                             754  
Exploration   38     100     128     482     6     156     60     240     1,210  
Development (b)   815     1,921     1,487     1,698     935     385     971     70     8,282  
Total costs incurred consolidated subsidiaries   853     2,021     1,672     2,877     941     541     1,031     310     10,246  
Equity-accounted entities                                                      
Proved property acquisitions                                                      
Unproved property acquisitions                                                      
Exploration         5           5           8     9           27  
Development (c)         2     3     659           68     154           886  
Total costs incurred equity-accounted entities         7     3     664           76     163           913  
2012                                                      




























Consolidated subsidiaries                                                      
Proved property acquisitions               14     27                 2           43  
Unproved property acquisitions                                                      
Exploration   32     151     153     1,142     3     193     80     96     1,850  
Development (b)   1,045     2,485     1,441     2,246     762     702     1,071     16     9,768  
Total costs incurred consolidated subsidiaries   1,077     2,636     1,608     3,415     765     895     1,153     112     11,661  
Equity-accounted entities                                                      
Proved property acquisitions                                                      
Unproved property acquisitions                                                      
Exploration         13     2     11           4                 30  
Development (c)         19     7     117           188     154           485  
Total costs incurred equity-accounted entities         32     9     128           192     154           515  




























(a) Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities.
(b) Includes the abandonment costs of the assets for euro 269 million in 2010, euro 918 million in 2011 and euro 1,381 million in 2012.
(c) Includes the abandonment costs of the assets for euro -3 million in 2010, euro 15 million in 2011 and euro 63 million in 2012.

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Contents

Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and are determined by applying year-end the average prices during the years ended.
Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered.
The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.
Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future
  development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates.
The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - oil&gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

 

 

 

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Contents

Eni Fact Book Supplemental oil and gas information

   Standardized measure of discounted future net cash flows (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















December 31, 2010                                                      




























Consolidated subsidiaries                                                      
     Future cash inflows   30,047     27,973     86,728     45,790     41,053     9,701     8,546     3,846     253,684  
     Future production costs   (4,865 )   (7,201 )   (12,896 )   (13,605 )   (6,686 )   (3,201 )   (2,250 )   (611 )   (51,315 )
     Future development and abandonment costs   (4,499 )   (6,491 )   (8,827 )   (5,310 )   (5,192 )   (3,489 )   (1,713 )   (221 )   (35,742 )
     Future net inflow before income tax   20,683     14,281     65,005     26,875     29,175     3,011     4,583     3,014     166,627  
     Future income tax   (6,289 )   (9,562 )   (37,108 )   (14,468 )   (7,213 )   (872 )   (910 )   (805 )   (77,227 )
     Future net cash flows   14,394     4,719     27,897     12,407     21,962     2,139     3,673     2,209     89,400  
     10% discount factor   (7,224 )   (1,608 )   (13,117 )   (3,884 )   (14,829 )   (419 )   (1,392 )   (850 )   (43,323 )
     Standardized measure
     of discounted future net cash flows
  7,170     3,111     14,780     8,523     7,133     1,720     2,281     1,359     46,077  
Equity-accounted entities                                                      
     Future cash inflows               498     750           2,893     7,363           11,504  
     Future production costs               (251 )   (98 )         (972 )   (2,676 )         (3,997 )
     Future development and abandonment costs               (35 )   (128 )         (879 )   (1,188 )         (2,230 )
     Future net inflow before income tax               212     524           1,042     3,499           5,277  
     Future income tax               (2 )   (69 )         (338 )   (2,145 )         (2,554 )
     Future net cash flows               210     455           704     1,354           2,723  
     10% discount factor               (113 )   (160 )         (515 )   (852 )         (1,640 )
     Standardized measure
     of discounted future net cash flows
              97     295           189     502           1,083  




























Total   7,170     3,111     14,877     8,818     7,133     1,909     2,783     1,359     47,160  




























December 31, 2011                                                      




























Consolidated subsidiaries                                                      
     Future cash inflows   38,200     37,974     109,825     59,263     50,443     10,403     11,980     5,185     323,273  
     Future production costs   (5,740 )   (7,666 )   (17,627 )   (15,191 )   (7,845 )   (3,852 )   (2,687 )   (813 )   (61,421 )
     Future development and abandonment costs   (4,712 )   (7,059 )   (9,639 )   (5,734 )   (3,705 )   (2,842 )   (1,836 )   (224 )   (35,751 )
     Future net inflow before income tax   27,748     23,249     82,559     38,338     38,893     3,709     7,457     4,148     226,101  
     Future income tax   (9,000 )   (15,912 )   (46,676 )   (23,075 )   (9,866 )   (1,124 )   (2,474 )   (1,254 )   (109,381 )
     Future net cash flows   18,748     7,337     35,883     15,263     29,027     2,585     4,983     2,894     116,720  
     10% discount factor   (9,692 )   (2,572 )   (16,191 )   (4,833 )   (17,599 )   (559 )   (1,914 )   (1,122 )   (54,482 )
     Standardized measure
     of discounted future net cash flows
  9,056     4,765     19,692     10,430     11,428     2,026     3,069     1,772     62,238  
Equity-accounted entities                                                      
     Future cash inflows         21     649     1,866           6,141     15,067           23,744  
     Future production costs         (5 )   (259 )   (471 )         (1,540 )   (4,598 )         (6,873 )
     Future development and abandonment costs         (2 )   (36 )   (147 )         (1,247 )   (1,754 )         (3,186 )
     Future net inflow before income tax         14     354     1,248           3,354     8,715           13,685  
     Future income tax         (3 )   (3 )   (189 )         (824 )   (5,368 )         (6,387 )
     Future net cash flows         11     351     1,059           2,530     3,347           7,298  
     10% discount factor               (183 )   (475 )         (1,825 )   (2,155 )         (4,638 )
     Standardized measure
     of discounted future net cash flows
        11     168     584           705     1,192           2,660  




























Total   9,056     4,776     19,860     11,014     11,428     2,731     4,261     1,772     64,898  




























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Contents

Eni Fact Book Supplemental oil and gas information

   Standardized measure of discounted future net cash flows (euro million)
    Italy   Rest of Europe   North Africa   Sub-Saharan Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total



















December 31, 2012                                                      




























Consolidated subsidiaries                                                      
     Future cash inflows   30,308     38,912     108,343     56,978     53,504     7,881     11,008     4,957     311,891  
     Future production costs   (5,900 )   (8,190 )   (18,555 )   (14,844 )   (9,561 )   (2,854 )   (2,520 )   (921 )   (63,345 )
     Future development and abandonment costs   (3,652 )   (7,511 )   (8,412 )   (6,873 )   (3,802 )   (1,974 )   (1,502 )   (197 )   (33,923 )
     Future net inflow before income tax   20,756     23,211     81,376     35,261     40,141     3,053     6,986     3,839     214,623  
     Future income tax   (6,911 )   (15,063 )   (44,256 )   (21,348 )   (10,293 )   (903 )   (2,906 )   (1,181 )   (102,861 )
     Future net cash flows   13,845     8,148     37,120     13,913     29,848     2,150     4,080     2,658     111,762  
     10% discount factor   (5,519 )   (2,630 )   (16,539 )   (4,976 )   (17,943 )   (496 )   (1,337 )   (1,030 )   (50,470 )
     Standardized measure
     of discounted future net cash flows
  8,326     5,518     20,581     8,937     11,905     1,654     2,743     1,628     61,292  
Equity-accounted entities                                                      
     Future cash inflows         1     658     3,594           6,689     18,132           29,074  
     Future production costs               (203 )   (576 )         (2,216 )   (5,003 )         (7,998 )
     Future development and abandonment costs         (1 )   (17 )   (101 )         (1,061 )   (2,563 )         (3,743 )
     Future net inflow before income tax               438     2,917           3,412     10,566           17,333  
     Future income tax               (36 )   (1,291 )         (795 )   (5,729 )         (7,851 )
     Future net cash flows               402     1,626           2,617     4,837           9,482  
     10% discount factor               (206 )   (962 )         (1,747 )   (3,621 )         (6,536 )
     Standardized measure
     of discounted future net cash flows
              196     664           870     1,216           2,946  
Total   8,326     5,518     20,777     9,601     11,905     2,524     3,959     1,628     64,238  




























 

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Contents

Eni Fact Book Supplemental oil and gas information

   Changes in standardized measure of discounted future net cash flows (euro million)
    Consolidated subsidiaries   Equity-accounted entities   Total







Standardized measure of discounted future net cash flows at December 31, 2009   31,500     257     31,757  










Increase (decrease):                  
- sales, net of production costs   (22,194 )   (243 )   (22,437 )
- net changes in sales and transfer prices, net of production costs   24,415     406     24,821  
- extensions, discoveries and improved recovery, net of future production and development costs   1,926     1,409     3,335  
- changes in estimated future development and abandonment costs   (6,464 )   (386 )   (6,850 )
- development costs incurred during the period that reduced future development costs   8,520     368     8,888  
- revisions of quantity estimates   12,600     143     12,743  
- accretion of discount   6,519     53     6,572  
- net change in income taxes   (11,802 )   (1,115 )   (12,917 )
- purchase of reserves in-place                  
- sale of reserves in-place   (177 )         (177 )
- changes in production rates (timing) and other   1,234     191     1,425  










Net increase (decrease)   14,577     826     15,403  










Standardized measure of discounted future net cash flows at December 31, 2010   46,077     1,083     47,160  










Increase (decrease):                  
- sales, net of production costs   (23,744 )   (300 )   (24,044 )
- net changes in sales and transfer prices, net of production costs   40,961     442     41,403  
- extensions, discoveries and improved recovery, net of future production and development costs   1,580     2,457     4,037  
- changes in estimated future development and abandonment costs   (3,890 )   (392 )   (4,282 )
- development costs incurred during the period that reduced future development costs   7,301     866     8,167  
- revisions of quantity estimates   1,337     (87 )   1,250  
- accretion of discount   8,640     235     8,875  
- net change in income taxes   (17,067 )   (1,678 )   (18,745 )
- purchase of reserves in-place   37     10     47  
- sale of reserves in-place   (146 )         (146 )
- changes in production rates (timing) and other   1,152     24     1,176  










Net increase (decrease)   16,161     1,577     17,738  










Standardized measure of discounted future net cash flows at December 31, 2011   62,238     2,660     64,898  










Increase (decrease):                  
- sales, net of production costs   (28,595 )   (325 )   (28,920 )
- net changes in sales and transfer prices, net of production costs   2,264     (56 )   2,208  
- extensions, discoveries and improved recovery, net of future production and development costs   4,868     812     5,680  
- changes in estimated future development and abandonment costs   (3,802 )   (357 )   (4,159 )
- development costs incurred during the period that reduced future development costs   8,199     409     8,608  
- revisions of quantity estimates   3,725     824     4,549  
- accretion of discount   12,527     477     13,004  
- net change in income taxes   2,207     (830 )   1,377  
- purchase of reserves in-place                  
- sale of reserves in-place   (1,509 )   (615 )   (2,124 )
- changes in production rates (timing) and other   (830 )   (53 )   (883 )










Net increase (decrease)   (946 )   286     (660 )










Standardized measure of discounted future net cash flows at December 31, 2012   61,292     2,946     64,238  










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Contents

Eni Fact Book Quarterly information

Quarterly information

   Main financial data (a) (b)
    2010   2011   2012
   
 
 
(euro million)   I Q     II Q     III Q     IV Q           I Q     II Q     III Q     IV Q           I Q     II Q     III Q     IV Q        

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net sales from operations   24,429     22,426     22,162     27,600     96,617     28,408     24,118     25,516     29,648     107,690     33,140     30,063     31,494     32,523     127,220  
Operating income:   4,750     4,135     3,855     2,742     15,482     5,583     3,604     4,241     3,375     16,803     6,537     2,780     4,072     1,637     15,026  
Exploration & Production   3,297     3,401     3,369     3,799     13,866     4,106     3,693     3,919     4,169     15,887     5,090     4,453     4,361     4,547     18,451  
Gas & Power   798     114     (53 )   37     896     358     (317 )   (170 )   (197 )   (326 )   916     (1,558 )   (764 )   (1,815 )   (3,221 )
Refining & Marketing   105     255     (65 )   (146 )   149     303     73     32     (681 )   (273 )   111     (789 )   454     (1,079 )   (1,303 )
Chemicals   36     17     24     (163 )   (86 )   108     (113 )   (122 )   (297 )   (424 )   (96 )   (134 )   (130 )   (323 )   (683 )
Engineering & Construction   291     334     327     350     1,302     354     366     304     398     1,422     376     364     387     306     1,433  
Other activities   (60 )   (115 )   (58 )   (1,151 )   (1,384 )   (27 )   (138 )   (79 )   (183 )   (427 )   (39 )   (107 )   (48 )   (108 )   (302 )
Corporate and financial companies   (70 )   (82 )   (47 )   (162 )   (361 )   (112 )   (76 )   (85 )   (46 )   (319 )   (84 )   (103 )   (69 )   (89 )   (345 )
Unrealized profit intragroup elimination and consolidation adjustments   353     211     358     178     1,100     493     116     442     212     1,263     263     654     (119 )   198     996  
Net income   2,235     1,803     1,658     556     6,252     2,614     1,197     1,775     1,316     6,902     3,544     156     2,462     (1,964 )   4,198  
Capital expenditure   2,512     4,034     2,511     3,393     12,450     2,615     3,343     2,568     3,383     11,909     2,632     3,015     3,224     3,890     12,761  
Investments   39     76     186     109     410     41     87     92     140     360     245     61     207     56     569  
Net borrowings at period end   21,052     23,342     25,261     26,119     26,119     24,951     25,978     28,273     28,032     28,032     27,426     26,909     19,617     15,511     15,511  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) Quarterly data are unaudited.
(b) In accordance with the guidelines of IFRS 5, results of the Italian regulated businesses managed by Snam divested in accordance to Article 15 of Law Decree No. 1 of January 24, 2012, enacted into Law No. 27 of March 24, 2012 have been reported as discontinued operations from July 1, 2012. Prior year data have been reclassified accordingly.

   Key market indicators
    2010   2011   2012
   
 
 
    I Q   II Q   III Q   IV Q       I Q   II Q   III Q   IV Q       I Q   II Q   III Q   IV Q    

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average price of Brent dated crude oil (a)   76.24   78.30   76.86   86.48   79.47   104.97   117.36   113.46   109.31   111.27   118.49   108.19   109.61   110.02   111.58
Average EUR/USD exchange rate (b)   1.384   1.273   1.291   1.359   1.327   1.367   1.439   1.413   1.348   1.392   1.311   1.281   1.250   1.297   1.285
Average price in euro of Brent dated crude oil   55.09   61.51   59.54   63.64   59.89   76.79   81.56   80.30   81.09   79.94   90.38   84.46   87.69   84.83   86.83
Average European refining margin (c)   2.40   3.39   2.09   2.74   2.66   1.74   1.09   2.87   2.52   2.06   2.92   5.89   7.96   2.54   4.83
Average European refining margins Brent/Ural (c)   3.20   4.56   2.48   3.78   3.47   3.35   2.20   2.92   3.13   2.90   3.26   6.31   7.35   2.83   4.94
Average European refining margins in euro   1.74   2.66   1.62   2.02   2.00   1.27   0.76   2.03   1.87   1.48   2.23   4.60   6.37   1.96   3.76
Price of NBP gas (d)   5.61   5.68   6.68   8.29   6.56   9.09   9.36   8.74   8.92   9.03   9.34   9.09   9.00   10.49   9.48
Euribor - three-month euro rate (%)   0.6   0.7   0.9   1.0   0.8   1.1   1.4   1.6   1.5   1.4   1.0   0.7   0.4   0.2   0.6
Libor - three-month dollar rate (%)   0.3   0.4   0.4   0.3   0.3   0.3   0.3   0.3   0.5   0.3   0.5   0.5   0.4   0.3   0.4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a) In USD per barrel. Source: Platt’s Oilgram.
(b) Source: BCE.
(c) In US$ per barrel FOB Mediterranean Brent dated crude oil. Eni elaborations on Platt’s Oilgram data.
(d) In US$ per BTU. Source Platt’s Oilgram.

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Contents

Eni Fact Book Quarterly information

   Main operating data
    2010   2011   2012
   
 
 
    I Q   II Q   III Q   IV Q       I Q   II Q   III Q   IV Q       I Q   II Q   III Q   IV Q    

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liquids production   (kbbl/d)   1,011   980   948   1,049   997   899   793   793   896   845   867   856   891   912   882
Natural gas production   (mmcf/d)   4,615   4,319   4,203   5,021   4,540   4,356   3,867   3,773   4,345   4,085   4,480   4,394   4,545   4,584   4,501
Hydrocarbons production   (kboe/d)   1,842   1,758   1,705   1,954   1,815   1,684   1,489   1,473   1,678   1,581   1,683   1,647   1,718   1,747   1,701
     Italy       182   185   182   182   183   186   172   193   191   186   188   186   187   195   189
     Rest of Europe       243   208   200   236   222   224   221   203   217   216   206   172   162   172   178
     North Africa       589   583   549   688   602   505   384   367   497   438   570   569   593   610   586
     Sub-Saharan Africa       402   388   407   403   400   375   356   364   381   369   335   332   387   324   345
     Kazakhstan       121   107   85   117   108   117   106   96   105   106   111   106   90   99   102
     Rest of Asia       122   123   125   155   131   120   104   103   121   112   111   127   128   149   129
     America       159   139   128   145   143   131   122   121   128   126   119   119   135   166   135
     Australia and Oceania       24   25   29   28   26   26   24   26   38   28   43   36   36   32   37
Production sold   (mmboe)   158.6   154.1   151.7   173.6   638.0   145.7   129.1   130.0   143.7   548.5   149.2   144.6   150.5   154.4   598.7
Sales of natural gas to third parties   (bcm)   26.51   15.62   14.95   24.38   81.46   27.87   17.33   14.59   21.23   81.02   26.12   16.38   16.56   21.91   80.97
Own consumption of natural gas       1.54   1.53   1.56   1.56   6.19   1.65   1.53   1.41   1.62   6.21   1.77   1.57   1.58   1.51   6.43
Sales to third parties and own consumption       28.05   17.15   16.51   25.94   87.65   29.52   18.86   16.00   22.85   87.23   27.89   17.95   18.14   23.42   87.40
Sales of natural gas of Eni's affiliates (net to Eni)       2.46   2.04   2.09   2.82   9.41   2.81   2.14   1.96   2.62   9.53   2.72   2.20   1.34   1.66   7.92
Total sales and own consumption of natural gas       30.51   19.19   18.60   28.76   97.06   32.33   21.00   17.96   25.47   96.76   30.61   20.15   19.48   25.08   95.32
Electricity sales   (TWh)   9.00   9.61   10.70   10.23   39.54   9.68   9.66   9.55   11.39   40.28   12.29   9.62   10.54   10.13   42.58
Sales of refined products   (mmtonnes)   10.87   11.77   12.01   12.15   46.80   10.34   11.03   13.16   10.49   45.02   10.01   12.73   13.25   12.34   48.33
     Retail sales in Italy       2.01   2.17   2.28   2.17   8.63   1.94   2.14   2.23   2.05   8.36   1.81   1.98   2.24   1.80   7.83
     Wholesale sales in Italy       2.04   2.33   2.50   2.58   9.45   2.19   2.22   2.47   2.48   9.36   2.06   2.18   2.20   2.18   8.62
     Retail sales Rest of Europe       0.67   0.77   0.91   0.75   3.10   0.70   0.76   0.80   0.75   3.01   0.72   0.76   0.81   0.75   3.04
     Wholesale sales Rest
     of Europe
      0.86   0.97   1.06   0.99   3.88   0.81   0.97   1.08   0.98   3.84   0.89   1.03   1.05   0.99   3.96
     Wholesale sales outside
     Europe
      0.09   0.11   0.11   0.11   0.42   0.10   0.11   0.11   0.11   0.43   0.10   0.11   0.10   0.11   0.42
     Other markets       5.20   5.42   5.15   5.55   21.32   4.60   4.83   6.47   4.12   20.02   4.43   6.67   6.85   6.49   24.46



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Contents


Contents


Contents


Contents


Table of Contents
Contents


Contents


Table of Contents
  

  

                 
                Contents  
               
          2 Our activities  
          4 Eni at a glance  
          6 The competitive environment  
          8 Our strategy  
               
            Business review  
               
          10 n Exploration & Production  
          15 n Gas & Power  
  "Eni in 2012" report comprises an extract of the description of the business, the management’s discussion and analysis of financial condition and results of operations and certain other Company information from Eni’s Annual Report for the year ended December 31, 2012. It does not contain sufficient information to allow as full an understanding of financial results, operating performance and business developments of Eni as "Eni 2012 Annual Report". It is not deemed to be filed or submitted with any Italian or US market or other regulatory authorities.
You may obtain a copy of "Eni in 2012" and "Eni 2012 Annual Report" on request, free of charge (see the request form on Eni’s web site –
eni.com – under the section "Publications").
"Eni in 2012" and "Eni 2012 Annual Report" may be downloaded from Eni’s web site under the section "Publications".

Financial data presented in this report is based on consolidated financial statements prepared in accordance with the IFRS endorsed by the EU.
For definitions of certain financial and operating terms see "Frequently used terms" section, on page 43.

This report contains certain forward-looking statements particularly those regarding capital expenditures, development and management of oil and gas resources, dividends, buy-back, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sale growth, new markets and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future.

  Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and regulations; development and use of new technologies; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document.

As Eni shares, in the form of ADRs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F has been filed with the US Securities and Exchange Commission in accordance with the US Securities Exchange Act of 1934.
Hard copies may be obtained free of charge (see the request form on Eni’s web site – eni.com – under the section "Publications"). Eni discloses on its Annual Report on Form 20-F significant ways in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards.
The term "shareholder’" in this report means, unless the context otherwise requires, investors in the equity capital of Eni SpA, both direct and/or indirect.

Eni shares are traded on the Italian Stock Exchange (Mercato Telematico Azionario) and on the New York Stock Exchange (NYSE) under the ticker symbol "E".

  20 n Refining & Marketing  
  25 n Chemicals  
  27 n Engineering & Construction  
       
    Financial review  
       
  30 Group results for the year  
  30           Trading environment  
  30           2012 results  
  32           Outlook for 2013  
  33           Financial risk factors  
  35 Financial information  
  43 n Frequently used terms  
       
  46 Directors and officers  
  50 Investor information  
       
       
                    

Contents

Eni in 2012 Our activities

- 2 -


Contents

Eni in 2012 Our activities

- 3 -


Contents

Eni in 2012 Eni at a glance

     
 

Operating performance
Eni’s adjusted operating profit increased by 14.6%, reflecting excellent results delivered by the Exploration & Production Division on the back of an ongoing recovery in the Libyan production and higher realizations.

Net borrowings and leverage
Eni’s financial structure was strengthened by the divestment of a significant stake in Snam and the deconsolidation of the investee’s finance debt, as well as the start of the commencement of Galp disposition which enabled Eni to nearly cut in half the debt-to-equity ratio.
Net borrowings decreased to euro 15.5 billion.

   

   

Net proved reserves of hydrocarbons
Eni’s net proved oil and gas reserves were at the eight-year record. Achieved an organic reserve replacement ratio of 147% through efficient project sanctioning.

Cash flow and F&D cost per boe
Unit cash flow and the finding and development cost per barrel was driven by competitive exploration costs, efficient development activity and an increased proportion of oil in our new productions.

  

    

   

Injury frequency rate
The injury frequency rate relating to employees and contractors decreased by 12.3% and 21.1% respectively, compared to 2011, progressing for the eighth consecutive year.

Gas flaring
The responsible use of resources was another feature of our 2012 performance where we have achieved an all time low in gas flaring, underpinned by our ability in monetizing our reserves of associated gas by means of marketing it in local outlets and LNG international markets, field reinjection and power plants construction.

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Contents

Eni in 2012 Eni at a glance

  
Energy savings
We continued to upgrade the energy efficiency of our operations in order to achieve a rational use of energy and process optimization. In R&M and Chemicals, initiatives concluded in 2012 allowed to reach important savings.

Diversity and inclusiveness
During the year Eni progressed in the process of enhancing the diversity and the inclusiveness of its people. Plurality is another distinctive elements of Eni’s business featured by a strong international note, with more than 65% of employees outside Italy.

   

   

Capex
Capital expenditure was mainly focused on the robust pipeline of exploration and development projects to exploit oil and gas reserves.

Safety of our employees
We are committed to maintain high standards of safety across all our activities.
Our constant focus on the protection of safety, is confirmed by the 43.3% decrease in the fatality index.

   

   

   

Research and development
Our growth has been supported by technological innovation and the application of advanced methodologies to be applied in harsh contexts, ensuring the protection of the environments and the conservation of sensitive ecosystems and biodiversity.

Customer satisfaction
Our attention to Eni’s customers is confirmed by our competitive and up with the times offer, commercial choices and high quality services, in the G&P where we increased the level of customer satisfaction and in the R&M with initiatives targeted at our customers who join the you&eni Program.

 

- 5 -


Contents

Eni in 2012 The competitive environment

- 6 -


Contents

Eni in 2012 The competitive environment

- 7 -


Contents

Eni in 2012 Our strategy

Our strategy

Eni’s excellent market position and competitive advantages derive from the Company’s strategic choices which are consistent with the long-term nature of the business. Our long-term success owes to a sustainable business model backed by a framework of clear and straightforward rules of corporate governance, rigorous risk management and adoption of the highest ethical standards.

 
In 2012 Eni laid the foundations for a new growth phase of its oil and gas production, one which promises to outperform the industry over the medium and long-term. In the meanwhile, Eni has started the reorganization of its mid and downstream activities to manage the current European downturn. In the Chemical segment, Eni has progressed at repositioning the business to deliver sustainable results. Eni’s strategies, resource allocation processes and management of day-by-day operations underpin sustainable value creation to shareholders and, more generally, to all of our stakeholders.

The oil&gas industry is copying with a complex scenario featured by the global economic slowdown, particularly in the Euro-zone, and volatile market conditions for energy commodities.
Against this backdrop, Eni believes that a sustainable business conduct contributes to both the achievement of industrial performance, and the mitigation of political, financial and operational risks. This strengthens Eni’s role as a trustworthy and reliable partner, who is ready to capture new opportunities in the marketplace and is able to manage the complexities of the environment.

In the medium to long-term, the main challenges will be driven by rising competitive pressures in accessing hydrocarbon reserves, stricter regulation addressing environmental preservation and mitigation of the climate risk, growing importance of renewable sources as well as the role of unconventional resources in satisfying energy needs.

Eni’s strategy for the 2013-2016 four-year period confirms the priorities of profitably growing oil and gas production, recovering profitability in the downstream gas sector, improving efficiency in downstream oil, chemicals and general services supporting business activities, as well as retaining the global leadership in Engineering & Construction focusing on the most technologically advanced

  and innovative segments.
In 2012 following the divestment of a significant interest in Snam and deconsolidation of the investee’s net borrowings as well as the transaction involving Eni’s interest in Galp, the Group achieved a substantial improvement in its leverage at 2012 year end down to 0.25 thanks to euro 19 billion of disposals. This renewed and strengthened balance sheet will help the Company mitigate its greater exposure to the Exploration & Production business. The increased weight of upstream activities in Eni’s portfolio will yield higher returns but also greater risks and volatility compared to the Italian regulated businesses that were divested in 2012. For these reasons, management will remain strongly focused on preserving the Company’s financial structure as well as managing the upstream risks in the foreseeable future. We intend to maintain our leverage within a target range of 0.1-0.3 at our long-term Brent price scenario of $90 a barrel flat in the next four years. This range will allow us to absorb temporary fluctuations in oil prices, the market environment and business results.
Over the next four years, we plan that net cash generated by operating activities will enable Eni to finance a large capital expenditure program amounting to euro 56.8 billion to fuel production growth. In addition we are committed to raise further euro 10 billion from completing the disposal of our residual interests in Snam and Galp and other portfolio transactions.
Given the Company’s changed business profile and improved balance sheet, management plans to distribute cash to shareholders by means of a revised dividend policy and share repurchases. The new dividend policy contemplates a progressive, growing dividend at a rate which is expected to be determined year-to-year taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at gas long-term supply contracts in the Gas & Power segment and the
  delivery of efficiency gains in the downstream businesses.
The other leg of our long-term strategy will be a continuing focus on managing the upstream risks. We intend to mitigate the political risk by expanding the geographic reach of our activities and deploying the Eni cooperation model with host Countries based on the commitment to maximize the value delivered to local communities and invest in long-term initiatives that benefit our local partners (access to energy, education and health). The risk of "project delivery" will require the in-source of critical engineering and project management activities as well as careful monitoring of supply-chain programming. Finally, the operational risk relating to drilling activities will be managed by applying Eni’s rigorous procedures throughout the engineering and execution stages, leveraging on proprietary drilling technologies, internal skills and know-how, increased control of operations and specific technologies aimed at minimizing blow-out risks and responding quickly and effectively in case of emergencies.

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Eni in 2012 Business review / Exploration & Production

   Key performance indicators

       

2010

 

2011

 

2012










Employees injury frequency rate  

(No. of accidents per million of worked hours)

 

0.72

 

0.41

 

0.28

Contractors injury frequency rate      

0.48

 

0.41

 

0.36

Fatality index  

(No. of fatalities per 100 million of worked hours)

 

7.90

 

1.83

 

0.81










Net sales from operations (a)  

(euro million)

 

29,497

 

29,121

 

35,881

Operating profit      

13,866

 

15,887

 

18,451

Adjusted operating profit      

13,898

 

16,075

 

18,518

Adjusted net profit      

5,609

 

6,865

 

7,425

Capital expenditure      

9,690

 

9,435

 

10,307

Adjusted ROACE  

(%)

 

16.0

 

17.2

 

17.6










Profit per boe (b)  

($/boe)

 

11.91

 

16.98

 

15.95

Opex per boe (b)      

6.14

 

7.28

 

7.10

Cash flow per boe (d)      

25.52

 

31.65

 

32.77

Finding & Development cost per boe (c) (d)      

19.32

 

18.82

 

17.37

Average hydrocarbons realizations (d)      

55.60

 

72.26

 

73.39










Production of hydrocarbons (d)  

(kboe/d)

 

1,815

 

1,581

 

1,701

Estimated net proved reserves of hydrocarbons (d)  

(mmboe)

 

6,843

 

7,086

 

7,166

Reserves life index (d)  

(years)

 

10.3

 

12.3

 

11.5

Organic reserves replacement ratio (d)  

(%)

 

127

 

143

 

147










Employees at year end  

(units)

 

10,276

 

10,425

 

11,304

of which: outside Italy      

6,370

 

6,628

 

7,371

Oil spills  

(bbl)

 

3,820

 

2,930

 

3,093

Oil spills from sabotage and terrorism      

18,695

 

7,657

 

8,384

Produced water re-injected  

(%)

 

44

 

43

 

49

Direct GHG emissions  

(mmtonnes CO2 eq)

 

31.20

 

23.59

 

28.46

of which: from flaring      

13.83

 

9.55

 

9.46

Community investment  

(euro million)

 

72

 

62

 

59










(a) Before elimination of intragroup sales.
(b) Consolidated subsidiaries.
(c) Three-year average.
(d) Includes Eni’s share of equity-accounted entities.

 

2012 Highlights

Performance of the year
> In 2012 employees and contractors injury frequency rate declined by 31.7% and 12.2% compared to the previous year.
> Total greenhouse gas emissions increased by 20.6% due to the recovery of activities in Libya. Greenhouse gas emissions from flaring were in line with 2011 (down 0.9%).
> In 2012 the E&P Division reported a record performance with an adjusted net profit amounting to euro 7,425 million (up 8.2% from 2011) driven by an ongoing production recovery in Libya.
  > Eni reported oil and natural gas production for the full year of 1,701 kboe/day (up 7% from 2011) sustained by the recovery of activities in Libya, the start-up/ramp-up of fields, particularly in Russia and Australia, and higher production in Iraq.
> Estimated net proved reserves at December 31, 2012 was an eight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. The organic reserves replacement ratio was 147% with a reserves life index of 11.5 years (12.3
  years in 2011).
> Oil spills increased in the full year (up 5.6% from accidents and up 9.5% from sabotage and terrorism) due to force majeure and security issues in Nigeria.
> Capital expenditure amounted to euro 10,307 million (up 9.2% from 2011) to fuel the growth of major projects in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria.
>
In 2012 overall R&D expenditure of the Exploration & Production Division

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Eni in 2012 Business review / Exploration & Production

amounted to approximately euro 94 million (euro 90 million in 2011).

Mozambique
> The exploration campaign executed in Mozambique in the Area 4 offshore the Rovuma basin proved the Mamba gas complex to be the largest discovery in the Company’s exploration history. Eni estimates the full mineral potential of Area 4 at 80 Tcf of gas in place. The geological studies confirmed the high productivity of exploration wells. This means that this huge resource base can be exploited with a limited number of producing wells that will make the upstream project highly efficient.
> Signed an agreement with Anadarko Petroleum Corporation for the coordinated development of common offshore activities in Area 4, operated by Eni and Area 1, operated by Anadarko. Furthermore, the two companies will jointly plan and construct onshore LNG liquefaction facilities in Northern Mozambique.
> Signed an agreement with CNPC/Petrochina to sell 28.57% of the share capital of our subsidiary Eni East Africa, which currently owns a 70% interest in Area 4 in Mozambique, for an agreed price of $4,210 million in cash. The deal is subject to approval by relevant authorities. Once finalized, CNPC indirectly acquires, through its 28.57% equity investment in Eni East Africa, a 20% interest in Area 4, while Eni will retain a 50% interest through the remaining controlling stake in Eni East Africa.

  Exploration activity
> Full year 2012 was a record for exploration, adding 3.64 bboe of discovered resources, about six times the production of the year, increasing our reserves to best ever levels with rapid time-to-market and cost effectiveness. Our approach in the selective development initiatives, advanced technologies and knowledge management of core basins will be the key to achieve future targets. New resources were, in addition to the above mentioned Mozambique discoveries, the appraisal of the Skrugard/Havis discoveries in the Barents Sea and the Sankofa field in Ghana, a relevant onshore discovery in Pakistan as well as other successes in Egypt, Congo, Indonesia, Angola, the United States and Nigeria.
> Our portfolio was boosted with the acquisition of new exploration acreage in high potential areas such as Kenya, Liberia, Vietnam, Cyprus, offshore Russia and shale gas in Ukraine, as well as legacy areas such as China, Pakistan, Indonesia and Norway.
> Exploration expenditure amounted to euro 1,850 million (up 52.9% from 2011) to complete 60 new exploratory wells (34.1 net to Eni). The overall commercial success rate was 40% (40.8% net to Eni). In addition 144 exploratory wells drilled are in progress at year end (62 net to Eni).

Portfolio
> The international Contracting Companies of the Final Production Sharing Agreement

  (FPSA) of the Karachaganak 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. The Contracting Companies divested 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for $1 billion net cash consideration ($325 million being Eni’s share).
> The Consortium partners and the Authorities of the Republic of Kazakhstan reached an agreement on the Amendment to the sanctioned development plan of the Kashagan field (Amendment 4) which included an update to the project schedule, a revision of the investments estimate and the settlement of all pending claims relating to recoverable costs and other tax matters. The commercial production start-up is expected by the end of the first half of 2013.
> Divested production and development assets in Italy, Nigeria, Norway, the United Kingdom and offshore Gulf of Mexico confirming a selective growth approach to optimize Eni’s asset portfolio and to enhance the competitiveness of Eni’s full-cycle production costs.
> Sanctioned by Venezuelan authorities the development plan of the Perla gas project, in Block Cardón IV (Eni’s interest 50%), in the Gulf of Venezuela. Two more phases were sanctioned to reach a production plateau of approximately 1,200 mmcf/d.
> Made final investment decisions to develop fields in Angola, Congo, Nigeria and Italy which are expected to add 59 kboe/d in 2016.

 

Strategies

Eni’s Exploration & Production business boasts a strong competitive position in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and Sub-Saharan Africa, Venezuela, Russia, the Barents Sea and the Gulf of Mexico. Eni’s strategy is to deliver organic production growth with increasing returns and full reserve replacement. Growth will be fuelled by continuing production start-ups and ramp-ups in Eni’s core areas leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. We intend to drive higher returns and manage the operational risk in our

  upstream operations by reducing time to market, increasing total volumes of operated production as well as selectively picking partners in non-operated joint-projects. Our growth trajectory will be supported by our ongoing commitment in establishing and consolidating our partnerships with key host Countries, leveraging the Eni co-operation model. We expect that continuing technological innovation and competence build-up will drive production growth by increasing rates of reserve recovery, developing drilling techniques to be applied in complex environment to fully exploiting marginal fields and leveraging deep/ultra deep offshore areas potential. Consistent with the long-term nature of the business, strategic guidelines for our Exploration   & Production Division have remained basically unchanged in the years, as follows:

Maintain strong profitable production growth.
Invest in exploration to enhance growth prospects over the long-term and ensure reserve replacement.
Develop new projects to fuel future growth.
Consolidate our industry-leading cost position.

Management plans to invest euro 39.9 billion to develop reserves over the next four years. An important share of these expenditures will be allocated to certain development projects which will support the Company’s long-term production plateau, in particular we plan to

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Eni in 2012 Business review / Exploration & Production

start developing the recent gas discovery offshore Mozambique and to progress large and complex projects in the Barents Sea, Nigeria and Indonesia.
We are also planning to maintain a prevailing share of projects regulated by production sharing agreements in our portfolio; this will shorten cost recovery in an environment of high crude oil prices.

Our long-term sustainable growth will leverage on continuous exploration activities, with planned expenses of euro 5.5 billion, which are intended to pursue finding projects in well-established basins and in high potential frontier areas.

Approximately euro 1.8 billion will be spent to execute development projects through equity-accounted entities.

Maintain strong production growth

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations in 43 Countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the United States, Kazakhstan, Russia, Algeria, Australia, Venezuela, Iraq and Mozambique.
The main driver of future growth will be the start-up of new fields which we estimate to add more than 700 kboe/d of new production by the end of the plan horizon. We have a good level of visibility on those new projects as we have already sanctioned 65% of these projects and we expect to arrive at 90% by the end of 2013.
Management will focus on delivering the planned projects on time and on budget. We acknowledge that most of our projects are complex due to scale and reach of operations, environmentally-sensitive or remote locations, harsh external conditions, industry limits and other considerations.
We intend to implement a number of initiatives to support profitability by exercising tight control on project time schedules and costs and reducing the time span which is necessary to develop and market reserves. We acknowledge that the upstream industry is exposed to the risks of project delays and cost overruns. We plan to mitigate those risks by: (i) in-sourcing critical engineering and project management activities; (ii) strict monitoring

  of construction activities; and (iii) signing framework agreements with major suppliers, using standardized specifications to speed up the pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows.
Eni will pursue further growth options by developing unconventional plays, gas-to-LNG projects and integrated gas projects. Finally, we intend to optimize our portfolio of development properties by focusing on areas where our presence is well established, and divesting non-strategic or marginal assets.

> Production and reserves:
    2012 and outlook
Eni reported liquids and gas production for the full year of 1,701 kboe/d, up 7% from 2011. The performance was driven by an ongoing recovery in Libyan production and continuing field start-up and ramp-up mainly in Russia and Australia, as well as increased production in Iraq. The share of oil and natural gas produced outside Italy was 89%.
In the year we achieved the following main start-ups: (i) the MLE field (Eni’s interest 75%) as part of the MLE-CAFC integrated project, in Algeria. A natural gas treatment plant started operations with a production and export capacity of approximately 320 mmcf/d of gas, 15 kbbl/d of oil and condensates and 12 kbbl/d of LPG; (ii) the Seth field located in the Ras el Barr concession (Eni’s interest 50%). Production is processed at the El Gamil onshore plant. Production plateau is expected at approximately 170 mmcf/d (approximately 11 kboe/d net to Eni); (iii) the satellites Kizomba Phase 1 project in the Development Areas of former Block 15 (Eni’s interest 20%), in Angola. Peak production of 72 kbbl/d (12 kbbl/d net to Eni) is expected in 2013; (iv) Phase 2A project located in service contract OML 119, in Nigeria, with a peak production at 15 kbbl/d; (v) the Samburgskoye field (Eni’s interest 29.4%) located in the Yamal-Nenets area, in Siberia, by means of the first and the second train with an expected production level of 95 kboe/d (28 kboe/d net to Eni).
The outlook for the production of liquids and gas is positive in 2013. Management expects to grow production by ramping-up fields started in 2012 and major project start-ups in 2013, mainly those in Angola and Algeria.
According to management’s plans, production growth will continue in the coming years as the Company is targeting an annual growth rate higher than 4% on average in the next 2013-2016 four-year period, based on our long-term Brent price assumptions of 90 $/bbl.

 

To achieve that target, we intend:
• to leverage our robust pipeline of project start-ups, particularly in North Africa, Sub-Saharan Africa, Venezuela, Barents Sea, Yamal Peninsula, Kazakhstan, Iraq and Far East;
• to maximize the production recovery rate at our current fields by counteracting natural field depletion. We expect a low decline rate of approximately 4% on average in the next four-year period leveraging on dynamic reservoir management and intense production optimization activities;
• to monetize our reserves of associated gas in particular in Africa, targeting to reach zero flaring by 2017.

Actual production volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, severe weather events, price effects under production sharing contracts and other factors.

Estimated net proved reserves at December 31, 2012 was an eight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. Additions to proved reserves booked in 2012 derived from: (i) revisions of previous estimates were 576 mmboe mainly reported in Venezuela, Kazakhstan, Nigeria and Egypt; (ii) extensions, discoveries and other factors were 349 mmboe, with major increases booked in Venezuela, Kazakhstan and Angola; (iii) improved recovery were 28 mmboe mainly reported in Algeria and Nigeria. The reserves life index is 11.5 years.
Eni intends to pay special attention to reserve replacement in order to ensure the medium to long-term sustainability of the business. In 2012, we achieved a strong reserve organic replacement ratio of 147%

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Eni in 2012 Business review / Exploration & Production

through fast sanctioning and time to market of new projects. We made final investment decisions to develop fields in Angola, Congo, Nigeria and Venezuela as well as other minor projects in Italy. Eni will continue focusing on well-established areas of presence where availability of production facilities will enable the Company to readily put in production discovered reserves. We plan to increase returns at our oil and gas projects by reducing time to market, as 90% of the discoveries made in 2008-2012 will reach production within 8 years from their discovery.
Our reserve replacement will be underpinned by our strong focus on exploration and timely conversion of resources into reserves and production, while at the same time fighting depletion and enhancing the recovery factor in existing fields through effective reservoir management.

Exploration

Exploration activities play a major role in our sustainable growth strategy by fuelling new production and securing access to new opportunities.
In 2012 exploration expenditure amounted to euro 1,850 million (up 52.9% from 2011) and extraordinary success was achieved in terms of size and potential of new discoveries. Exploration in 2012 contributed to increase our resource base by 3.64 bboe, about six times the production of the year. Our exploration results support our capacity to deliver sustainable returns on new projects under almost any oil-price scenario with a very competitive discovery cost of 60 cents per barrel. Eni’s resource base achieved 34.5 billion boe.
The exploration campaign executed in Mozambique in Area 4 offshore the Rovuma basin proved the Mamba gas complex to be the largest discovery in the Company’s exploration history. Eni estimates the full mineral potential of Area 4 at 80 Tcf of gas in place. Geological studies confirmed the high productivity of exploration wells. This means that this huge resource base can be exploited with a limited number of producing wells that will make the upstream project highly efficient. On development, we will jointly build with Anadarko onshore LNG facilities in Northern Mozambique. We will now proceed rapidly with the technical and commercial activities. The final investment decision is expected in 2014.

  World-class discoveries have been made in the Barents Sea with the appraisal campaign of the mineral potential at the oil and gas Skrugard discovery and the new Havis oil and gas discovery in the PL532 license (Eni’s interest 30%). Both fields are planned to be put in production by means of a fast-track synergic development. In addition we have made the gas and condensate Salina discovery in the PL 533 license (Eni’s interest 40%). In Ghana, appraisal activities at the Sankofa discovery in the Offshore Cape Three Points license (Eni operator with a 47.22% interest) confirmed the overall potential of the discovery to be around 450 million barrels of oil in place. A relevant onshore discovery was made in Pakistan with estimated resources of 300 to 400 bcf of gas in place and in line with Eni’s strategy of focusing on conventional and synergic assets. Other significant exploration successes were achieved in Egypt, Congo, Indonesia, Angola, the United States and Nigeria where synergies with existing infrastructures will reduce the time-to-market of discovered resources.

Our consistent performance confirms the effectiveness of our exploration strategy, with its focus on proven basins, a select number of high-potential frontier themes and accelerating appraisal campaigns. Building on this success, over the next four years we will confirm our exploration efforts to further strengthen the basis of our long-term growth. Exploration projects will attract some euro 5.5 billion in the next four years to appraise the latest discoveries made by the Company and to support continuing reserve replacement. The most important amounts of exploration expenses will be incurred in Angola, Russia, the United States, Nigeria, Egypt, Norway and Indonesia; important resources will be dedicated to explore new areas (Kenya, Vietnam, Ukraine and Cyprus) and on unconventional plays.
Over the next four years we aim to discover approximately 1 billion boe of resources per year, at an average unit exploration cost of $2 per boe. We will continue to focus on assets with high materiality and fast time to market, concentrating on plays where we have experience and good knowledge of the geological model. We are also renewing our portfolio in new basins close to areas with high demand growth.
As of December 31, 2012, Eni’s mineral right portfolio consisted of 1,072 exclusive or

 

shared rights for exploration and development in 43 Countries on five continents for a total acreage of 251,170 square kilometers net to Eni of which developed acreage was 40,939 square kilometers and undeveloped acreage was 210,231 square kilometers. Eni’s portfolio was boosted with the acquisition of new exploration acreage in high potential areas such as Kenya, Liberia, Vietnam, Cyprus, offshore Russia and shale gas in Ukraine, as well as legacy areas such as China, Pakistan, Indonesia and Norway.

Develop new
projects to fuel
future growth

Eni has a strong pipeline of development projects that will fuel the medium and long-term growth of its oil and gas production.
The pipeline of projects is geographically diversified and will become even more balanced across our hubs.
We expect that costs to develop and operate fields will increase in future years due to sector-specific inflation, and growing complexity of new projects. We plan to counteract those cost increases by leveraging on: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; and (iii) applying our technologies which we believe can reduce drilling and completion costs.

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Eni in 2012 Business review / Exploration & Production

A description of our hubs is provided below.

> Oil & gas major hubs

Africa
Historically, Africa has been the backbone of Eni’s production and growth, and it will be a key driver of our future. Our asset base is robust with a 1.5 million boe/d of operated production. We have major development projects with 5 bboe of 2P reserves, with significant exploration upside of 4.7 bboe of risked resources. Leveraging on our history in the area and long-term relationships we expect to gain further access to new opportunities.

While Libya and Egypt are the pillars of our current production in the area, our main ongoing projects are located in Algeria, Angola and moving to long-term in Mozambique.

Algeria – We achieved the production start-up at the MLE (Eni 75%) field as part of the MLE-CAFC integrated project; and lately, at the El Merk (Eni 12.25%) project. These projects will add 30 kboe/d in 2013 and will grow to 45 kboe/d at the end of 2016.

Angola – Block 15/06 (Eni 35%, Op.) is our major giant development in this Country. The potential resources will be developed within the West Hub and the East Hub projects. Production start-up of the West Hub is expected in 2014 with a peaking production of 25 kbbl/d in 2016. The East Hub will be sanctioned in 2013. Peak production is expected at approximately 15 kbbl/d.

  Kazakhstan
Kazakhstan is one of our legacy Countries where we have interests in the Karachaganak (Eni 29.25%, Op.) and the Kashagan (Eni 16.81%) supergiant fields.
The Karachaganak field still contains about 5 bboe of reserves, approximately four times the amount already produced, with competitive production costs. Phase 3 of development is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation, in stages, of gas treatment plants and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing definition to be presented to the relevant Authorities.
Start-up and commercial production of the Kashagan field is confirmed by the end of the first half of 2013, as agreed with the Republic of Kazakhstan. In 2013 the project will add approximately 20 kboe/d.

Russia
In recent years, project development has been sped up in Russia. We have 5 giant gas and condensates fields (Eni’s interest 29.4%) located in the Yamal Peninsula, in Siberia. In 2012, production started-up at the Samburgskoye field by means of the first and the second train with an expected production level of 95 kboe/d (28 kboe/d net to Eni). In addition, planned activities progressed at the sanctioned Urengoiskoye field. Start-up is expected in 2014. Activities are progressing

  also on the Yaro-Yakhinskoye field. The Yamal hub will provide a plateau of 165 kboe/d by 2016.

Barents Sea
Goliat represents the first oil development in the Barents Sea. We have already obtained governmental approval. Development provides for the use of a cylindrical FPSO unit linked to an underwater production system. Gas produced will be injected in the field. Start-up is expected in 2014 with a production plateau at approximately 100 kbbl/d. Activities progressed at the Skrugard, Havis and Salina discoveries to be developed in future years.

Venezuela
Our main development activities are the Perla (Eni 50%) and Junin 5 (Eni 40%) giant projects. Production started up at the Junin 5 field. Early production of the first phase is expected at plateau of 75 kbbl/d in 2015, targeting a long-term production plateau of 240 kbbl/d to be reached by 2018.
Venezuelan relevant authorities sanctioned the full field development plan of the Perla gas discovery. The early production phase includes the utilization of the already successfully drilled discovery/appraisal wells and the installation of production platforms linked by pipelines to the onshore treatment plant. Target production of approximately 300 mmcf/d is expected in 2015.
Overall the ongoing projects in Venezuela will contribute approximately 50 kboe/d to our production plateau in 2016.

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Eni in 2012 Business review / Gas & Power

   Key performance indicators (*)

       

2010   

 

2011   

 

2012   










Employees injury frequency rate   (No. of accidents per million of worked hours)   3.97     2.44     1.84  
Contractors injury frequency rate       4.00     5.22     3.64  












Net sales from operations (a)   (euro million)   27,806     33,093     36,200  
Operating profit       896     (326 )   (3,221 )
Adjusted operating profit       1,268     (247 )   354  
     Marketing       923     (657 )   45  
     International transport       345     410     309  
Adjusted net profit       1,267     252     473  
Pro-forma adjusted EBITDA       2,562     949     1,314  
     Marketing       1,863     257     856  
     International transport       699     692     458  
Capital expenditure       265     192     225  












Worldwide gas sales (b)   (bcm)   97.06     96.76     95.32  
LNG sales (c)       15.00     15.70     14.60  
Customers in Italy   (million)   6.88     7.10     7.45  
Electricity sold   (TWh)   39.54     40.28     42.58  












Employees at period end   (units)   5,072     4,795     4,752  
Direct GHG emissions   (mmtonnes CO2 eq)   13.41     12.77     12.70  
Customer satisfaction score (CSC) (d)   (%)   87.4     88.6     89.8  
Water consumption/withdrawals per kWh eq produced   (cm/kW eq)   0.013     0.014     0.012  












(*) Following the divestment plan of the Regulated Business in Italy, results of the Gas & Power Division include Marketing and International transport activities. Prior periods have been modified on a like-for-like basis.
(a) Before elimination of intragroup sales.
(b) Include volumes marketed by the Exploration & Production Division of 2.73 bcm (5.65 and 2.86 bcm in 2010 and 2011, respectively).
(c) LNG sales of affiliates and associates of the Gas & Power Division (included in worldwide gas sales) and the Exploration & Production Division.
(d) 2012 figure is calculated as the average of the CSS reviewed by the AEEG in the first half of 2012 and the result reviewed by the Eni satisfaction survey in the second half of 2012.

 

2012 Highlights

Performance of the year
> In 2012, Eni’s continuous commitment and the resources dedicated to safety allowed to improve significantly the accident frequency rate. In particular a positive trend was confirmed for employees (down 24.6% from 2011), while the rate for contractors returned to levels lower than in 2010, improving by 30% from 2011.
> In 2012, the water consumption rate of EniPower’s plants declined both in general (down 11.2% from 2011) and per kWh produced (down 13.8%).
> In 2012, adjusted net profit was euro 473 million, almost doubling the 2011 results. This reflected a better performance of the Marketing business in a context of weak demand and mounting competitive pressures. Declining selling prices were more
  than offset by the benefits associated with the renegotiations of the supply contracts, certain of which with effects retroactive to 2011, and an improved supply mix following the full recovery of Libyan supplies.
> Worldwide gas sales decreased by 1.5% to 95.32 bcm due to lower European demand and competitive pressures. Sales in Italy were in line with 2011, while they declined slightly in European markets, in particular in Benelux due to competitive pressure and in the Iberian Peninsula due to the divestment of Galp.
> Electricity sales of 42.58 TWh increased by 2.30 TWh from 2011, up 5.7%.
> Capital expenditure of euro 225 million concerned essentially flexibility and upgrading of combined cycle power stations (euro 131 million) and initiatives in gas marketing (euro 81 million).
  Commercial Agreements in the Far East
> Eni signed a trilateral agreement with Korea Gas Corporation and Japanese company Chubu Electric Power Company for the sale of 28 loads of LNG (liquefied natural gas) corresponding to 1.7 million tonnes of LNG in the 2013-2017 period.

Entry in the French and Belgian markets
> In October 2012, Eni launched its brand in the gas retail market in France and in the business and retail gas and power market in Belgium. The Eni brand replaced the local brands of the operators acquired in the past few years with the aim of becoming one of the major retail operators in France and Belgium while consolidating its leadership on the Belgian business market.

 

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Eni in 2012 Business review / Gas & Power

Strategies

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.
The natural gas market in Europe is facing a weaker-than-anticipated demand growth due to the economic downturn and rising competitive pressures fuelled by ongoing oversupplies. These trends will reduce sales opportunities and fuel continuing price pressure also considering the rigidities at long-term supply contracts with take-or-pay clauses. Difficult market conditions in the European gas sector are expected to continue at least over the next two years.
Given this challenging market scenario, we intend to improve the profitability at our Gas & Power segment by renegotiating our long-term supply contracts in order to enhance the competitiveness of the Company’s gas offer and to mitigate the take-or-pay risk to our liquidity as we manage through the downturn. We plan to retain our market share in Italy and Europe by leveraging the expected improved costs in procurement and logistics and effective commercial actions. The return to profitability will be helped by developing LNG sales in international markets and optimizing margins by means of our trading activities.

The Gas & Power strategic guidelines are the following:
Renegotiate the bulk of the supply contracts seeking to align supply prices with hub prices less logistic costs and to increase contract flexibility.
Retain the Company’s market share in Italy.
Expand in the industrial and wholesale segments across Europe by developing new structured products.
Leverage on trading activities to boost marketing margins.
Grow LNG sales.

Management believes that profitability in the Company’s gas marketing business will gradually recover along the plan period, however the visibility into future results of operations is constrained by the ongoing volatility in marketing margins. Our profitability outlook factors in the expected benefits of ongoing renegotiations at the Company long-term supply contracts which the Company is seeking to finalize over time

  during the plan period. Currently, 80% of Eni’s supplies are under renegotiation.
Management will also seek to improve profitability by means of cost efficiencies, streamlining business support activities and reducing marketing, general and administrative costs. In addition, the Company intends to capture margins improvements by means of trading activities by entering derivative contracts both in the commodity and the financial trading venues in order to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, and customer base and market position). This can be achieved through strategies of asset-backed trading by entering into arbitrage contracts to leverage on commodity price volatility exploiting the flexibility provided by the Company’s assets.

Gas Market trends

Management expects the outlook in the European gas sector to remain unfavorable over the short to the medium-term due to continuing demand weakness and oversupplies, against the backdrop of the economic downturn.
In the latest years competitive dynamics and the economics of the European gas sector have structurally changed reflecting reduced sales opportunities due to lower gas demand, abundant supplies on the marketplace related to worldwide flows of LNG and continuing pipeline upgrades for importing natural gas from Algeria and Russia to Europe and other factors as the massive increase of shale gas production in the United States which substantially reduced the Country’s dependence on LNG imports.
On the one hand, high liquidity at the main European hubs for spot gas has favored the development of well established market prices which have become the prevailing benchmark for bilateral selling contracts to European customers. In spite of the fact that part of the worldwide LNG surplus has been absorbed by growing energy needs in Asia, spot prices in Europe have been affected by continuing weak trends in demand and rising competitive pressure leading to unrelenting price softness.

  On the other side of the equation, European gas intermediaries, including Eni, have seen their profit margins squeezed by rising trends in costs of oil-linked gas supplies, as provided by pricing formulas in long-term supply contracts. In addition, minimum off-take obligations and the necessity to minimize the associated financial exposure have forced gas operators to compete more aggressively on pricing in consideration of lower selling opportunities, with negative effects on selling prices, and hence profitability.

In 2012, gas demand in Europe declined by 2% (down by 4% in Italy) due to lower consumption in all market segments on the back of the economic downturn. The power generation segment recorded the steepest fall, hit by an ongoing expansion in the use of renewable sources and a shift to coal as feedstock for power plants due to cost advantages. Due to the severity of the contraction in European gas demand and ongoing uncertainties in the macroeconomic outlook, management has revised down its projections of gas demand over the medium to long-term to factor in a number of trends:
• uncertainties and volatility in the current macroeconomic cycle;
• growing adoption of consumption patterns and life-styles characterized by wider sensitivity to energy efficiency; and
• EU policies intended to reduce GHG emissions and promoting renewable energy sources, following prescriptions set by the Climate Change and Renewable Energy package (the so-called PEE 20-20-20).

Management now expects EU demand to increase at an average growth rate of approximately 1.8% along the planning period. Gas demand in Italy is expected to grow with an average rate of approximately 1.7% in the same period. The projected level of gas demand in 2016 is significantly below the level recorded in the pre-crisis years.

As a result of those drivers, we expect that current market imbalances will continue over the next two to three years. Looking beyond, however, we believe that certain potential catalysts may help rebalance the European gas market. Those include: possible developments in the decommissioning of nuclear plants in countries like Japan, Taiwan and in Europe; continuing growth in LNG imports in China, India and other emerging countries in East Asia, Middle East and South America where we expect that consumption

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Eni in 2012 Business review / Gas & Power

will increase significantly mainly driven by robust rates of economic development; the possible enactment of stricter environmental regulation in the EU; and finally we expect that gas production in Europe will progressively decline due to mature field depletion while the gas balance might tighten in the North African area due to growing consumption. Any combination of those possible developments could trigger a recovery in European gas prices and a market tightening. In such an environment, Eni’s competitive advantages given by a solid portfolio of gas contracts, access to infrastructures and storage capacity, innovative product offering and   trading capabilities would drive significant upside potential.

Gas sales:
2012 and outlook

In 2012, sales of natural gas were 95.32 bcm, down 1.44 bcm, or 1.5% from 2011.
Sales volumes on the Italian market were substantially stable at 34.78 bcm (up 0.10 bcm, or 0.3% from 2011). Lower sales to the power generation segment, industrial customers and wholesalers, due to the

  negative scenario and increasing competitive pressure, were offset by higher sales at Italian hubs and, at a lower extent, to the residential segment reflecting efficient commercial initiatives.
Sales on target markets in Europe of 48.29 bcm showed a slight decline from 2011 (down 2.9%). This decline was mainly due to lower sales in Benelux and in the Iberian Peninsula due to the exclusion of Galp sales after the loss of control, offset only in part by increases recorded in France and in Germany/Austria.
Sales to markets outside Europe increased by 0.55 bcm due to higher LNG sales in the Far East, in particular in Japan.

 

   Gas sales by market      (bcm)

       

2010

 

2011

 

2012










ITALY       34.29   34.68   34.78
Wholesalers       4.84   5.16   4.65
Gas release       0.68        
Italian gas exchange and spot markets       4.65   5.24   7.52
Industries       6.41   7.21   6.93
Medium-sized enterprises and services       1.09   0.88   0.81
Power generation       4.04   4.31   2.55
Residential       6.39   5.67   5.89
Own consumption       6.19   6.21   6.43









INTERNATIONAL SALES       62.77   62.08   60.54









Rest of Europe       54.52   52.98   51.02
Importers in Italy       8.44   3.24   2.73
European markets       46.08   49.74   48.29
Iberian Peninsula       7.11   7.48   6.29
Germany/Austria       5.67   6.47   7.78
Benelux       15.64   13.84   10.31
Hungary       2.36   2.24   2.02
UK/Northern Europe       4.45   4.21   4.75
Turkey       3.95   6.86   7.22
France       6.09   7.01   8.36
Other       0.81   1.63   1.56









Extra European markets       2.60   6.24   6.79









E&P in Europe and in the Gulf of Mexico       5.65   2.86   2.73









WORLDWIDE GAS SALES       97.06   96.76   95.32









 

In 2013 management expects to achieve stable natural gas sales compared to 2012 on a homogeneous basis, i.e. excluding the impact of the Galp divestment.

Marketing strategy:
planned actions

Over the 2013-2016 period, Eni’s marketing strategy will focus on certain distinct commercial objectives:

  • to maintain its leadership in the Italian market mainly by strengthening the customer base in the valuable segments of retail consumers and small and medium businesses;
• to strengthen Eni’s position in Europe in the business gas market, where the Company has a well balanced portfolio in terms of geographies, customer segments and contract duration.

In particular management plans to regain market share in Italy and to expand sales in

  European target markets by leveraging first of all on the improved competitiveness of the Company’s cost position reflecting the expected benefits of the renegotiation of its supply contracts. About the marketing effort, we intend to improve the quality of our offer. We are targeting the industrial and wholesale segment across Europe, where we have integrated our commercial and trading operations in order to develop new structured products for those sophisticated customers. Those products will include multiple pricing options and volume flexibility.

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In order to increase exposure to the retail segment, management plans to expand its customer base in Italy and outside Italy, by almost 3 million clients in the next four years to reach a total of 14 million customers by 2016, strengthening Eni’s position in this segment. Particularly in the retail market in Italy, Eni’s marketing action will focus on the combined commercial offer "luce, gas, carburanti" (electricity, gas and fuels), high standards of service, and the adoption of lean marketing procedures to facilitate customers’ tasks and optimization of commercial channels (such as agencies, remote selling, energy stores) with a strong focus on web channels.

Supply

In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets. These contracts have been ensuring approximately 80 bcm/y of gas availability from 2010 (including the Eni Gas & Power NV portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 16 years and a pricing mechanism that indexes the cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.).
In 2012, Eni’s consolidated subsidiaries supplied 86.74 bcm of natural gas, representing an increase of 3.36 bcm, or 4% from 2011. Gas volumes supplied outside Italy (79.19 bcm from consolidated companies), imported in Italy or

 

  sold outside Italy, represented approximately 91% of total supplies, an increase of 3.03 BCM, or 4%, from 2011, mainly reflecting higher volumes   purchased from Libya (up 4.23 BCM), almost tripled from 2011 when the GreenStream gas pipeline had been shutdown.
 

  LNG

Eni is present in all phases of the LNG business: gas feeding, liquefaction, shipping, re-

  gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is synergic with to the Company’s plans to develop its large gas

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reserve base in Africa and elsewhere in the world. The LNG business has been marginally impacted by the economic downturn and oversupply affecting the European gas market, as well as by structural modifications in the US market. LNG flexibility allowed to adapt the business model to a changing market scenario and to increase the value of the commodity entering in new markets. Looking forward, we expect that the LNG business will be one of the major drivers of our Gas & Power Division. We are targeting to increase LNG sales and profitability mainly through cargo diversion to Asia or South America and we have signed long-term supply agreements with clients in East Asia. At present, we participate through our affiliates in a number of facilities located in Spain (regasification) and Egypt (liquefaction). The Company has also access to LNG supplies in Algeria and Qatar. Our main ongoing interest in the LNG business is the joint Pascagoula project with our Exploration & Production business. The Pascagoula project is part of an upstream development project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 bcm/y) in order to monetize part of the Company’s gas reserves.

Power generation

Eni’s main power generation plants are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in various photovoltaic parks.
In 2012, power production was 25.67 TWh, down 0.44 TWh, or 1.7% from 2011, mainly due to

  increased production at the Ferrara plant, offset in part by decreases at the Ferrera Erbognone and Ravenna plants. As of December 31, 2012, installed operational capacity was 5.3 GW. Power availability in 2012 was supported by the growth in electricity trading activities (up 1.86 TWh, or 12.4%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices. By 2015, Eni expects to complete its plans for capacity expansion targeting an installed capacity of 5.4 GW. In the medium term, Eni intends to consolidate operations at its power generation plants and to enhance the flexibility of assets in order to better meet market needs. Furthermore Eni intends to develop the production from renewable sources focusing on photovoltaic power plants, and on the Company’s "Green Chemistry" project for the remediation of the Porto Torres site, where it will be also build a bio-mass power plant.

International transport

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

  Follows a description of the main international pipelines currently participated or operated by Eni.
TTPC The pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.
TMPC The pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.
GreenStream The pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y expandible to 11 bcm/y and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.
• 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.

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   Key performance indicators

       

2010   

 

2011   

 

2012   










Employees injury frequency rate   (No. of accidents per million of worked hours)   1.77     1.96     1.08  
Contractors injury frequency rate       3.59     3.21     2.32  












Net sales from operations (a)   (euro million)   43,190     51,219     62,656  
Operating profit       149     (273 )   (1,303 )
Adjusted operating profit       (181 )   (539 )   (328 )
Adjusted net profit       (56 )   (264 )   (179 )
Capital expenditure       711     866     842  












Refinery throughputs on own account   (mmtonnes)   34.80     31.96     30.01  
Conversion index   (%)   61     61     61  
Balanced capacity of refineries   (kbbl/d)   757     767     767  












Retail sales of petroleum products in Europe   (mmtonnes)   11.73     11.37     10.87  
Service stations in Europe at year end   (units)   6,167     6,287     6,384  
Average throughput per service station in Europe   (kliters)   2,353     2,206     2,064  
Retail efficiency index   (%)   1.53     1.50     1.48  












Employees at period end   (units)   8,022     7,591     7,125  
Direct GHG emissions   (mmtonnes CO2 eq)   7.76     7.23     6.03  
SOx emissions (sulphur oxide)   (ktonnes SO2 eq)   28.05     23.07     16.99  
NOx emissions (nitrogen oxide)   (ktonnes NO2 eq)   7.96     6.74     5.87  
Water consumption rate (refineries)/refinery throughputs   (cm/tonnes)   28.36     30.98     25.33  
Biofuels marketed   (mmtonnes)   17.79     13.26     14.83  
Customer satisfaction index   (likert scale)   7.84     7.74     7.90  












(a) Before elimination of intragroup sales.

 

2012 Highlights

Performance of the year
> The injury frequency rates decreased from 2011 (down 45% for employees and 27.7% for contractors).
> In 2012 the trend in GHG, NOx and SOx, emissions continued to decline, benefiting from energy saving measures and increasing use of natural gas to replace fuel oil.
> The 2012 scenario was weighted down by a steep fall in fuel demand in Italy and continued deteriorating fundamentals in the refining activity. Against this backdrop, Eni’s Refining & Marketing Division managed to reduce adjusted operating loss by euro 85 million from 2011 (down euro 179 million) due to better operating performances and improved efficiency at
  our operated refineries. Results posted by the Marketing activity were impacted by falling demand, high competitive pressure and increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends.
> In 2012 refining throughputs were 30.01 mmtonnes, down 6.1% from 2011. In Italy, processed volumes decreased (down 7.8%) due to the anticipation of scheduled standstills in order to mitigate the negative impact of the trading environment mainly at the Taranto and Gela refineries. Outside Italy, Eni’s refining throughputs increased by 3.2% in particular in the Czech Republic.
  > Retail sales in Italy of 7.83 mmtonnes decreased by 6.3% from 2011. This decline was driven by sharply lower consumption of gasoil and gasoline in Italy (down 8.3% from 2011) and increased competitive pressure. In 2012 Eni’s average retail market share was 31.2% increasing by 0.7 percentage points from 2011 benefiting from the commercial initiatives made in the third quarter of 2012.
> Retail sales in the rest of Europe of 3.04 mmtonnes improved slightly from 2011 (up 1%). Volume additions in Austria and Switzerland, reflecting successful commercial initiatives were offset by lower sales in Eastern Europe due to declining demand.

 

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Eni in 2012 Business review / Refining & Marketing

Strategies

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.
Our Refining & Marketing business has delivered poor results in recent years driven by a weak trading environment. High purchase costs for crude feedstock and oil-linked energy expenses have squeezed refining margins as product prices have lagged behind cost increases due to sluggish demand and excess capacity. At the same time our complex processes have been suffering from narrowing spreads between sour and sweet crudes.
Over the next four years of the industrial plan, management does not expect any

  meaningful improvement in the trading environment. The ongoing economic downturn is anticipated to weigh on a recovery in demand and in refining margins. On the supply side, we see that capacity rationalization is progressing as 11 refineries have shut down in Europe eliminating 1.4 mmboe/d of processing capacity and we believe that a further 15 refineries could potentially close in coming years. However, we assume that the trading environment will not get any benefits from the current rationalization process at least over the short to the medium-term. Retail and wholesale marketing activities of refined products will be affected by sluggish demand and product oversupply that is expected to trigger pricing competition.
Our priority in the Refining & Marketing segment remains to restore profitability and improve the cash generation against the backdrop of weak industry fundamentals. Our strategic guidelines are:
to intensify cost reduction initiatives, energy saving and optimization of plant operations, in order to drive margin expansions;
  to make selective capital expenditure projects;
to enhance profitability at our marketing operations through a number of initiatives for improving service quality and client retention and non-oil profit contribution;
to grow selectively in target European markets and divest marginal assets.
In the four year period, management plans to implement selective capital projects for upgrading refinery complexity and modernizing the retail network for a total amount of euro 2.4 billion. Approximately euro 1.7 billion is expected to be employed to convert the Venice plant into a bio-refinery, upgrade the Company’s best refineries and improving plant efficiency and reliability. Retail activities will attract some 25% of the planned expenditure which will be mainly directed to upgrade and modernize our service stations in Italy and in selected European Countries, and to complete the network rebranding.
Based on these actions, management expects the Refining & Marketing Division to break-even by 2014, assuming the same trading environment as in 2012.

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Refining

> Planned actions
In 2012, Eni’s refining system had total refining capacity (balanced with conversion capacity) of approximately 38.3 mmtonnes (equal to 767 kbbl/d) and a conversion index of 61%. Conversion is a parameter of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies associated with the purchase of heavy crudes that normally trade at discount with reference to the light crude Brent benchmark. Eni’s five 100% owned refineries have balanced capacity of 28.7 mmtonnes (equal to 574 kbbl/d), with a 64% conversion index. In 2012, Eni’s refineries throughputs in Italy and outside Italy were 30.01 mmtonnes.
Against the backdrop of a weak refining scenario, management plans to implement all available levers to improve operations efficiency and profitability by:
• pursuing better integration of refineries and logistic assets and seeking synergies with the Exploration & Production segment to monetize equity crudes and proprietary technologies;
• maximizing refinery flexibility and conversion to extract value from heavy crudes;
• converting the Venice plant into a "bio-refinery" to produce bio-fuels;
• achieving energy efficiency initiatives and ensuring higher rates of plant reliability;
• rationalizing logistic costs and implementing other cost-saving measures;
• strictly selecting capital expenditure; and
• boosting margins leveraging on risk management activities.

> Our assets

ITALY
Eni’s refining system in Italy is composed of five wholly owned refineries and a 50% share in the Milazzo refinery in Sicily. Eni’s refineries in Italy operate and plan in order to maximize asset value according to the markets and the integration with Eni’s other activities.
Sannazzaro refinery has balanced refining capacity of 190 kbbl/d and a conversion index of 59%. Management believes that this site is one of the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-

  Western Italy and Switzerland. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdC), and a visbreaking thermal conversion unit with a gasification facility loaded with heavy residue from visbreaking unit (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. The most important ongoing project is a conversion unit based on the EST (Eni Slurry Technology) proprietary technology which targets the full upgrading of the heavy and extra-heavy barrel. Start-up of this facility is scheduled by 2013. As part of this initiative, Eni is developing the Slurry Dual Catalyst (an evolution of EST), based on a combination of two nano-catalysts, which could lead to a relevant breakthrough in the EST process, increasing its productivity and improving product quality. Another strategic process is the development of a process for hydrogen production, Hydrogen SCT-CPO (Short Contact Time-Catalytic Partial Oxidation) whose design is nearly completed. This reforming technology aims at transforming gaseous and liquid hydrocarbons (also derived from bio-mass) into synthetic gas (carbon monoxide and hydrogen) at competitive costs.
Taranto refinery has balanced refining capacity of 120 kbbl/d and a conversion index of 72%. This refinery process most of oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2012 a total of 2.26 mmtonnes of this oil was processed). It principally produces fuels for automotive use and residential heating purposes for the Southern Italian markets. The complexity is achieved through a Residue Hydroconversion Unit (RHU) - Hydrocracking process and a "Two Stage" Visbreaking-Thermal Cracking unit.
Gela refinery has balanced refining capacity of 100 kbbl/d and a conversion index of 142%. Located on the Southern coast of Sicily, it is integrated with upstream operations processing heavy crude produced from Eni’s nearby offshore and onshore fields. Its high conversion level is ensured by an FCC unit with go-finer for feedstocks upgrading and two coking plants enabling conversion of
  heavy residues topping or vacuum residues. In order to achieve full compliance with the tightest environmental standards, in the power station there is SNOx plant to remove suphur dioxide, nitrogen oxides and particulates from flue gases. An underway refurbishment of the Gela power plant, substantially renewing pet-coke boilers, will increase profitability maximizing synergies from refining and power generation.

OUTSIDE ITALY
In Germany, Eni’s share in the Schwedt refinery is 8.3% and 20% in Bayernoil, an integrated industrial hub that includes the Vohburg and Neustadt refineries. Eni’s refining capacity in Germany is approximately 60 kbbl/d mainly to supply Eni’s distribution network in Bavaria and Eastern Germany. In the Czech Republic, Eni’s share is 32.4% in Ceska Rafinerska, that includes two refineries, Kralupy and Litvinov. Eni’s refining capacity amounts to about 53 kbbl/d to supply Eastern Europe.

> Operational efficiency and
> environmental performance
Eni plans to improve operational efficiency and environmental performance at its refineries.
Our targets in environmental sustainability include energy saving projects aimed at cutting emissions and use of fresh water; in particular our commitment is to reach total savings of 106 ktoe/y (of which 45 ktoe/y from 2013) entailing a saving in CO2 emissions of 307 ktonnes/y (of which 130 ktonnes/y from 2013). Water reuse projects at Gela and Sannazzaro are expected to lead to savings of water of 5 mmcm/y.

Logistics

Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 20 directly managed storage sites and a network of petroleum product pipelines for products sale and storage of LPG and crude. Located in the Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) sites, they reduce logistic costs, and increase efficiency.
Eni’s logistic model is based on a hub structure covering five main areas. These hubs monitor and centralize products flows in order to lower collection and delivery costs. Eni holds five partnerships with major Italian operators.

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Marketing

Eni is the leader in the retail marketing of refined products in Italy with a 31.2% market share, marketing a wide range of refined petroleum products, through an extensive network of operated service stations, franchises and other distribution systems.
In the Marketing activity management intends to preserve profitability by:
• strengthening our leadership in the Italian retail market leveraging on opportunities deriving from the liberalization process (i.e. rationalizing stations with low throughput, boosting full "iperself" mode and development of non-oil activities);
• preserving our customer base by effective marketing actions, rolling out our "eni" brand and service excellence;
• boosting margins by increasing the number of fully automated outlets and the contribution from non-oil products and services; and
• selectively growing our market share in European markets.
Outside Italy, we intend to selectively develop our activities.

In 2012, 2,300 of Eni service stations were re-branded to the "eni brand". We plan to complete this activity by the end of 2013. In spite of a weak domestic demand for fuels and rising competition, management plans to preserve the market share achieved in 2012 (31.2%). We expect that effective marketing campaigns, development of the non-oil offering and continuous network upgrading will underpin our market share and client retention.

In 2012, retail sales in Italy were 7.79 mmtonnes, down 6.5% driven by lower consumption of fuel and gasoline, in particular at highway service stations related to the decline in freight transportation. At December 31, 2012, Eni’s retail network in Italy consisted of 4,780 service stations, 79 more than at December 31, 2011.

 

Co-marketing
During the summer months of 2012, Eni launched a number of co-marketing promotions implemented with important partners, such as Coop, Vodafone and Despar, mainly targeting Italian households. This has been achieved by offering
  significant discounts on primary goods and services. Eni has made an important step to get closer to its customers and will continue to do so also during the second half of 2013 with other co-marketing activities with major national and international brands.

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> Retail – outside Italy
Eni’s strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany, Austria and Eastern Europe (e.g. Czech Republic) leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities.
In 2012, retail sales of refined products marketed in the rest of Europe (3.04 mmtonnes) were basically stable (up 1%). Volume additions in Austria and Switzerland reflecting successful commercial policies were almost completely offset by lower sales in Eastern Europe due to declining demand. At December 31, 2012, Eni’s retail network in the rest of Europe consisted of 1,604 service stations, an increase of 18 units from December 31, 2011.
The key markets of Eni’s presence are: Austria with a 11.7% market share, Hungary with 11.9%, Czech Republic with 10.8%, Slovakia with 9.7%, Switzerland with 7.1% and Germany with a 3.2% on national basis.

> Non-oil
Non-oil activities have become an integral part of our retail business. We have been upgrading our offer of non-oil products and services by carefully selecting our partners and improving quality and reach of the offer. Our most important service stations in Italy are equipped with franchised outlets, which market a wide range of food items, services and other merchandise.
In 2012 we increased our supply of non-oil products and services at our service stations in Italy by developing a chain of franchised outlets, in particular:
• "enicafé", which is a format deployed at 610 stations following the upgrading of existing bars and stores where foods and other services (wifi connection, payments, etc.) are marketed;
• "enishop24", Eni launched a new self-service option h24 of food, non-food and personal care products by means of the installation of eni branded vending machines in 550 outlets;
• "eni carwash", areas for car washing, mainly automatic, which are present in 180 service stations.

  > Wholesale and other businesses
Fuels
Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Along with traditional products provided with the Eni high quality standard, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization present all over Italy and articulated in local marketing offices and a network of agents and concessionaires.
In 2012, sales volumes on wholesale markets in Italy (8.62 mmtonnes) declined by approximately 740 ktonnes, down 7.9%, mainly due to declining sales of gasoline and gasoil related to lower demand from transports and industrial customers due to a generalized slowdown and lower jet fuel sales related to declining demand.

LPG
In Italy, Eni is leader in LPG production, marketing and sale with 614 ktonnes sold for heating and automotive use equal to a 19.8% market share. An additional 206 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna. Outside Italy, LPG sales in 2012 amounted to 515 ktonnes of which 389 ktonnes in Ecuador where Eni’s LPG market share is around 37.8%.

  Lubricants
Eni operates six (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state-of-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases. In 2012, retail and wholesale sales in Italy amounted to 96 ktonnes with a 24.3% market share.

Oxygenates
Eni, through its subsidiary Ecofuel (Eni 100%), sells approximately 1.10 mmtonnes/y of oxygenates, mainly ethers (approximately 3.1% of world demand) and methanol (approximately 0.6% of world demand). About 76% of oxygenates are produced in Eni’s plants in Italy (Ravenna), in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 24% is bought and resold. Eni distributes bio-ETBE in the Italian market in compliance with the new legislation indicating minimum content of bio-fuels. Bio-ETBE like MTBE is an octane booster and gained a relevant position in the formulation of gasoline in European Union because it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. Starting from March 1, 2010, Italian regulation on bio-fuels minimum content changed from 3% to 3.5%. From January 1, 2012, the compulsory content of bio-fuels increased to 4.5% from 4% in 2011 and through bio-ETBE and bio-diesel (of 1st and 2nd generation) blending into fossil fuels Eni covered the compliance within 109.6% in 2012. Eni plans to cover compliance through bio-ETBE, FAME, green diesel from Porto Marghera site, and direct blending of ethanol in gasoline in particular in some extents of Sannazzaro refinery inland.

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Eni in 2012 Business review / Chemicals

   Key performance indicators

       

2010   

 

2011   

 

2012   










Employees injury frequency rate   (No. of accidents per million of worked hours)   1.54     1.47     0.76  
Contractors injury frequency rate       5.94     4.60     1.66  












Net sales from operations (a)   (euro million)   6,141     6,491     6,418  
     Intermediates       2,833     2,987     3,110  
     Polymers       3,126     3,299     3,128  
     Other sales       182     205     180  
Operating profit       (86 )   (424 )   (683 )
Adjusted operating profit       (96 )   (273 )   (485 )
Adjusted net profit       (73 )   (206 )   (395 )
Capital expenditure       251     216     172  












Production   (ktonnes)   7,220     6,245     6,090  
Sales of petrochemical products       4,731     4,040     3,953  
Average plant utilization rate   (%)   72.9     65.3     66.7  












Employees at year end   (units)   5,972     5,804     5,668  
Direct GHG emissions   (mmtonnes CO2 eq)   4.69     4.12     3.69  
NMVOC (Non-Methane Volatile Organic Compound) emissions   (ktonnes)   4.71     4.18     4.40  
SOx emissions (sulphur oxide)   (ktonnes SO2 eq)   3.30     3.17     2.19  
NOx emissions (nitrogen oxide)   (ktonnes NO2 eq)   4.87     4.14     3.43  
Recycled/reused water   (%)   82.7     81.8     81.5  












(a) Before elimination of intragroup sales.

 

2012 Highlights

Performance of the year
> In 2012 the employees and contractors injury frequency rates continued to follow the positive trends of previous years (down 48.3% and 63.9%, respectively).
> In 2012 emissions of greenhouse gases, NOx and SOx decreased due to energy saving.
> In 2012 the sector reported sharply higher operating losses at euro 395 million (down euro 189 million from 2011), due to weak trends in demand reflecting the economic downturn and falling unit margins.
> Sales of petrochemical products were 3,953 ktonnes, down 87 ktonnes, or 2.1% from 2011, due to declining consumption.
> Petrochemical production volumes were 6,090 ktonnes, decreasing by 155 ktonnes, down 2.48%, due a steep decline in demand for petrochemical products in all businesses, in particular the steepest decline was reported in polyethylene.
  > In 2012 overall expenditure in R&D amounted to approximately euro 38 million in line with the previous year. A total of new 18 patent applications were filed, including one in collaboration with our Exploration & Production Division.

Expansion in international markets
> In October 2012, Versalis signed 2 joint venture agreements with major chemical operators in South Korea and Malaysia to build and operate facilities for the production of elastomers incorporating Versalis proprietary technologies and know-how. These initiatives are in line with Eni’s strategy of international expansion in Asian markets with interesting growth prospects.

Bio-based chemicals
> In January 2013, Versalis and Yulex, an agricultural-based bio-materials

  company, signed a strategic partnership to manufacture guayule-based bio-rubber materials in a production complex in Southern Europe. The partnership will cover the entire manufacturing chain. Versalis will produce high-margin materials for consumer and medical specialty markets. The investment will include an ambitious research project to develop technologies targeting the tire industry.
In June 2012, a Memorandum of Understanding was signed with Genomatica and Novamont to establish a technological joint venture in Italy aimed at developing a new technology for the production of butadiene from renewable feedstock. This joint venture will also hold exclusive rights for the industrial application of the research results, including licensing it to third parties.

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Eni in 2012 Business review / Chemicals

Strategies

The chemical industry is subject to fluctuations in demand in response to macroeconomic cycles, leading to volatile results of operations and cash flow. It is a highly competitive industry due to lack of entry barriers, product commoditization and excess capacity, which may exacerbate the impact of any demand downturns on the results reported by Eni’s Chemical business. Eni’s chemical operations have been facing increasing competition from Asian companies and the petrochemical arm of national oil companies based in the Middle East which can leverage on long-term competitive advantages in terms of lower operating costs and cheaper feedstock costs. Management also expects that US-based petrochemical companies will regain competitiveness in the medium term leveraging on the large domestic availability of raw materials which can be extracted from shale gas.
On the back of this scenario, management intends to recover profitability by further rationalizing and integrating Eni’s activities, refocusing Versalis’ portfolio away from loss-making commodity chemicals while at the same time developing innovative and niche productions which are expected to yield better returns. Versalis’ core products will be elastomers, with targeted production growth of over 60% to 2016 and the specialties segment including bio-chemicals.
Particularly, we intend to grow the green chemistry business leveraging on the ongoing project of converting the Porto Torres site into a modern plant for the manufacture of eco-compatible chemical products.

Based on these initiatives, management expects chemical operations to break-even in the next four-year period.

Business areas

> Intermediates
Intermediates petrochemicals account for one of the pillars of the petrochemical activities of Versalis, whose products have a range of important industrial uses, such as the production of polyethylene, polypropylene, PVC and polystyrene. They are also used in the production of petrochemical derivatives that converge, in turn, into a range of other productive processes: plastics, rubbers, fibers, solvents and lubricants.

Intermediate revenues (euro 3,110 million) increased by euro 123 million from 2011 (up

 

  4%) due to the positive performance of derivatives, reflecting increased sales volumes (up 21%) and average unit prices (up 10%) due to a more dynamic market and product availability. Sales volumes of olefins and aromatics declined (down 2% and 4.5%, respectively) due to the shutdown of the polyethylene line in the Sicilian plants due to their lack of profitability and demand decline. Average unit aromatics prices increased by 12% driven by the price of benzene (up 18.7%).

Intermediates production (4,112.5 ktonnes) was in line with last year (up 0.3%). An increase was registered in derivatives (up 12%) for phenol/derivatives and styrene monomer that last year had been affected by the planned facility downtimes at the Mantova plant. Production of olefins and aromatics declined by 2.7% and 5.4%, respectively.

> Polymers
In the polymers business, Versalis is active in the production of (i) polyethylene that accounts for 40% of the total volume of world production of plastic materials. It is a basic plastic material, used as a raw material by companies that transform it into a range of finished goods; (ii) styrenics, which are polymeric materials based on styrenes that are used in a very large number of sectors through a range of transformation technologies. The most common applications are for industrial packaging and in the food industry, small and large electrical appliances, building isolation, electrical and electronic devices, household appliances, car components and toys; (iii) elastomers, which are polymers

  characterized by high elasticity that allow them to regain their original shape even after having been subjected to extensive deformation. Versalis has a leading position in this sector and produces a wide range of products for the following sectors: tyres, footwear, adhesives, building components, pipes, electrical cables, car components and sealings, household appliances; they can be used as modifiers for plastics and bitumens, as additives for lubricating oils (solid elastomers); paper coating and saturation, carpet backing, molded foams, adhesives (synthetic latex). Versalis is one of the world’s major producers of elastomers and synthetic latex.

Polymer revenues (euro 3,128 million) decreased by euro 171 million from 2011 (down 5.2%) due to decreased sales volumes (down 5.8%) resulting from a steep decline in demand in particular on Italian and European markets, offset in part by slight increases in the markets of Eastern Europe.

Unit prices of elastomers declined (down 1.3%) due to lower unit prices for SBR/BR rubbers, affected by the downturn of the automotive industry and of polyethylene (down 0.4%), despite an improvement in the second part of the year.
Polymer production (1,978 ktonnes) decreased by 167 ktonnes from 2011 (down 7.8%), due mainly to a decline in elastomer production (down 9.4%) at Ravenna and Ferrara for the downturn of the automotive industry and of polyethylene (down 6%). The decline in styrene production (down 10.3%) was due to the divestment of compact and expandable polystyrene plant of Feluy (Belgium).

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Eni in 2012 Business review / Engineering & Construction

   Key performance indicators

         

2010

 

2011

 

2012










Employees injury frequency rate   (No. of accidents per million of worked hours)   0.45   0.44   0.54
Contractors injury frequency rate       0.33   0.21   0.17
Fatality index   (No. of fatalities per 100 million of worked hours)   2.14   1.82   0.93









Net sales from operations (a)   (euro million)   10,581   11,834   12,771
Operating profit       1,302   1,422   1,433
Adjusted operating profit       1,326   1,443   1,465
Adjusted net profit       994   1,098   1,109
Capital expenditure       1,552   1,090   1,011









Orders acquired   (euro million)   12,935   12,505   13,391
Order backlog       20,505   20,417   19,739









Employees at period end   (units)   38,826   38,561   43,387
Employees outside Italy   (%)   87.3   86.5   89.2
Local managers       45.3   43.0   42.3
Local procurement       61.3   56.4   51.8
Healthcare expenditure   (euro thousand)   19,506   32,410   21,236
Security expenditure       26,403   50,541   81,777
Direct GHG emissions   (mmtonnes CO2 eq)   1.11   1.32   1.54









(a) Before elimination of intragroup sales.

 

2012 Highlights

Performance of the year
> The percentage of manager positions covered by local personnel is higher than 40% of total managerial positions, except for France and Italy, reflecting however fluctuations due to he opening of new yards and short-term projects.
> The overall amount of procurement was euro 9,584 million, of which euro 7,802 million related to operating projects, 51.8% of which was procured with local suppliers.
> In 2012 the employees injury frequency rate worsened from 2011 (by 22.7%) while it improved for contractors by 19%. Saipem continues to strive to mitigate and reduce
  accidents and injuries to its employees and contractors by means of training and awareness campaigns, such as the "Working at height", the dedicated HSE training portal and training courses for crane operators.
> Safety and environment expenditure increased by 24% from 2011 (from euro 83 million to euro 103 million).
> In 2012 the Engineering & Construction sector reported adjusted net profit amounting to euro 1,109 million, in line with 2011 (up 1%). This result reflects the good operating performance recorded mainly in the Drilling businesses deriving from the full operations of Scarabeo 9 and to greater profitability
  from the Saipem 10000 vessel, almost totally offset by the decline in performance of the Engineering & Construction business due to falling demand for oilfield services and lower margins at certain works related to the general downturn especially in the second half of the year.
> Capital expenditure amounted to euro 1,011 million (euro 1,090 million in 2011) and mainly regarded the upgrading of the drilling and construction fleet.
> In 2012 overall expenditure in R&D amounted approximately to euro 15 million in line with 2011. A total of 13 new patent applications were filed.

 

Strategies

Through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 42.91%), and Saipem’s controlled entities, Eni engages in engineering and construction, as well as offshore and onshore drilling targeting the oil&gas industry. In those

  markets Saipem boasts a strong competitive position, particularly in executing large, complex EPC contracts for the construction of offshore and onshore facilities and systems to develop hydrocarbons reserves as well as LNG, refining and petrochemicals plants, pipeline laying and offshore and onshore drilling services. The Company   owes its market position to technological and operational skills which we believe are acknowledged in the marketplace due to its capabilities to operate in frontier areas and complex ecosystems, efficiently and effectively managing large projects, engineering competencies and availability of technologically-advanced vessels and rigs

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Eni in 2012 Business review / Engineering & Construction

which have been upgraded in recent years through a large capital expenditure plan. Management expects to further strengthen Saipem’s competitive position in the medium term, leveraging on its business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. Based on those strengths we believe that Saipem will be able to overcome current headwinds due to macroeconomic uncertainties and a margin slowdown that are expected to affect the profitability outlook in 2013.

> Engineering & Construction Offshore
Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies ("NOCs"). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, the construction of a large construction yard in Brazil and the acquisition of new rigs in the drilling segments.

In 2012 revenues amounted to euro 5,207 million, increasing by 5.5% from 2011, due to higher levels of activity in the Middle and Far East. Orders acquired amounted to euro 7,477 million (euro 6,131 million in 2011) and related to: (i) an EPCI contract with INPEX for the installation of an underwater pipeline 889-kilometer long linking the offshore Ichthys field with the onshore shut-off valves in the area of Darwin, Australia; (ii) an EPCI contract with Lukoil for the installation of two underwater pipelines linking the offshore Vladimir Filanovsky block in the northern area of the Caspian Sea, with the onshore facility between 10-20

  kilometers inland in the Russian Republic of Kalmyk.

> Engineering & Construction Onshore
In the Engineering & Construction Onshore business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the oil&gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through its technology excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of the Middle East, Caspian Sea, Northern and Western Africa and Russia.

In 2012 revenues amounted to euro 5,745 million, increasing by 3.9% from 2011, due to higher levels of activity in the Middle East and North America. Orders acquired amounted to euro 3,972 million (euro 5,006 million in 2011), declining mainly as a result of the cancellation of the Jurassic contract in the third quarter of 2012.

Among the main orders acquired were: (i)a turn-key contract for Shell concerning the SSAGS (Southern Swamp Associated Gas) project concerning the construction of four compression stations and new production facilities for the treatment of collected gas in various areas of the Delta State in Nigeria; (ii) an EPC contract for Saudi Aramco and Sumitomo Chemical for the Naphtha and Aromatics Package (RP2) of the Rabigh II project.

> Offshore drilling
Saipem is the only engineering and construction contractor that provides also offshore and onshore drilling services to oil

  companies. In the offshore drilling segment Saipem mainly operates in West Africa, the North Sea, the Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum depth of 9,200 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients’ needs and purchase of support equipment).

In 2012 revenues amounted to euro 1,089 million, increasing by 30.6% from 2011. Revenues deriving from the entry in full activity of the semisubmersible rigs Scarabeo 8 and Scarabeo 9 in 2012 were offset in part by the planned facility downtime of the Scarabeo 3 and Scarabeo 6 semisubmersible rigs. Orders acquired amounted to euro 1,025 million (euro 780 million in 2011), relating mainly to the drilling contract of the Scarabeo 7 operating in Indonesian waters; (ii) the contract of the Perro Negro jack up operating in Italian waters.

> Onshore drilling
Saipem operates in this area as a main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this area Saipem can leverage its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments.

In 2012 revenues amounted to euro 730 million, increasing slightly from 2011.
Orders acquired amounted to euro 917 million (euro 588 million in 2011) and related mainly (i) the leasing contract to Saudi Aramco of 15 facilities in Saudi Arabia; (ii) the contracts for 8 facilities to be employed in South America, Saudi Arabia, Kazakhstan, Algeria, Mauritania and Italy.

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Eni in 2012 Group results for the year

Group results for the year

Trading
environment

Eni’s results of operations and the year-to-year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business.

2012 Group results were achieved in a trading environment characterized by a marker Brent price of $111.58 per barrel, almost in line with 2011. The gas market was influenced by weak demand as a consequence of the European economic slowdown and strong competition fuelled by oversupplies. In spite of a 5% rise in European spot prices gas margins were

  squeezed by higher oil-linked supply costs. Refining margins showed a recovery from the depressed levels registered a year ago (the benchmark margin on Brent crude averaged $4.83 per barrel, up $2.77 per barrel). However the absolute size of margins remained in unprofitable territory due to the volatility in the trading environment and weak fuel demand on the back of the economic downturn, excess capacity and high cost of oil feedstock and oil-linked energy utilities. Furthermore, Eni’s complex refineries were impacted by narrowing price differentials between light and heavy crudes. Results for the year were helped by the appreciation of the US dollar over the euro (up 7.7%).

2012 results

In 2012, net profit attributable to Eni’s shareholders from continuing operations was euro 4,198 million, a decrease of euro 2,704 million, down by 39.2% from 2011. The result was negatively impacted by a lower operating profit, down by euro 1,777 million driven by the recognition of impairment losses of euro 4,029 million (euro 1,031 million in

  2011) which were mainly incurred in the gas marketing and refining businesses due to a reduced profitability outlook on the back of the ongoing European downturn. In addition, net profit reflected increased income taxes (up by euro 1,756 million) due to higher taxable income reported by the Exploration & Production Division, subject to higher tax rates, and a write-down of euro 1,030 million recognized at deferred tax assets of Italian subsidiaries. On a positive side, net profit for the year reflected higher net profit from investments (up by euro 758 million) mainly due to gains from the disposal of part of Eni’s interest in Galp and other Galp-related transactions.
Net profit from discontinued operations included results of Snam until loss of control by Eni and the gains recorded both on the divestment of about 30% of Snam to Cassa Depositi e Prestiti for an amount of euro 2,019 million and the fair value revaluation at the residual interest based on current market prices for euro 1,451 million.

Adjusted net profit attributable to Eni’s shareholders including results from discontinued operations amounted to euro 7,788 million, an increase of euro 928 million (up 13.5% from 2011).

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Eni in 2012 Group results for the year

  Results for the year      (euro million)
2010         2011     2012     Change     % Ch.  
















6,252     Net profit attributable to Eni’s shareholders - continuing operations   6,902     4,198     (2,704 )   (39.2 )
(610 )   Exclusion of inventory holding (gains) losses   (724 )   (23 )            
1,128     Exclusion of special items   760     2,953              
      of which:                        
(246 )   - non-recurring items   69                    
1,374     - other special items   691     2,953              
6,770     Adjusted net profit attributable to Eni’s shareholders - continuing operations (a)   6,938     7,128     190     2.7  
















(a) For a detailed explanation of adjusted operating profit and net profit see paragraph "Reconciliation of reported operating and net profit to results on an adjusted basis".

Special charges in operating profit from continuing operations of euro 4,744 million mainly related to:
(i) impairment losses of euro 4,029 million relating to goodwill and other tangible and intangible assets in the gas marketing and the refining businesses. In performing the impairment review, management assumed a reduced profitability outlook in those businesses driven by a deteriorating European macroeconomic environment, volatility in commodity prices and margins, and rising competitive pressures. Other impairment losses were incurred at a number of oil&gas properties in the Exploration & Production Division reflecting downward reserve revisions and a changed pricing environment, as well as marginal lines of business in the Chemical segment due to lack of profitability perspectives;
  (ii) extraordinary expenses and risk provisions of euro 945 million incurred in connection with price revisions at long-term gas purchase contracts which were presented as special items given the contractual time span for price revisions expired in previous periods and relating to gas volumes purchased in previous reporting periods, including the one related to the settlement of an arbitration proceeding with GasTerra;
(iii) a gain on the divestment of a 10% interest in the Karachaganak project to the Kazakh partner KazMunaiGas as part of the settlement agreement (euro 343 million).

Special items in net profit included:
(i) the euro 2.08 billion gains recorded on Galp, including the divestment of a 9% interest (euro 311 million), a revaluation gain of the residual interest in Galp at market

  fair value through profit, following the loss of significant influence over the investee (euro 865 million) as well as a gain recognized through profit on occasion of a capital increase made by Galp’s subsidiary Petrogal which was subscribed by a new partner (euro 835 million);
(ii) a portion of the write-down incurred at Italian subsidiaries’ deferred tax assets (euro 800 million out of a global write-down of euro 1,030 million) which was driven by a lower likelihood of recoverability due to an expected reduction in taxable income generated in Italy, and as Eni has lost the availability of Snam taxable profit against which Italian tax assets can be utilized following the deconsolidation of Snam.

The breakdown of adjusted net profit by Division is shown in the table below:

 

  Adjusted net profit by Division      (euro million)
2010         2011     2012     Change     % Ch.  
















5,609     Exploration & Production   6,865     7,425     560     8.2  
1,267     Gas & Power   252     473     221     87.7  
(56 )   Refining & Marketing   (264 )   (179 )   85     32.2  
(73 )   Chemicals   (206 )   (395 )   (189 )   (91.7 )
994     Engineering & Construction   1,098     1,109     11     1.0  
(216 )   Other activities   (225 )   (247 )   (22 )   (9.8 )
(867 )   Corporate and financial companies   (753 )   (976 )   (223 )   (29.6 )
1,124     Impact of unrealized intragroup profit elimination (a)   1,146     661     (485 )      
7,782     Adjusted net profit - continuing operations   7,913     7,871     (42 )   (0.5 )
      of which attributable to:                        
1,012     - Non-controlling interest   975     743     (232 )   (23.8 )
6,770     - Eni’s shareholders   6,938     7,128     190     2.7  
















(a) This item concerned mainly intragroup sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end period.

> Capital expenditure
In 2012, capital expenditure of continuing operations amounted to euro 12,761 million, mainly relating to:
• development activities deployed mainly in Norway, the United States, Congo,
  Italy, Kazakhstan, Angola and Algeria, and exploratory activities of which 98% was spent outside Italy, primarily in Mozambique, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia;
• upgrading of the Engineering & Construction
  fleet of vessels and rigs (euro 1,011 million);
• projects designed to improve the conversion rate and flexibility of refineries (euro 622 million), in particular at the Sannazzaro refinery, as well as upgrading and rebranding of the refined product retail network (euro 220 million).

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Eni in 2012 Group results for the year

  Capital expenditure by Division      (euro million)
2010         2011     2012     Change     % Ch.  
















9,690     Exploration & Production   9,435     10,307     872     9.2  
265     Gas & Power   192     225     33     17.2  
711     Refining & Marketing   866     842     (24 )   (2.8 )
251     Chemicals   216     172     (44 )   (20.4 )
1,552     Engineering & Construction   1,090     1,011     (79 )   (7.2 )
22     Other activities   10     14     4     ..  
109     Corporate and financial companies   128     152     24     18.8  
(150 )   Impact of unrealized intragroup profit elimination   (28 )   38     66        
12,450     Capital expenditure - continuing operations   11,909     12,761     852     7.2  
1,420     Capital expenditure - discontinued operations   1,529     756     (773 )   (50.6 )
13,870     Capital expenditure   13,438     13,517     79     0.6  
















 

> Sources and uses of cash
The Company’s cash requirements for capital expenditure, dividends to shareholders, and working capital were financed by a combination of funds generated from operations, borrowings and divestments.

Net cash provided by operating activities of continuing operations (euro 12,356 million) and proceeds from disposals of euro 6,014 million funded cash outflows relating to capital expenditure totaling euro 12,761 million and investments (euro 569 million) relating to the acquisition of Nuon in Belgium and joint venture projects, as well as dividend payments amounting to euro 4,379 million (of which euro 1,956 million relating to the 2012 interim dividend and euro 1,884 million to the balance dividend for fiscal year 2011 to Eni’s shareholders and the remaining part related to other dividend payments to non-controlling interests). Disposals of assets mainly regarded the divestment of a 30% interest less one share in Snam to Cassa Depositi e Prestiti (euro 3,517 million), two tranches of the interest in Galp for an overall amount of euro 963 million (a 5% interest sold to Amorim BV and a 4% sold through an accelerated book-building procedure), a 10% interest in the Karachaganak field (approximately euro 500 million) and other non-strategic assets in the Exploration & Production Division (euro 695 million). The proceeds on the divestment of a 5% interest in Snam before loss of control to institutional investors (euro 612 million) were recognized as an equity transaction.

> Capital structure and ratios
Following the divestment of a significant interest in Snam and deconsolidation of the investee’s net borrowings as well as the transaction involving Eni’s interest in Galp, the Group achieved a substantial improvement in its leverage at 2012 year end down to 0.25. Management believes

  that this improved financial position is consistent with the Company’s new business profile, which features greater exposure to the Exploration & Production segment. For planning purposes, management projected the Company’s expected cash flows assuming a scenario of Brent prices at 90 $/bbl for the years 2013-2016 to assess the financial compatibility of its capital expenditure programs and dividend policy with internal targets of ratio of total equity to net borrowing. Under that assumption, in 2013, the ratio of net borrowings to total equity is projected to be substantially in line with the level achieved at the end of 2012, due to cash flows from operations and portfolio management. Going forward, management currently expects to maintain this ratio within a target range of 0.1-0.3. This range will allow us to absorb temporary fluctuations in oil prices, the market environment and business results. The projected future cash flows from operations are estimated to fully fund capital expenditure plans. Furthermore management expects to deliver more than euro 10 billion of additional cash flows from asset disposal, mainly the divestment of the residual interest of Eni in Snam and Galp, the announced divestment of the 28.57% interest in Eni East Africa and other marginal assets in the Exploration & Production segment. Our cash flow projections are based on our Brent scenario of 90 $/bbl flat in the next four years. We note that Brent price in the period January 1 to March 28, 2013 was 112.60 $/bbl on average. We estimated that our cash flow from operations may improve by around euro 120 million for each dollar increase in Brent prices on a yearly basis.

> Returning cash to shareholders
Management plans to pay a dividend of euro 1.08 a share for fiscal year 2012 subject to approval from the General Shareholders’ Meeting scheduled for May 10, 2013. Of this, euro 0.54 per share was paid in September 2012

  as an interim dividend with the balance of euro 0.54 per share expected to be paid in late May 2013. The dividend for fiscal year 2012 represents an increase of 4% compared to the 2011 dividend.
Management has adopted a new dividend policy which contemplates a progressive, growing dividend at a rate which is expected to be determined year-to-year taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at long-term gas supply contracts in the Gas & Power segment and the delivery on efficiency gains in the downstream businesses.
Management also plans to return cash to shareholders by means of a new flexible buy-back program, which has been authorized by the Shareholders’ Meeting for a total amount of euro 6 billion. The buy-back will be activated at management’s sole discretion and when a number of conditions are met. These include, but are not limited to, a level of leverage which management assesses to be sound enough given market conditions and well within our target range limit of 0.3, and full funding of capital expenditure requirements and dividends throughout the plan period. In 2013, management would consider the activation of the buyback program, provided oil prices remain at current levels and Eni makes good progress on its business and cash flow targets.

Outlook for 2013

Management expects an uncertain macroeconomic outlook in 2013, particularly in the Euro-zone where businesses and households are cautious about investments

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and consumption decisions. We expect that a number of factors will support the price of crude oil including ongoing geopolitical risks as well as an improved balance between world demand and supplies of crude oil. For investment evaluation purposes and short-term financial projections, Eni assumes a full-year average price of $90 a barrel for the Brent crude benchmark. Management expects continuing weak conditions in the European gas, refining and marketing of fuels and chemical sectors. Demand for energy commodities is anticipated to remain sluggish due to the ongoing economic stagnation; unit margins are exposed to competitive pressures and the risk of new increases in the costs of oil-based raw materials in an extremely volatile environment. In this scenario, the recovery of profitability in the Gas & Power, Refining & Marketing and Chemical segments will depend greatly on management actions to optimize operations and improve the cost position.
Management expects that year-on-year comparability of results from continuing operations in 2013 will be affected by the fact that in 2012 Snam margins on intra-group transactions relating to the supply of gas transport and other services have been eliminated upon consolidation, while in 2013 those transactions will be accounted as third-party transactions, thus affecting the Group operating costs and profits.

Financial risk factors

> Market risk and sensitivity
> to market environment
Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the euro/$ exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil and gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity. The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and chemical operations depends upon the speed

  at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the euro/$ exchange rate as commodities are generally priced internationally in US dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.
As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, trading activities and risk management and optimization activities as well as, from time to time, to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil and gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives. Due to a changed competitive environment in the European gas market and also considering the development of highly liquid spot markets for gas and volatile gas margins, management has implemented through 2011 new risk management policies and instruments to safeguard the value of the Company’s assets in the gas value chain and to seek to profit from market and trading opportunities. As part of its risk management strategy, the Company actively manages exposure to the commodity risk by entering into commodity derivatives transactions on both financial and physical trading venues targeting different objectives.
(i) On one hand, management enters commodity derivative transactions to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. Management has been implementing tight correlation between such commodity derivatives transactions and underlying physical contracts in order to account for those derivatives in accordance with hedging accounting in compliance with IAS 39, where possible; and (ii) on the other hand, management
  enters purchase/sale commodity contracts for speculative purposes in order to alter the risk profile associated with a portfolio of assets (purchase contracts, transport entitlements, storage capacity) or leverage any price differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of future trends in prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives will be accounted through profit and loss, resulting in higher volatility in the gas business operating profit. These trading activities are executed within limits set by internal policies and guidelines that define the maximum tolerable level of market risk. Furthermore the Company intends to optimize the value of its assets (gas supply contracts, storage sites, transportation rights, customer base, and market position) by effectively managing the flexibilities associated with them. This can be achieved through strategies of asset-backed trading where the underlying items are represented by the Company’s assets. We believe that the risk associated with asset backed trading activities is mitigated by the natural hedge granted by the assets availability. In 2012, Eni’s risk management activities helped reduce the Group exposure to the commodity risk. Furthermore trading activities including asset-backed activities reported a positive contribution to the Group results of operations. We are planning to expand those trading activities both in the Gas & Power and the Refining & Marketing businesses. In fact, in 2012 the Company started a reorganization to integrate the supply activities of the Gas & Power and Refining & Marketing segments together with our trading, risk management and the wholesale activities of gas and LNG. This integration will allow us to capture opportunities from market trends and synergies in commodity risk management.

> Liquidity and counterparty risks
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term finance requirements and to settle obligations.
Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing

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expenses to meet its obligations or, under the worst conditions, the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks.

The actions implemented as part of Eni’s 2012 financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. The minimization of liquidity risks is a strategic driver of the next four-year financial plan. In particular in 2012, Eni issued three bonds addressed to institutional investors for a total amount of euro 1.82 billion, all at fixed rate with maturity of approximately 8 years. In November, as part of the divestment process of its interest in Galp, Eni also issued a convertible bond with underlying Galp shares equal to 8% of the share capital of the investee for a total amount of euro 1.03 billion at fixed rate with a maturity of three years.
Eni’s financial policies are designed to achieve the following targets: (i) ensuring adequate funds to cover short-term obligations and reimbursement of long-term debt due; (ii) maintaining an adequate level of financial flexibility to support Eni’s development plans; (iii) attaining a balance between duration and composition of the finance debt; and (iv) maintaining a cash reserve following the great flow of liquidity achieved from the divestments of 2012, particularly the disposal of Snam. The cash reserve will be commeasured in order to: (i) reduce the refinancing with maturity of one

  year, allowing the Company to be financially independent also in case of negative trends in the trading environment; (ii) increase the level of liquidity to face possible extraordinary needs; and (iii) increase the flexibility of the Company’s financial structure considering lingering uncertainties in the credit markets, in a similar way as the policies adopted by the peer group companies and with a view of improving the Company’s financial rating assessment. Cash stock will be available only for short-term operations with a very low risk profile.

At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements.
At December 31, 2012, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 12,173 million, of which euro 1,241 million were committed, and long-term committed borrowing facilities of euro 6,928 million which were completely undrawn at the balance sheet date. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 12.3 billion were drawn as of December 31, 2012. The Group has credit ratings of A and A-1, respectively, for long and short-term debt assigned by Standard & Poor’s and A3 and P-2 assigned by Moody’s; the outlook is negative in both ratings.
Eni’s credit ratings are potentially exposed to the risk of further downgrading of the sovereign credit rating of Italy in addition to a possible deterioration in the global macroeconomic outlook, particularly the risks of a break-up of the Euro-zone. 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. Eni, through the constant monitoring of the international economic environment and continuing dialogue with financial investors and rating agencies, believes to be ready to perceive emerging critical issues screened by the financial community and to be able to react quickly to any changes in the financial and

  the global macroeconomic environment and implement the necessary actions to mitigate such risks, coherently with Company strategies.

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of business.
The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group Companies and Divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterpart on a daily basis. Exceptional market conditions have forced the Group to adopt contingency plans and under certain circumstances to suspend eligibility to be a Group financial counterparty. Actions implemented also have been intended to limit concentrations of credit risk by maximizing counterparty diversification and turnover.

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Eni in 2012 Financial information

Financial information

Summary
of significant
accounting policies
and practices

Eni prepares its consolidated financial statements in accordance with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Union. Differences in certain respects between IFRS as endorsed by the EU and IFRS as issued by IASB are on matters that do not relate to Eni. On this basis, Eni’s financial statements are fully in compliance with IFRS as issued by IASB.
In 2012, in accordance with the guidelines of IFRS 5, the results of Snam SpA and its subsidiaries (Snam) have been reported as discontinued operations due to Eni’s plan to divest the business. Eni lost control over the entity in October 2012, as part of a transaction to divest approximately 30% of the share capital of Snam to an Italian entity, Cassa Depositi e Prestiti which is a related party of Eni as both entities are under the common control of the Italian Ministry for Economy and Finance. The divestment took place in accordance to Law No. 27 of March 24, 2012, which mandated the ownership unbundling of Snam from Eni. Prior year data have been reclassified in accordance with guidelines of IFRS 5. The residual interest of Eni in Snam equal to 20.2% of the share capital of the investee as of the balance sheet date was accounted as financial instrument because Eni is forbidden from exercising the underlying voting rights by applicable laws and therefore cannot influence the financial and operating policy decisions of the investee. Furthermore, under applicable rules, Eni is mandated to divest any residual interest in the entity.

The consolidated financial statements of Eni include the accounts of the parent company Eni SpA and of all Italian and foreign significant subsidiaries in which Eni directly or indirectly

  holds the majority of voting rights or is otherwise able to exercise control as in the case of "de facto" controlled entities. Control comprises the power to govern the financial and operating policies of the investee so as to obtain benefits from its activities. Immaterial subsidiaries, jointly controlled entities, and other entities in which the Group is in a position to exercise a significant influence through participation in the financial and operating policy decisions of the investee are generally accounted for under the equity method.

Revenues from sales of crude oil, natural gas, petroleum and petrochemical products are recognized when the products are delivered and title passes to the customer. Revenue recognition in the Engineering & Construction Division is based on the stage of completion of contracts as measured on the cost-to-cost basis applied to contractual revenues.

Eni enters into various derivative financial transactions to manage exposures to certain market risks, including foreign currency exchange rate risks, interest rate risks and commodity risks. Such derivative financial instruments are assets and liabilities recognized at fair value starting on the date on which a derivative contract is entered into and are subsequently re-measured at fair value. Derivatives are designated as hedges when the hedging relationship between the hedged item or transaction and the hedging instrument is highly effective and formally documented. Changes in the fair value of cash flow hedges, hedging exposure to variability in cash flows, are recognized in equity, except for the ineffective portion which is recognized in profit or loss; subsequently amounts taken to equity are transferred to the profit and loss account when the hedged transaction affects profit or loss. Changes in fair value of derivatives held for trading purposes, including derivatives for which the hedging relationship is not formally documented or is ineffective, are recognized in profit or loss.

Inventories of crude oil, natural gas and oil products are stated at the lower of purchase

  or production cost and net realizable value. Cost is determined by applying the weighted-average cost method. Contract work in progress is recorded on the basis of contractual considerations by reference to the stage of completion of a contract measured on a cost-to-cost basis.

Property, plant and equipment is stated at cost less any accumulated depreciation, depletion and amortization charges and impairment losses. Depreciation, depletion and amortization of oil and gas properties (capitalized costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas) is calculated based on the Unit-Of-Production (UOP) method on proved reserves or proved developed reserves. Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.

Exploration costs (costs associated with exploratory activities for oil and gas including geological and geophysical exploration costs and exploratory drilling well expenditures) are capitalized and fully amortized as incurred.

Intangible assets are initially stated at cost. Intangible assets having a defined useful life are amortized systematically, based on the straight-line method. Goodwill and intangibles lacking a defined useful life are not amortized but are reviewed periodically for impairment.

Impairment of tangible and intangible assets Eni assesses its property, plant and equipment and intangible assets, including goodwill, for impairment whenever events or changes in circumstances indicate that the carrying values of the assets may not be recoverable. Indications of impairment include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. The recoverability of an asset or group of assets is assessed by comparing the carrying value with the recoverable amount

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represented by the higher of fair value less costs to sell and value in use. In assessing value in use, the Group makes an estimate of the future cash flows expected to be derived from the use of the asset on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years of the estimate and management’s long-term planning assumptions thereafter. Future cash flows are discounted at a rate that reflects current market valuation of the time value of money and those specific risks of the asset that are not reflected in the estimation of future cash flows. The Group uses a discount rate that is calculated as the weighted average cost of capital to the Group (WACC), adjusted to reflect specific Country risks of each asset.

Asset retirement obligations, that may be incurred for the dismantling and removal of assets and the reclamation of sites, are evaluated estimating the costs to be incurred when the asset is retired. Future estimated costs are discounted if the effect of the time value of money is material. The initial estimate is reviewed periodically to reflect changes in circumstances and other factors surrounding the estimate, including the discount rates. The Company recognizes material provisions for asset retirement

  in the upstream business. No significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets are generally recognized, as indeterminate settlement dates for the asset retirement prevent estimation of the fair value of the associated asset retirement obligation.

Provisions, including environmental liabilities, are recognized when the Group has a current (legal or constructive) obligation as a result of a past event, when it is probable that an outflow of resources embodying economic benefit will be required to settle the obligation, and when the obligation can be reliably estimated. The initial estimate to settle the obligation is discounted when the effect of the time value of money is material. The estimate is reviewed periodically to take account of changes in costs expected to be incurred to settle the obligation and other factors, including changes in the discount rates.

Eni is a party to a number of legal proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni’s management believes that ongoing litigations will not have a material adverse effect on Eni’s financial position and results of operations. However, there can be no assurance that in the future Eni will not incur material charges in connection with pending litigations as new information becomes available and new developments may occur. For further information about

  pending litigations, see Note 34 - Legal proceedings - to the consolidated financial statements of 2012 included in Eni’s Annual Report.

The preparation of consolidated financial statements requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Estimates made are based on complex or subjective judgments, past experience, other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of consolidated financial statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the engineering and construction business. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used.

For further information regarding accounting policies and practices, see Note 3 - Summary of significant accounting policies – and Note 5 - Use of accounting estimates – to the consolidated financial statements of 2012 included in Eni’s Annual Report.

 

 

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Eni in 2012 Financial information

  Profit and loss account      (euro million)
    2010     2011     2012  










REVENUES                  
Net sales from operations   96,617     107,690     127,220  
Other income and revenues   967     926     1,546  
    97,584     108,616     128,766  
OPERATING EXPENSES                  
Purchases, services and other   68,774     78,795     95,363  
- of which non-recurring charge (income)   (246 )   69        
Payroll and related costs   4,428     4,404     4,658  
OTHER OPERATING (EXPENSE) INCOME   131     171     (158 )
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS   9,031     8,785     13,561  
OPERATING PROFIT   15,482     16,803     15,026  
FINANCE INCOME (EXPENSE)                  
Finance income   6,109     6,376     7,218  
Finance expense   (6,727 )   (7,410 )   (8,274 )
Derivative financial instruments   (131 )   (112 )   (251 )
    (749 )   (1,146 )   (1,307 )
INCOME (EXPENSE) FROM INVESTMENTS                  
Share of profit (loss) of equity-accounted investments   493     500     278  
Other gain (loss) from investments   619     1,623     2,603  
    1,112     2,123     2,881  
PROFIT BEFORE INCOME TAXES   15,845     17,780     16,600  
Income taxes   (8,581 )   (9,903 )   (11,659 )
Net profit for the year - Continuing operations   7,264     7,877     4,941  
Net profit (loss) for the year - Discontinued operations   119     (74 )   3,732  
Net profit for the year   7,383     7,803     8,673  
Attributable to:                  
Eni                  
- continuing operations   6,252     6,902     4,198  
- discontinued operations   66     (42 )   3,590  
    6,318     6,860     7,788  
Non-controlling interest                  
- continuing operations   1,012     975     743  
- discontinued operations   53     (32 )   142  
    1,065     943     885  










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Eni in 2012 Financial information

  Balance sheet      (euro million)
    Dec. 31, 2011     Dec. 31, 2012  







ASSETS            
Current assets            
Cash and cash equivalents   1,500     7,765  
Other financial assets available for sale   262     235  
Trade and other receivables   24,595     28,621  
Inventories   7,575     8,496  
Current tax assets   549     771  
Other current tax assets   1,388     1,230  
Other current assets   2,326     1,624  
Total current assets   38,195     48,742  
Non-current assets            
Property, plant and equipment   73,578     63,466  
Inventory - compulsory stock   2,433     2,538  
Intangible assets   10,950     4,487  
Equity-accounted investments   5,843     4,265  
Other investments   399     5,085  
Other financial assets   1,578     1,229  
Deferred tax assets   5,514     4,913  
Other non-current receivables   4,225     4,400  
Total non-current assets   104,520     90,383  
Assets held for sale   230     516  
TOTAL ASSETS   142,945     139,641  
LIABILITIES AND SHAREHOLDERS’ EQUITY            
Current liabilities            
Short-term debt   4,459     2,223  
Current portion of long-term debt   2,036     2,961  
Trade and other payables   22,912     23,581  
Income taxes payables   2,092     1,622  
Other taxes payables   1,896     2,162  
Other current liabilities   2,237     1,437  
Total current liabilities   35,632     33,986  
Non-current liabilities            
Long-term debt   23,102     19,279  
Provisions for contingencies   12,735     13,603  
Provisions for employee benefits   1,039     982  
Deferred tax liabilities   7,120     6,740  
Other non-current liabilities   2,900     1,977  
Total non-current liabilities   46,896     42,581  
Liabilities directly associated with assets held for sale   24     361  
TOTAL LIABILITIES   82,552     76,928  
SHAREHOLDERS’ EQUITY            
Non-controlling interest   4,921     3,514  
Eni shareholders’ equity            
Share capital   4,005     4,005  
Reserves related to cash flow hedging derivatives net of tax effect   49     (16 )
Other reserves   53,195     49,579  
Treasury shares   (6,753 )   (201 )
Interim dividend   (1,884 )   (1,956 )
Net profit   6,860     7,788  
Total Eni shareholders’ equity   55,472     59,199  
TOTAL SHAREHOLDERS’ EQUITY   60,393     62,713  
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   142,945     139,641  







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Eni in 2012 Financial information

  Statements of cash flow      (euro million)
    2010     2011     2012  










Net profit of the year - Continuing operations   7,264     7,877     4,941  
Adjustments to reconcile net profit to net cash provided by operating activities:                  
Depreciation and amortization   8,343     7,755     9,538  
Impairments of tangible and intangible assets, net   688     1,030     4,023  
Share of (profit) loss of equity-accounted investments   (493 )   (500 )   (278 )
Gain on disposal of assets, net   (558 )   (1,176 )   (875 )
Dividend income   (264 )   (659 )   (431 )
Interest income   (95 )   (99 )   (108 )
Interest expense   607     773     803  
Income taxes   8,581     9,903     11,659  
Other changes   (39 )   331     (1,945 )
Changes in working capital:                  
- inventories   (1,141 )   (1,400 )   (1,395 )
- trade receivables   (1,923 )   218     (3,184 )
- trade payables   2,811     34     2,029  
- provisions for contingencies   575     109     338  
- other assets and liabilities   (1,480 )   (657 )   (1,161 )
Cash flow from changes in working capital   (1,158 )   (1,696 )   (3,373 )
Net change in the provisions for employee benefits   22     (10 )   16  
Dividends received   766     955     988  
Interest received   124     99     91  
Interest paid   (630 )   (927 )   (825 )
Income taxes paid, net of tax receivables received   (9,018 )   (9,893 )   (11,868 )
Net cash provided by operating activities - Continuing operations   14,140     13,763     12,356  
Net cash provided by operating activities - Discontinued operations   554     619     15  
Net cash provided by operating activities   14,694     14,382     12,371  
Investing activities:                  
- tangible assets   (12,308 )   (11,658 )   (11,222 )
- intangible assets   (1,562 )   (1,780 )   (2,295 )
- consolidated subsidiaries and businesses   (143 )   (115 )   (178 )
- investments   (267 )   (245 )   (391 )
- securities   (50 )   (62 )   (17 )
- financing receivables   (866 )   (715 )   (1,634 )
- change in payables and receivables in relation to investing activities and capitalized depreciation   261     379     54  
Cash flow from investing activities   (14,935 )   (14,196 )   (15,683 )
Disposals:                  
- tangible assets   272     154     1,229  
- intangible assets   57     41     61  
- consolidated subsidiaries and businesses   215     1,006     3,521  
- investments   569     711     1,203  
- securities   14     128     52  
- financing receivables   841     695     1,578  
- change in payables and receivables in relation to disposals   2     243     (252 )
Cash flow from disposals   1,970     2,978     7,392  
Net cash used in investing activities   (12,965 )   (11,218 )   (8,291 )
Proceeds from long-term debt   2,953     4,474     10,484  
Repayments of long-term debt   (3,327 )   (889 )   (3,784 )
Increase (decrease) in short-term debt   2,646     (2,481 )   (753 )
    2,272     1,104     5,947  
Net capital contributions by non-controlling interest         26        
Sale of treasury shares         3        
Net acquisition of treasury shares different from Eni SpA   37     17     29  
Acquisition of additional interests in consolidated subsidiaries         (126 )   604  
Dividends paid to Eni’s shareholders   (3,622 )   (3,695 )   (3,840 )
Dividends paid to non-controlling interest   (514 )   (552 )   (539 )
Net cash used in financing activities   (1,827 )   (3,223 )   2,201  
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)         (7 )   (4 )
Effect of exchange rate changes on cash and cash equivalents and other changes   39     17     (12 )
Net cash flow of the year   (59 )   (49 )   6,265  
Cash and cash equivalents - beginning of the year   1,608     1,549     1,500  
Cash and cash equivalents - end of the year   1,549     1,500     7,765  










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Non-GAAP measures

> Reconciliation of reported operating profit and reported net profit to results on an adjusted basis
Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses, special items and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates which impact industrial margins

  and translation of commercial payables and receivables. Accordingly also currency translation effects recorded through profit and loss are reported within business segments’ adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (38% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models. The following   is a description of items that are excluded from the calculation of adjusted results.

Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting.

Special items include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on

 

  2012      (euro million)
    OTHER ACTIVITIES (a)   DISCONTINUED OPERATIONS  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   GROUP   Snam   Consolidation adjustments   Total   CONTINUING OPERATIONS





























Operating profit   18,451     (3,221 )   (1,303 )   (683 )   1,433     (345 )   1,676     (302 )   208     15,914     (1,676 )   788     (888 )   15,026  
Exclusion of inventory holding (gains) losses         163     (29 )   63                             (214 )   (17 )                     (17 )
Exclusion of special items:                                                                                    
  - asset impairments   550     2,494     846     112     25                 2           4,029                       4,029  
  - gains on disposal of assets   (542 )   (3 )   5     1     3           (22 )   (12 )         (570 )   22           22     (548 )
  - risk provisions   7     831     49     18           5           35           945                       945  
  - environmental charges         (2 )   40                       71     25           134     (71 )         (71 )   63  
  - provision for redundancy
    incentives
  6     5     19     14     7     11     2     2           66     (2 )         (2 )   64  
  - re-measurement gains/losses
    on commodity derivatives
  1                 1     (3 )                           (1 )                     (1 )
  - exchange rate differences
    and derivatives
  (9 )   (51 )   (8 )   (11 )                                 (79 )                     (79 )
  - other   54     138     53                             26           271                       271  
Special items of operating profit   67     3,412     1,004     135     32     16     51     78           4,795     (51 )         (51 )   4,744  
Adjusted operating profit   18,518     354     (328 )   (485 )   1,465     (329 )   1,727     (224 )   (6 )   20,692     (1,727 )   788     (939 )   19,753  
Net finance (expense) income (b)   (248 )   31     (4 )   (1 )         (861 )   (51 )   (22 )         (1,156 )   51           51     (1,105 )
Net income (expense) from investments (b)   436     261     63     2     55     99     38     (1 )         953     (38 )         (38 )   915  
Income taxes (b)   (11,281 )   (173 )   90     89     (411 )   115     (712 )         2     (12,281 )   712     (123 )   589     (11,692 )
Tax rate (%)   60.3     26.8     ..           27.0           41.5                 59.9                       59.8  
Adjusted net profit   7,425     473     (179 )   (395 )   1,109     (976 )   1,002     (247 )   (4 )   8,208     (1,002 )   665     (337 )   7,871  
of which attributable to:                                                                                    
- non-controlling interest                                                         885                 (142 )   743  
- Eni’s shareholders                                                         7,323                 (195 )   7,128  
Net profit attributable to Eni’s shareholders                                   7,788                 (3,590 )   4,198  
Exclusion of inventory holding (gains) losses                                   (23 )                     (23 )
Exclusion of special items                                   (442 )               3,395     2,953  
Adjusted net profit attributable to Eni’s shareholders                                   7,323                 (195 )   7,128  





























(a) Following the divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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divestments even though they occurred in past periods or are likely to occur in future ones; or (iii) exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency. Those items are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the exchange rate market. As provided for in Decision No. 15519 of July 27, 2006, of the Italian market regulator   (Consob), non recurring material income or charges are to be clearly reported in the management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non hedging commodity derivatives, including the ineffective portion of cash flow hedges and certain derivatives financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production Division.

Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents

  not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment-operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production Division). Finance charges or interest income and related taxation effects excluded from the adjusted net profit of the business segments are allocated on the aggregate corporate and financial companies. For a reconciliation of adjusted operating profit and adjusted net profit to reported operating profit and reported net profit see tables below.

 

  2011      (euro million)
    OTHER ACTIVITIES (a)   DISCONTINUED OPERATIONS  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   GROUP   Snam   Consolidation adjustments   Total   CONTINUING OPERATIONS





























Operating profit   15,887     (326 )   (273 )   (424 )   1,422     (319 )   2,084     (427 )   (189 )   17,435     (2,084 )   1,452     (632 )   16,803  
Exclusion of inventory holding (gains) losses         (166 )   (907 )   (40 )                                 (1,113 )                     (1,113 )
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges                     10                       59           69                       69  
Other special (income) charges   188     245     641     181     21     53     27     142           1,498     (27 )         (27 )   1,471  
  - asset impairments   190     154     488     160     35           (9 )   4           1,022     9           9     1,031  
  - gains on disposal of assets   (63 )         10           4     (1 )   (4 )   (7 )         (61 )   4           4     (57 )
  - risk provisions         77     8                 (6 )         9           88                       88  
  - environmental charges               34     1                 10     141           186     (10 )         (10 )   176  
  - provision for redundancy
    incentives
  44     34     81     17     10     9     6     8           209     (6 )         (6 )   203  
  - re-measurement gains/losses
    on commodity derivatives
  1     45     (3 )         (28 )                           15                       15  
  - exchange rate differences
    and derivatives
  (2 )   (82 )   (4 )   3                                   (85 )                     (85 )
  - other   18     17     27                 51     24     (13 )         124     (24 )         (24 )   100  
Special items of operating profit   188     245     641     191     21     53     27     201           1,567     (27 )         (27 )   1,540  
Adjusted operating profit   16,075     (247 )   (539 )   (273 )   1,443     (266 )   2,111     (226 )   (189 )   17,889     (2,111 )   1,452     (659 )   17,230  
Net finance (expense) income (b)   (231 )   43                       (876 )   19     5           (1,040 )   (19 )         (19 )   (1,059 )
Net income (expense) from investments (b)   624     363     99           95     1     44     (3 )         1,223     (44 )         (44 )   1,179  
Income taxes (b)   (9,603 )   93     176     67     (440 )   388     (918 )   (1 )   78     (10,160 )   918     (195 )   723     (9,437 )
Tax rate (%)   58.3     ..     ..           28.6           42.2                 56.2                       54.4  
Adjusted net profit   6,865     252     (264 )   (206 )   1,098     (753 )   1,256     (225 )   (111 )   7,912     (1,256 )   1,257     1     7,913  
of which attributable to:                                                                                    
- non-controlling interest                                                         943                 32     975  
- Eni’s shareholders                                                         6,969                 (31 )   6,938  
Net profit attributable to Eni’s shareholders                             6,860                 42     6,902  
Exclusion of inventory holding (gains) losses                             (724 )                     (724 )
Exclusion of special items:                             833                 (73 )   760  
- non-recurring charges                             69                       69  
- other special (income) charges                             764                 (73 )   691  
Adjusted net profit attributable to Eni’s shareholders                             6,969                 (31 )   6,938  





























(a) Following the divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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  2010      (euro million)
    OTHER ACTIVITIES (a)   DISCONTINUED OPERATIONS  
   
 
 
    Exploration & Production   Gas & Power (a)   Refining & Marketing   Chemicals   Engineering & Construction   Corporate and financial companies   Snam   Other activities   Impact of unrealized intragroup profit elimination   GROUP   Snam   Consolidation adjustments   Total   CONTINUING OPERATIONS





























Operating profit   13,866     896     149     (86 )   1,302     (361 )   2,000     (1,384 )   (271 )   16,111     (2,000 )   1,371     (629 )   15,482  
Exclusion of inventory holding (gains) losses         (117 )   (659 )   (105 )                                 (881 )                     (881 )
Exclusion of special items                                                                                    
of which:                                                                                    
Non-recurring (income) charges         (270 )               24                             (246 )                     (246 )
Other special (income) charges:   32     759     329     95           96     46     1,179           2,536     (46 )         (46 )   2,490  
  - asset impairments   127     426     76     52     3           10     8           702     (10 )         (10 )   692  
  - gains on disposal of assets   (241 )         (16 )         5           4                 (248 )   (4 )         (4 )   (252 )
  - risk provisions         78     2                 8           7           95                       95  
  - environmental charges   30     16     169                       9     1,145           1,369     (9 )         (9 )   1,360  
  - provision for redundancy
    incentives
  97     52     113     26     14     88     23     10           423     (23 )         (23 )   400  
  - re-measurement gains/losses
    on commodity derivatives
        30     (10 )         (22 )                           (2 )                     (2 )
  - exchange rate differences
    and derivatives
  14     195     (10 )   17                                   216                       216  
   - other   5     (38 )   5                             9           (19 )                     (19 )
Special items of operating profit   32     489     329     95     24     96     46     1,179           2,290     (46 )         (46 )   2,244  
Adjusted operating profit   13,898     1,268     (181 )   (96 )   1,326     (265 )   2,046     (205 )   (271 )   17,520     (2,046 )   1,371     (675 )   16,845  
Net finance (expense) income (b)   (205 )   34                 33     (783 )   22     (9 )         (908 )   (22 )         (22 )   (930 )
Net income from investments (b)   274     362     92     1     10           44     (2 )         781     (44 )         (44 )   737  
Income taxes (b)   (8,358 )   (397 )   33     22     (375 )   181     (667 )         102     (9,459 )   667     (78 )   589     (8,870 )
Tax rate (%)   59.8     23.9     ..           27.4           31.6                 54.4                       53.3  
Adjusted net profit   5,609     1,267     (56 )   (73 )   994     (867 )   1,445     (216 )   (169 )   7,934     (1,445 )   1,293     (152 )   7,782  
of which attributable to:                                                                                    
- non-controlling interest                                                         1,065                 (53 )   1,012  
- Eni’s shareholders                                                         6,869                 (99 )   6,770  
Net profit attributable to Eni’s shareholders                             6,318                 (66 )   6,252  
Exclusion of inventory holding (gains) losses                             (610 )                     (610 )
Exclusion of special items:                             1,161                 (33 )   1,128  
- non-recurring charges                             (246 )                     (246 )
- other special (income) charges                             1,407                 (33 )   1,374  
Adjusted net profit attributable to Eni’s shareholders                             6,869                 (99 )   6,770  





























(a) Following the divestment plan, Snam results are reclassified from "Gas & Power" sector to "Other activities" and accounted as discontinued operations.
(b) Excluding special items.

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For a reconciliation of Summarized Group Balance Sheet and Summarized Group Cash Flow Statement with the corresponding statutory tables see Eni’s 2012 Annual Report, "Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes" pages 86-88.

 

> Summarized Group Balance Sheet
The Summarized Group Balance Sheet aggregates the amount of assets and liabilities derived from the statutory balance sheet in accordance with functional criteria which consider the enterprise conventionally divided into the three fundamental areas
  focusing on resource investments, operations and financing. Management believes that this Summarized Group Balance Sheet is useful information in assisting investors to assess Eni’s capital structure and to analyze its sources of funds and investments in fixed assets and working capital. Management   uses the Summarized Group Balance Sheet to calculate key ratios such as the proportion of net borrowings to shareholders’ equity (leverage) intended to evaluate whether Eni’s financing structure is sound and well-balanced.

 

  Summarized Group Balance Sheet      (euro million)
    Dec. 31, 2011     Dec. 31, 2012  







Fixed assets            
Property, plant and equipment   73,578     63,466  
Inventories - Compulsory stock   2,433     2,538  
Intangible assets   10,950     4,487  
Equity-accounted investments and other investments   6,242     9,350  
Receivables and securities held for operating purposes   1,740     1,457  
Net payables related to capital expenditure   (1,576 )   (1,142 )
    93,367     80,156  







Net working capital            
Inventories   7,575     8,496  
Trade receivables   17,709     19,966  
Trade payables   (13,436 )   (14,993 )
Tax payables and provisions for net deferred tax liabilities   (3,503 )   (3,318 )
Provisions   (12,735 )   (13,603 )
Other current assets and liabilities   281     2,347  
    (4,109 )   (1,105 )







Provisions for employee post-retirement benefits   (1,039 )   (982 )
Assets held for sale including related liabilities   206     155  







CAPITAL EMPLOYED NET   88,425     78,224  







- Eni shareholders’ equity   55,472     59,199  
- Non-controlling interest   4,921     3,514  
Shareholders’ equity   60,393     62,713  
Net borrowings   28,032     15,511  







TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   88,425     78,224  







 

> Net borrowings and leverage
Eni evaluates its financial condition by reference to net borrowings, which is calculated 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.
Leverage is a measure used by management to assess the Company’s level of indebtedness. It is calculated as a ratio of net borrowings
  which is calculated by excluding cash and cash equivalents and certain very liquid assets from financial debt to shareholders’ equity, including non-controlling interest. Management periodically reviews leverage in order to assess the soundness and efficiency of the Group Balance Sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards.

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  Net borrowings and leverage      (euro million)
    Dec. 31, 2011     Dec. 31, 2012  







Total debt   29,597     24,463  
- Short-term debt   6,495     5,184  
- Long-term debt   23,102     19,279  
Cash and cash equivalents   (1,500 )   (7,765 )
Securities held for non-operating purposes   (37 )   (34 )
Financing receivables for non-operating purposes   (28 )   (1,153 )
Net borrowings   28,032     15,511  
Shareholders’ equity including non-controlling interest   60,393     62,713  
Leverage   0.46     0.25  







             
> Summarized Group Cash Flow
     Statement and Change in net
     borrowings
Eni’s summarized Group Cash Flow Statement derives from the statutory statement of cash flows. It enables investors to understand the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow
  statement) that occurred from the beginning of the period to the end of period. The measure enabling such a link is represented by the free cash flow which is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/receivables (issuance/repayment of debt and receivables   related to financing activities), shareholders’ equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; and (ii) change in net borrowings for the period by adding/deducting cash flows relating to shareholders’ equity and the effect of changes in consolidation and of exchange rate differences. The free cash flow is a non-GAAP measure of financial performance.
         
  Summarized Group Cash Flow Statement     (euro million)
    2010     2011     2012  










Net profit - continuing operations   7,264     7,877     4,941  
Adjustments to reconcile net profit to net cash provided by operating activities:                  
- depreciation, depletion and amortization and other non-monetary items   8,521     8,606     11,354  
- net gains on disposal of assets   (558 )   (1,176 )   (875 )
- dividends, interest, taxes and other changes   8,829     9,918     11,923  
Changes in working capital related to operations   (1,158 )   (1,696 )   (3,373 )
Dividends received, taxes paid, interest (paid) received during the period   (8,758 )   (9,766 )   (11,614 )
Net cash provided by operating activities - continuing operations   14,140     13,763     12,356  
Net cash provided by operating activities - discontinued operations   554     619     15  
Net cash provided by operating activities   14,694     14,382     12,371  
Capital expenditure - continuing operations   (12,450 )   (11,909 )   (12,761 )
Capital expenditure - discontinued operations   (1,420 )   (1,529 )   (756 )
Capital expenditure   (13,870 )   (13,438 )   (13,517 )
Investments and purchase of consolidated subsidiaries and businesses   (410 )   (360 )   (569 )
Disposals   1,113     1,912     6,014  
Other cash flow related to capital expenditure, investments and disposals   228     627     (136 )
Free cash flow   1,755     3,123     4,163  
Borrowings (repayment) of debt related to financing activities   (26 )   41     (83 )
Changes in short and long-term financial debt   2,272     1,104     5,947  
Dividends paid and changes in non-controlling interests and reserves   (4,099 )   (4,327 )   (3,746 )
Effect of changes in consolidation area and exchange differences   39     10     (16 )
NET CASH FLOW   (59 )   (49 )   6,265  










                   
  Change in net borrowings     (euro million)
    2010     2011     2012  










Free cash flow   1,755     3,123     4,163  
Net borrowings of acquired companies   (33 )         (2 )
Net borrowings of divested companies         (192 )   12,446  
Exchange differences on net borrowings and other changes   (687 )   (517 )   (340 )
Dividends paid and changes in non-controlling interest and reserves   (4,099 )   (4,327 )   (3,746 )
CHANGE IN NET BORROWINGS   (3,064 )   (1,913 )   12,521  










                   
> Pro-forma adjusted EBITDA
EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization charges) on an adjusted basis is calculated by adding amortization and depreciation charges to
  adjusted operating profit, which is also modified to take into account the impact associated with certain derivatives instruments as detailed below. This performance indicator includes the adjusted EBITDA of Eni’s wholly owned   subsidiaries and Eni’s share of adjusted EBITDA generated by certain associates which are accounted for under the equity method for IFRS purposes. In order to calculate the EBITDA pro-forma adjusted, the adjusted operating profit

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of the Marketing business has been modified to take into account the impact of the settlement of certain commodity and exchange rate derivatives that do not meet the formal criteria to be classified as hedges under the IFRS. These are entered into by the Company in view of certain amounts of gas and electricity that the Company expects to supply at fixed prices during future periods. The impact of those derivatives has been allocated to the EBITDA pro-forma adjusted relating to the reporting periods during which those supplies at fixed prices are recognized. Management believes that the EBITDA pro-forma adjusted is an important alternative measure to assess the performance of Eni’s Gas & Power Division, taking into account evidence that this Division is comparable to European utilities in the gas and power generation sector. This measure is provided in order to assist investors and financial analysts in assessing the divisional performance of Eni Gas & Power, as compared to its European peers, as EBITDA is widely used as the main performance indicator for utilities. The EBITDA pro-forma adjusted is a non-GAAP measure under IFRS.

> Production sharing agreements (PSA)
Contract in use in non OECD Countries, regulating relationships between States and oil companies with regard to the exploration and production of hydrocarbons. The mining concession is assigned to the national oil company jointly with the foreign oil company who has exclusive right to perform exploration, development and production activities and can enter 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, "Profit Oil" is divided between contractor and national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions may vary from one Country to the other.

> 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.

  > 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.

> Recoverable reserves
Amounts of hydrocarbons included in different categories of reserves (proved, probable and possible), without considering their different degree of uncertainty.

> Reserves
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 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. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods.

> 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 value of reserves – in PSAs – due to changes in international oil prices. Management also calculates this ratio by excluding the effect of the purchase of proved property in order to better assess the underlying performance of the Company’s operations.

> Average reserve life index
Ratio between the amount of reserves at the end of the year and total production for the year.

> Resource base
Oil and gas volumes contained in a reservoir as ascertained based on available engineering and geological data (sum of proved, probable and possible reserves) plus volumes not yet discovered but that are expected to be eventually recovered from the reservoir net of a risk factor (risked exploration resources).

> 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.

> Conversion
Refinery process allowing the transformation of heavy fractions into lighter fractions. Conversion processes are cracking, visbreaking, coking, the gasification of refinery residues, etc. The ratio of overall treatment capacity of these plants and that of primary crude fractioning plants is the conversion rate of a refinery. Flexible refineries have higher rates and higher profitability.

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Was born in 1964 and has been Chairman of the Board of Eni since May 2011. He is also Vice Chairman of GE Capital Interbanca SpA; a member of the Board of Directors and of the Audit Committee of Exor SpA; a member of the European Advisory Board of Blackstone and a member of the Massachusetts Institute of Technology E.I. External Advisory Board. He is also a member of the Italian Corporate Governance Committee, of the executive committees of Confindustria (where he chairs the Foreign Investment Committee), Assonime (Association of Italian Joint Stock Companies), Aspen Institute Italia; a member of the Board of Directors of FEEM-Eni Enrico Mattei Foundation, of the Italian Institute of Technology and of the LUISS Business School Advisory Board. He is co-Chair of the B20 Task Force on Improving Transparency and Anti-Corruption and director of the World Economic Forum Partnering Against Corruption Initiative. He holds a degree in Engineering from the Polytechnic of Turin. In 1989 he started his career as entrepreneur at Recchi SpA, a general contractor active in 25 Countries in the construction of high-tech public infrastructure. Since 1994 he has served as Executive Chairman of Recchi America Inc., the US branch of Recchi Group. In 1999 he joined General Electric, where he held several management positions in Europe and in the United States. He served as Director of GE Capital Structure Finance Group; Managing Director for Industrial M&A and Business Development for GE EMEA; President & CEO of GE Italy. Until May 2011 he was President & CEO of GE South Europe. Mr. Recchi was a member of the Organizing Committee for the Rome Candidacy for the 2020 Olympic Games, of the Board of Permasteelisa SpA, of the Advisory Board of Invest Industrial (private equity) and visiting professor in Structured Finance at Turin University.

Has been Chief Executive Officer of Eni since June 2005. He is currently a Non-Executive Director of Assicurazioni Generali, Non-Executive Deputy Chairman of the London Stock Exchange Group and a Non- Executive Director of Veolia Environnement. He also sits on the Board of Overseers of Columbia

  Business School and of Fondazione Teatro alla Scala. After receiving a degree in economics and business from Luigi Bocconi University in Milan in 1969, he worked for three years at Chevron, before obtaining an MBA from Columbia University, New York, and continuing his career at McKinsey. In 1973 he joined Saint Gobain, where he held a series of management positions in Italy and abroad, until his appointment as head of the glass division in Paris in 1984. From 1985 to 1996 he was Deputy Chairman and CEO of Techint. In 1996 he moved to the UK and served as CEO of Pilkington until May 2002.
From May 2002 to May 2005 he served as Chief Executive Officer and General Manager of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro of the Italian Republic. In November 2007 he was decorated as an Officier of the French Légion d’Honneur.

Was born in 1941 and has been a Director of Eni since May 2011. He graduated from the University of Turin with a degree in Economics and Business. He is a certified public auditor. He is currently Chairman of the Board of Statutory Auditors of RAI SpA, Natuzzi SpA, Difesa Servizi SpA, Rainet SpA and Director of Arcese Trasporti SpA. He has taught courses in Finance, Administration and Control at the Isvor Fiat SpA training institute. In 1968 he was hired by Impresit as Chief Accountant, where he managed the finance department of the local branch in Jordan. He joined the Fiat Group in 1969 where over the years he held a series positions of increasing responsibility in the area of finance, administration and control. From 1979 to 1990 he was in charge of Financial Reporting at the Fiat Group and was also responsible for controlling the transport companies of the Fiat Group operating public transport concessions (Sapav, Sadem, Sita) and oversaw their subsequent sale. In 1990 he was appointed Joint Manager of Finance and Control of the Fiat Group, before becoming, in 1998, Chief Administration Officer (CAO). From 2000 to 2004, he was Chief Executive Officer and Deputy Chairman of Business Solutions, a new sector created by Fiat to provide business services. In 1993 he was the Italian Representative to the European Commission for the fiscal harmonization of the Member States. In 1992 he was decorated as Cavaliere Ordine al Merito of the Italian Republic and, in 1995, an Ufficiale Ordine al Merito of the Italian Republic.

 

Was born in 1948 and has been a Director of Eni since May 2011. He is currently a founding partner of Tokos Srl, a securities investment consulting firm, and Chairman of Società Metropolitana Acque Torino SpA, and a Director of Ersel SIM SpA, Millbo SpA and Sicme Motori Srl. He began his career at SAIAG SpA, in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined the GFT Group, where he was head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of the GFT Group (1984-1988), Head of Finance and Control of the GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Central Manager and, subsequently, Director of Ersel SIM SpA, a position he held until June 2000. In 2000 he became Central Manager of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of the Coin Group. In 2006 he became Central Corporate Manager at Lavazza SpA, serving as a member of the Board of Directors from 2008 to June 2011.

Was born in 1969 and has been a Director of Eni since June 2008. He is a lawyer specializing in criminal and administrative law, and has been admitted to argue before the Supreme Court and the higher Courts. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010. He serves as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the

(*) Appointed by the Ordinary Shareholders’ Meeting held on May 5, 2011, for a three-year period. The Board of Directors appointed Paolo Scaroni Chief Executive Officer. The Board mandate will expire with the shareholders’ meeting approving the financial statements for the year ending December 31, 2013.

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Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola waste water consortium, the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of the Stresa (VB) city council. From October 2001 to April 2004 he was a Director of CIM SpA of Novara (merchandise interport centre) and from December 2002 to December 2005 a Director and executive committee member of Finpiemonte SpA. From June 2005 to June 2008 he was a Director of Consip SpA. He was Vice President and Provincial Councillor in charge of the budget, financial reporting, property, legal affairs and productive activities of the Province of Verbano-Cusio-Ossola from June 2009 to October 2011. He was Director of the Provincial Board of the Province of Verbano-Cusio-Ossola from October 2011 to November 2012.

Has been a Director of Eni since May 2011. He was born in Pescara in 1949 and graduated with a degree in law from "Gabriele D’Annunzio" University of Chieti and Pescara. He has been a member of the Board of Directors of the Ravenna Festival since 2007 and he has been Chairman of Italimmobili Srl since 2011. In 1976 he was hired by Banca Nazionale del Lavoro (BNL) where he held a series of positions: Head of the "Lending Advisory" of BNL in Busto Arsizio (1982), Deputy Manager for the industrial division at the BNL branch in Ravenna (1983-1987), Area Chief of BNL in Venice (1987-1989) and Joint Manager of the central office of BNL in Rome (1989-1990). In 1990 he was appointed Commercial Manager at Banca Popolare and in 1994 he transferred, holding the same position, to Cassa di Risparmio di Ravenna Group (Carisp Ravenna and Banca di Imola). From 2001 to 2006 he was Chief Secretary to the Under-Secretary of Defence, where he was mainly involved in the Defence Ministry’s contacts with industry and international relations. From 2008 to 2011 he was Chief Secretary of the Minister of Defence. From 2003 to 2006 he was a Director of Fintecna SpA and from 2005 to 2008 a Director of Finmeccanica SpA.

Was born in 1957 and has been Director of Eni since May 2011. He received a degree in Business Administration from Università Luigi Bocconi of Milan. He is currently Chairman of Banca Monte dei Paschi di Siena, of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also member of the Board of Directors of the Bocconi University in Milan. He began his career

  in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development projects at Bain, Cuneo e Associati firm (now Bain & Co). In 1991 he left the consulting field to join RAS, Riunione Adriatica di Sicurtà, where he was given responsibility, as General Manager, for the banking and parabanking sectors.
He was also in charge of expanding the revenues of that group’s bank and of the other group companies operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager, with responsibility for Programming and Control, becoming General Manager in 1995. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On an international level he was Chairman of the European Banking Federation in Bruxelles and Chairman of the Internal Monetary Conference Washington. In May 2004 he was decorated as a Cavaliere del Lavoro.

Was born in 1945 and has been a Director of Eni since May 2002. He graduated from the Università Luigi Bocconi of Milan with a degree in Economics and Business. He is also Chairman of Confimprese, Deputy Chairman of Sesto Immobiliare SpA and Director of Mondadori SpA. After graduating, he joined Chase Manhattan Bank. In 1974 he was appointed manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner at Egon Zehnder. In this period he was appointed Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonald’s Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners, Chairman of the American Chamber of Commerce, General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities and Chairman of Convention Bureau Italia SpA. He was decorated as a Cavaliere del Lavoro in June 2002.

Was born in 1940 and has been a Director of Eni since June 2008. He is currently Vice Chairman of Banca CR Firenze SpA (Cassa di Risparmio di Firenze SpA). He is also a Director and member of the Executive Committee of Rimorchiatori Riuniti SpA. He started working in 1959 in a stock brokerage in Milan. From 1965 to 1982, he worked at Banco

  di Napoli as deputy manager of the stock market and securities department. He held a series of management positions in the asset management field, notably as manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime group (1987 to 2000), he was Chief Executive Officer of the parent company for an extended period of time. He was Director of ERSEL SIM, member of the steering council of Assogestioni and of the Committee for the Corporate Governance of listed companies formed by Borsa Italiana. He was a Director of Enel from October 2000 to June 2008.

BOARD COMMITTEES
Control and Risk Committee:
Alessandro Lorenzi - Chairman, Carlo Cesare Gatto, Paolo Marchioni and Francesco Taranto
Compensation Committee:
Mario Resca - Chairman, Carlo Cesare Gatto, Roberto Petri and Alessandro Profumo
Nomination Committee:
Giuseppe Recchi - Chairman, Alessandro Lorenzi, Alessandro Profumo and Mario Resca
Oil - Gas Energy Committee:
Alessandro Profumo - Chairman, Alessandro Lorenzi, Paolo Marchioni, Roberto Petri, Mario Resca and Francesco Taranto

BOARD OF STATUTORY AUDITORS
Ugo Marinelli - Chairman, Roberto Ferranti, Paolo Fumagalli, Renato Righetti, Giorgio Silva, Francesco Bilotti and Maurizio Lauri

EXTERNAL AUDITORS
Reconta Ernst & Young SpA

GROUP OFFICERS
Paolo Scaroni
Chief Executive Officer and General Manager
Claudio Descalzi
Exploration & Production Chief Operating Officer
Umberto Vergine (a)
Gas & Power Chief Operating Officer
Angelo Fanelli
Refining & Marketing Chief Operating Officer
Massimo Mondazzi
Chief Financial Officer
Salvatore Sardo
Chief Corporate Operations Officer
Stefano Lucchini
Senior Executive Vice President for International Relations and Communication
Massimo Mantovani
Senior Executive Vice President for General Counsel Legal Affairs
Roberto Ulissi
Senior Executive Vice President for Corporate Affairs and Governance
Marco Petracchini
Senior Executive Vice President for Internal Audit
Marco Alverà
Senior Executive Vice President for Trading
Salvatore Meli
Executive Vice President for Research and Technological Innovation
Leonardo Bellodi
Executive Vice President for Government Affairs
Stefano Leofreddi
Senior Vice President for Integrated Risk Management
Raffaella Leone
Executive Assistant to the Chief Executive Officer

(a) In charge until December 4, 2012; since December 5, 2012 Paolo Scaroni has been Gas & Power Chief Operating Officer ad interim.

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> Remuneration1
The Eni Remuneration Policy is defined consistently with the recommendations of the Borsa Italiana Code as transposed in the Eni Code. It is approved by the Board of Directors following a proposal by the Compensation Committee, made up of non-executive, independent Directors, and is
  defined in accordance with the governance model adopted by the Company and with the recommendations of the Corporate Governance Code.
This Policy aims to align the interests of management with the prime objective of creating sustainable value for shareholders over the medium-long term, in accordance
  with the guidelines defined in the Strategic Plan of the Company.
The table describes the main elements of the approved 2013 Guidelines for the remuneration of the Chief Executive Officer and General Manager (CEO/GM), of the Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities (MSR).
         
Remuneration Policy 2013
Component Aims and characteristics Implementation condition Values
Fixed remuneration Reflects the skills, experiences and contribution related to the assigned role Setting of the remuneration levels through benchmarks consistent with Eni and with the responsibilities of the specific roles CEO/GM euro 1,430,000 annually (unchanged since 2005)
MSR: remuneration determined on the basis of the level of the specific role with possible adjustments in relation to competitive placement targets (average market values)
Annual variable incentives Promotes the achievement of annual budget objectives
All the managers participate in the Plan
Target incentives assigned are differentiated based on different roles
Incentives paid on the basis of results achieved in the previous year
CEO/GM Objectives:
- Implementation of strategic, financial and sustainability guidelines (30%)
- Operational Performance of Divisions (30%)
- Adjusted EBIT (30%)
- Efficiency program (10%)
MSR objectives: business and individual objectives determined based on those of the CEO/GM and on the responsibilities assigned
Performance scale for each objective 70÷130 points (*); minimum threshold for the incentive equal to a total performance of 85 points
CEO/GM: on-target bonus of 110% of the fixed remuneration (min. 87.5% and max. 155%)
MSR: on-target incentives up to a maximum 60% of the fixed remuneration
Deferred Monetary Incentive
(2012-2014 Plan)
Promotes the business profitability growth in the long-term
All managers who have reached the annual objectives participate in the Plan
Target incentives assigned are differentiated based on specific roles
EBITDA performance measured against the EBITDA value as per the Plan
Amount assigned on the basis of the EBITDA results achieved in the previous year evaluated in accordance with the performance scale 70÷130 (*)
Amount paid as a variable percentage between zero and 170% of the amount assigned, on the basis of the average results achieved in the vesting period, evaluated in accordance with the performance scale 70÷170 (*)
Vesting period: three years
  
CEO/GM: on-target incentive assigned of 55% of the fixed remuneration
(min. 38.5% and max. 71.5%)
MSR: on-target incentives assigned up to a maximum 40% of the fixed remuneration
Long-Term Monetary Incentive
(2012-2014 Plan)
Promotes a business long-term profitability growth superior of that of the peers
Managers who are critical for the business participate in Plan
Target incentives assigned are differentiated based on specific roles
Performance measured in terms of the variation of the Adjusted Net Profit + DD&A, compared to the ones reported by the main Oil Majors in the Eni Peer group (Exxon, Shell, Chevron, BP, Total, Conoco)
Incentive paid as a variable percentage between zero and 130% of the assigned amount, based on the average annual placement achieved in the vesting period:
1° Place 130%
     2° Place 115%      3° Place 100%      4° Place 85%
———————————————————————————————————
5° Place 70%
     6° Place 0%      7° Place 0%

Vesting period: three years

CEO/GM: on-target incentive assigned to target on the basis of the annual value of the previous stock option plan
MSR: on-target incentives assigned up to a maximum 50% of the fixed remuneration
Benefits The remuneration package is integrated with social security and insurance-related benefits, according to a "total reward" approach Conditions defined by the national collective labor agreement and complementary company level agreements applicable to senior managers - Supplementary pension plan
- Supplementary health plan
- Insurance coverages
- Company car

(*) Performance rated below the minimum threshold (70 points) is considered equal to zero.

Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the following table below reports individual remuneration paid in 2012 to each Member of the Board of Directors, Statutory Auditors, and Chief Operating Officers. The overall amount earned by other Managers with strategic responsibilities is reported too.
In compliance with the rule, the table provides details on:
• "Fixed remuneration" which includes, following the criteria of competence, fixed remuneration and fixed salary from employment due for the year, gross of social security and tax expenses to be paid by the employee; it excludes lump-sum expense reimbursements and attendance fees, as they are not envisaged;
• "Committees membership remuneration" which reports, following the criteria of
  competence, the compensation due to the Directors for participation in the Committees established by the Board;
• "Variable non-equity remuneration - Bonuses and other incentives" which reports the incentives paid during the year due to the vesting of the relative rights following the assessment and approval of the relative performance results by the relevant company bodies, in accordance with that specified, in greater detail, in the Table "Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities"; the column "Profit sharing", does not include any figures, as no form of profit-sharing is envisaged;
• "Non-monetary benefits" which reports, in accordance with competence and taxability criteria, the value of fringe benefits awarded;
  • "Other remuneration" reports, in accordance with the criteria of competence, any other remuneration deriving from other services provided;
• "Total" which reports the sum of the amounts of all the previous items;
• "Fair value of equity remuneration" which reports the fair value of competence of the year related to the existing stock option plans, estimated in accordance with international accounting standards which assign the relevant cost in the vesting period;
• "Severance indemnities for end of office or termination of employment" which reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of financial year considered or in relation to the end of the office and/or employment.

(1) For detailed information on Eni’s remuneration policy and compensation see the “Remuneration Report 2013” available on Eni’s website under the sections “Governance” and “Investor relations”.

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Remuneration paid to Directors, Statutory Auditors, Chief Operating Officers, and other Managers with strategic responsibilities
(euro thousand)   Variable non-equity remuneration    
   
   
Name   Office   Term of office   Office expiry (*)   Fixed remuneration   Committee membership remuneration   Bonuses and other incentives   Profit sharing   Non-monetary benefits   Other remuneration   Total 2012   Fair Value of equity remuneration   Severance indemnity for end of office or termination of employment

























Board of Directors                                                
Giuseppe Recchi   Chairman   01.01 - 31.12   04.2014   765       245       4       1,014        
Paolo Scaroni   CEO and General Manager   01.01 - 31.12   04.2014   1,430       4,952       15       6,397        
Carlo Cesare Gatto   Director   01.01 - 31.12   04.2014   115   50                   165        
Alessandro Lorenzi   Director   01.01 - 31.12   04.2014   115   59                   174        
Paolo Marchioni   Director   01.01 - 31.12   04.2014   115   50                   165        
Roberto Petri   Director   01.01 - 31.12   04.2014   115   36                   151        
Alessandro Profumo   Director   01.01 - 31.12   04.2014   115   45                   160        
Mario Resca   Director   01.01 - 31.12   04.2014   115   45                   160        
Francesco Taranto   Director   01.01 - 31.12   04.2014   115   50                   165        
Board of Statutory Auditors               435                       435        
Chief Operating Officers                                                
Claudio Descalzi   E&P Division   01.01 - 31.12   04.2014   773       1,171       13   599   2,556        
Domenico Dispenza   G&P Division   01.01 - 31.12   04.2014   372       335       10       717        
Angelo Fanelli   R&M Division   01.01 - 31.12   04.2014   559       533       14       1,106        
Other Managers with strategic responsibilities (**)               5,432       6,597       133   145   12,307       2,917
                10,571   335   13,833       189   744   25,672       2,917

























(*) The term of office expires with the Shareholders’ Meeting approving the financial statements for the year ending December 31, 2013.
(**) Managers who were permanent members of the Company Management Committee during the course of the year and with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, and those who report directly to the Chief Executive Officer (thirteen managers).

The following table sets out long-term variable components.

    Bonuses of the year   Bonuses of previous years   Other bonuses
   
 
 
Name   Office   (euro thousand)   paid/
payable
  deferred   deferral period   no longer payable   paid/
payable
(a)
  still deferred    
Giuseppe Recchi   Chairman   245                        
Paolo Scaroni   CEO and General Manager   2,110   3,150       896   2,842   6,522    
Claudio Descalzi   Chief Operating Officer E&P Division   579   743           442   1,294   150
Umberto Vergine   Chief Operating Officer G&P Division (b)   191   387           144   447    
Angelo Fanelli   Chief Operating Officer R&M Division   369   481           164   925    
Other Managers with strategic responsibilities (c)       3,281   2,916       1,114   2,866   5,216   450
        6,775   7,677       2,010   6,458   14,404   600

(a) Payment relative to deferred monetary incentive awarded in 2009.
(b) Chief Operating Officer G&P Division until December 4, 2012.
(c) Managers who were permanent members of the Company Management Committee, during the course of the year together with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, and those who report directly to the Chief Executive Officer (thirteen managers).

> Overall remuneration of key
     management personnel
Remuneration of persons responsible of key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, Chief Operating Officers and other managers with strategic responsibilities in charge at December 31, 2012, amounted to euro 33 million, as described in the table below:
     
 

   (euro million)

2012   

Fees and salaries 21
Post employment benefits 1
Other long-term benefits 11
Indemnity upon termination of the office 0
   33

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Investor information

> Eni share performance in 2012
In accordance with Article 5 of the By-laws, the Company’s share capital amounts to euro 4,005,358,876.00, fully-paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value.
As of December 31, 2012, the decrease of No. 371,266,546 shares held in treasury compared to December 31, 2011 (No. 382,654,833 shares) was due to the cancellation of No. 371,173,546 shares, as
  resolved by the Extraordinary and Ordinary Shareholders’ Meeting held on July 16, 2012 and to the sale of No. 93,000 shares following 2004 stock option plans. In the last session of 2012, the Eni share price, quoted on the Italian Stock Exchange, was euro 18.34, up 14.6 percentage points from the price quoted at the end of 2011 (euro 16.01). The Italian Stock Exchange is the primary market where the Eni share is traded. During the year the FTSE/MIB index, the basket including the 40 most   important shares listed on the Italian Stock Exchange, increased by 7.8 percentage points. At the end of 2012, the Eni ADR listed on the NYSE was $49.14, up 19.07% compared to the price registered in the last session of 2011 ($41.27).
One ADR is equal to two Eni ordinary shares. In the same period the S&P 500 index increased by 13.2 percentage points. Eni market capitalization at the end of 2012 was euro 66.4 billion (euro 58 billion at the end of

 

Share information
        2010   2011   2012









Market quotations for common stock on the Mercato Telematico Azionario (MTA)                
High   (euro)   18.56   18.42   18.70
Low       14.61   12.17   15.25
Average daily close       16.39   15.95   17.18
Year-end close       16.34   16.01   18.34









Market quotations for ADR on the New York Stock Exchange                
High   (US$)   53.89   53.74   49.44
Low       35.37   32.98   36.85
Average daily close       43.56   44.41   44.24
Year-end close       43.74   41.27   49.14









Average daily traded volumes   (million of shares)   20.69   22.85   15.63
Value of traded volumes   (euro million)   336   355   267









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Eni in 2012 Investor information

2011), confirming Eni as the first company for market capitalization listed on the Italian Stock Exchange. Shares traded during the year   totaled almost 3.9 billion, with a daily average of shares traded of 15.6 million (22.9 million in 2011).   The total trade value of Eni shares amounted to approximately euro 68 billion (euro 92 billion in 2011), equal to a daily average of euro 267 million.

 

Share data
        2010     2011   2012










Net profit - continuing operations                  
- per share (a)   (euro)   1.72     1.90   1.16
- per ADR (a) (b)   (US$)   4.59     5.29   2.98
Adjusted net profit - continuing operations                  
- per share (a)   (euro)   1.87     1.92   1.97
- per ADR (a) (b)   (US$)   4.96     5.35   5.06










Leverage       0.47     0.46   0.25
Coverage       22.2     15.4   11.7
Current ratio       1.00     1.10   1.40
Debt coverage       56.3     51.3   80.5










Dividends pertaining to the year   (euro per share)   1.00     1.04   1.08
Pay-out   (%)   57     55   50
Dividend yield (c)   (%)   6.1     6.6   5.9
TSR       (2.2)     5.1   22.0










(a) Fully diluted. Ratio of net profit and average number of shares outstanding in the year. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by ECB for the year presented.
(b) One American Depositary Receipt (ADR) is equal two Eni ordinary shares.
(c) Ratio of dividend for the period and the average price of Eni shares as recorded in December.

Dividends

Management intends to propose to the Annual Shareholders’ Meeting scheduled on May 10, 2013, the distribution of a dividend of euro 1.08 per share for fiscal year 2012, of which euro 0.54 was already paid as interim dividend in September 2012. Total cash outlay for the 2012 dividend is expected at approximately euro 3.9 billion (including euro 1.96 billion already paid in September 2012) in case the Annual Shareholders’ Meeting approves the annual dividend.
In future years, management expects to continue paying interim dividends for each
  fiscal year, with the balance to the full-year dividend to be paid in each following year.

Eni intends to continue paying interim dividends in the future. Holders of ADRs receive their dividends in US dollars. The rate of exchange used to determine the amount in dollars is equal to the official rate recorded on the date of dividend payment in Italy (May 23, 2013).
On ADR payment date, Bank of New York Mellon pays the dividend less the amount of any withholding tax under Italian law

  (currently 27%) to all Depository Trust Company Participants, representing payment of Eni SpA’s gross dividend. By submitting to Bank of New York Mellon certain required documents with respect to each dividend payment, US holders of ADRs will enable the Italian Depositary bank and Bank of New York Mellon as ADR Depositary to pay the dividend at the reduced withholding tax rate of 15%. US shareholders can obtain relevant documents as well as a complete instruction packet to benefit from this tax relief by contacting Bank of New York Mellon at 1.201.680.6825.

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Publications

  1   Annual Report 2012 a comprehensive report on Eni’s activities and financial and sustainability results for the year.       set of operating and financial statistics.   in the section Publications (eni.com/sites/ENI_en_IT/documentation/documentation.page?type=bilrap&leftbox=documentazione&doc_from=hpeni_left). Shareholders may receive a hard copy of Eni’s publications, free of charge, by filling in the request form found in the section Publications or through an email request addressed to segreteriasocietaria.azionisti@eni.com or to investor.relations@eni.com. Any other information relevant to shareholders and investors can be found at Eni’s website under the "Investor Relations" section.  
        4   Remuneration Report 2013 a report on Eni’s compensation and remuneration policies pursuant to rule 123-ter of Legislative Decree No. 58/1998.    
  2   Annual Report on Form 20-F 2012 a comprehensive report on Eni’s activities and results to comply with the reporting requirements of the US Securities Exchange Act of 1934 and filed with the US Securities and Exchange Commission.          
        5   Corporate Governance Report 2012 a report on the Corporate Governance system adopted by Eni pursuant to rule 123-bis of Legislative Decree No. 58/1998.    
               
         
  3   Fact Book 2012 a report on Eni’s businesses, strategies, objectives and development projects, including a full            
        These and other Eni publications are available on Eni’s internet site eni.com,    
  Financial calendar  
The dates of the Board of Directors’ meetings to be held during 2013 in order to approve/review the Company’s quarterly and semi-annual, and annual preliminary results are the following: Results for the first quarter of 2013 April 24, 2013
Results for the second quarter and the first half of 2013 and proposal of interim dividend for the financial year 2013 July 31, 2013
Results for the third quarter of 2013 October 29, 2013
Preliminary full-year results for the year ending December 31, 2013 and dividend proposal for the financial year 2013 February 2014

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Eni Shareholders approve 2012 Financial Statements
at Annual Meeting

 

Rome, May 10, 2013 - The Ordinary General Meeting of Eni’s shareholders which was held today, resolved the following:

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the procedures established in the Rules of the Markets organized and managed by Borsa Italiana SpA. In order to respect the limit envisaged in the third paragraph of Article 2357 of the Italian Civil Code, the number of shares to be acquired and the relative amount shall take into account the number and amount of Eni shares already held in the portfolio.

 

 

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.06598232030
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39. 800 11 22 34 56
Switchboard: +39-0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

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Eni and Sonatrach reached an agreement on their gas contract

 

San Donato Milanese (Milan), May 28, 2013 - Eni and Sonatrach have agreed on a package solution for 2013 and 2014 within the framework of their commercial discussions under the existing gas contract.

As part of the Agreement, Eni and Sonatrach will reduce certain quantities of the contractual gas volumes delivered into Italy.

This agreement is part of the renegotiations program started in the recent months, and contributes to the announced objectives of profitability and cash generation.

 

 

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.06598232030
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39. 800 11 22 34 56
Switchboard: +39-0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com


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Eni: Board of Directors approves bond issue

 

San Donato Milanese (Milan) May 30, 2013 - Eni's Board of Directors this afternoon approved the possible issue of one or more bonds, to be placed with institutional investors, with a value of up to a maximum amount of 3 billion euro, or its equivalent in other currencies, to be issued in one or more tranches by May 30, 2014.

The bonds will enable Eni to maintain a well-balanced financial structure, in terms of short term and medium/long-term debt and average duration of the debt. The bonds may be listed on regulated markets.

 

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.06598232030
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39. 800 11 22 34 56
Switchboard: +39-0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com