6-K 1 sj0311aren6k.htm sj0311aren6k
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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 April 2011

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):               )



 

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TABLE OF CONTENTS

 

Annual Report 2010

 

 


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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:   Deputy Corporate Secretary   
 

Date: April 18, 2011


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Operating and Financial Review

Profile of the year 4
Eni share performance 8
Letter to shareholders 9

Operating review
Exploration & Production 12
Gas & Power 29
Refining & Marketing 38
Petrochemicals 44
Engineering & Construction 47

Financial review and other information
Financial review 51
     Profit and loss account 51
     Summarized Group Balance Sheet 69
     Cash Flow Statements 74
Risk factors and uncertainties 79
Outlook 92

Other information 93

Information on Corporate Governance 96

Commitment to sustainable development 112

Glossary 132

Consolidated Financial Statements

Consolidated financial statements 137
Notes to consolidated financial statements 146
Supplemental oil and gas information (unaudited) 232
List of Eni’s subsidiaries 241

Management’s certification 247

Report of Independent Auditors 248

Independent Assurance Report 250

 

Disclaimer

This annual report contains certain forward-looking statements in particular under the section "Outlook" regarding capital expenditures, 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.

 


"Eni" means the parent company Eni SpA and its consolidated subsidiaries.

Ordinary Shareholders’ Meeting of April 29 and May 5, 2011.
The notice convening the meeting was published on "Il Sole 24 Ore" and "Financial Times WW-section 2" of March 18, 2011.

This Annual Report includes the report of Eni’s Board of Directors and Eni’s Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared under the International Financial Reporting Standards (IFRS), as adopted by the European Union.


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Eni Annual Report / Profile of the year

     
Results
In 2010, Eni reported net profit of euro 6.32 billion. Adjusted net profit was euro 6.87 billion, up 32% from a year ago driven by an excellent performance reported by the Exploration & Production Division due to a recovery in the oil price environment.
The main cash inflows of the year were net cash generated by operating activities of euro 14.69 billion, and proceeds of euro 1.11 billion from divesting certain non-strategic assets, enabling the Company to partially fund capital expenditures of euro 13.87 billion to support organic growth and exploration activities and the payment of dividends to Eni’s shareholders amounting to euro 3.62 billion and other dividend payments to non-controlling interests amounting to euro 0.51 billion. Ratio of net borrowings to total equity was 0.47 at year end (0.46 at December 31, 2009).

Dividends
On the basis of the Company’s robust results and sound fundamentals, a dividend of euro 1.00 per share (euro 1.00 per share in 2009) will be distributed to shareholders. Included in this annual payment is euro 0.50 per share already distributed as interim dividend in September 2010. Management reaffirms its commitment to generate industry-leading value for the Company’s shareholders.

Oil and natural gas production
In 2010, Eni reported liquids and gas production was a record 1,815 kboe/d. On a comparable basis, production grew by 1.1% for the full year, driven by the timely delivery of all 12 of our planned start-ups, particularly the Zubair field in Iraq in the fourth quarter, which contributed 40 kboe/d of new production in 2010 and will account for 230 kboe/d of production at peak.
Eni plans to deliver an average organic growth rate of more than 3% over the next four-year period, targeting a production level in excess of 2.05 mmboe/d by 2014 under our Brent price scenario

  at $70 per barrel. This growth will be fuelled by our strong pipeline of project start-ups.

Proved oil and natural gas reserves
Eni’s net proved reserves as of December 31, 2010, amounted to 6.84 bboe, at a reference Brent price of 79 $/bbl. On a comparable basis, the all-sources reserve replacement ratio was 125%. Excluding price effects in PSAs the replacement ratio would be 135%. The reserve life index is 10.3 years.

Natural gas sales
Natural gas sales of 97.06 bcm declined by 6.4% from 2009 due to sharply lower sales volumes in the Italian market dragged down by increased competitive pressures and oversupplies. Higher volumes were sold in European key markets.
In the next four year plan, the recovery in volumes sold will be supported by strengthening the Company’s leadership on the European market, marketing actions intended to strengthen the customer base in the domestic market and renegotiating the Company’s long-term gas supply contracts. Eni expects to increase gas sales in Italy and in European target markets at an annual growth rate of 5%.

Development projects in Venezuela
In November 2010, Eni and the Venezuelan State oil company PDVSA established a joint venture for developing the giant Junin 5 oilfield, located in the Orinoco Oil Belt with certified volumes of oil in place of 35 billion barrels. The first oil is expected by 2013 at an initial rate of 75 kbbl/d, targeting a long-term production plateau of 240 kbbl/d to be reached in 2018.
Appraisal activities performed in 2010 confirmed Perla as a major gas discovery, one of the most significant in recent years and the largest ever in Venezuela, with volumes of gas in place of over

 

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Eni Annual Report / Profile of the year

14,000 bcf. The partners are planning to fast track Perla through an early production phase, targeted to start-up by 2013.

Zubair oilfield - Iraq
In the fourth quarter of 2010, Eni has achieved project milestones at the giant Zubair oilfield in Iraq by increasing production by more than 10% above the initial production rate of approximately 180 kbbl/d, thus beginning cost recovery for its work on the field, including receiving a remuneration fee. Eni, with a 32.8% share, is leading the consortium in charge of redeveloping the Zubair field over a 20 year period, targeting a production plateau of 1.2 mmbbl/d in the next six years.

Other portfolio developments and exploration activity
In February 2011, production start-up was achieved at the Nikaitchuq operated field (Eni 100%), located in the North Slope basin offshore Alaska, with resources of 220 million barrels. Peak production is expected at 28 kbbl/d.
In January 2011, Eni was awarded rights to explore and the operatorship of deep offshore Block 35 in Angola, with a 30% interest. The deal is subject to the approval of the relevant authorities.
In January 2011, Eni signed a Memorandum of Understanding with PetroChina to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in China and outside China.
In December 2010, Eni and Gazprom signed the extension to 2012 of the strategic agreement signed in 2006. This consolidates a long term partnership to launch joint projects in mid and downstream gas, in the upstream sector and in technological cooperation.
In December 2010, Eni increased its ownership interest in Altergaz, a company marketing natural gas in France to retail and middle market clients. Eni now controls the entity.
In November 2010, Eni signed with the Government of Ecuador new terms for the service contract for the Villano oilfield, due to expire in 2023. Under the new agreement, the operated area is enlarged to include the Oglan oil discovery, with volumes in place of 300 mmbbl. Development will be achieved in synergy with existing facilities.
In December 2010, Eni acquired Minsk Energy Resources operating 3 licenses in the Polish Baltic Basin, a highly prospective shale gas play.
In August 2010, Eni signed an agreement to acquire a 55% stake and operatorship in the Ndunda Block located in the Democratic Republic of Congo.
In October 2010, Eni was awarded operatorship of offshore Block 1 and Block 2 (Eni 100%) in the Dahomey Basin, in Togo. The area is located in a scarcely explored basin bordered to the west by the analogous Tano Basin where major discoveries have been made.

Portfolio optimization
In October 2010, with a view to rationalizing its upstream portfolio, Eni divested its subsidiary Società Padana Energia to Gas Plus. The divested subsidiary includes exploration leases and concessions for developing and producing oil and natural gas in Northern Italy.
In May 2010, Eni signed a preliminary agreement with an affiliate of Petrobras for the divestment of its 100% interest in Gas Brasiliano Distribuidora, a company that markets and distributes gas in an area of the São Paulo state, Brazil. The completion of the transaction is subject to approval of the relevant Brazilian authorities.
In April 2010, Eni divested to NOC (the Libyan National Oil

  Corporation) a 25% stake in the share capital and control of GreenStream BV, the Company owning and managing the gas pipeline for exporting to Italy natural gas produced in Libya.

Divestment of international pipelines
Procedures for the divestment of Eni’s interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas transport pipelines are progressing. The divestment has been agreed upon on September 29, 2010 with the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market ascribed to Eni without the ascertainment of any illicit behavior and consequently without imposition of any fines or sanctions.

Safety of people
In 2010 the employees and contractors injury frequency index decreased by 9% and 25.4%, respectively from last year. The year 2010 registered an increased number of fatalities (2 workers and 8 contractors). This number was increased by the 21 Eni people (15 workers and 6 contractors) deceased in the air crash which occurred in November 5, 2010 in Pakistan.

Cooperation for development
Cooperation with Countries, companies and communities in the territories where Eni operates is confirmed as one of the pillars of our company strategy. In 2010 Eni signed new strategic agreements in Togo, Iraq, Democratic Republic of Congo, Egypt, Venezuela and Libya, entailing programs for the integration of traditional business to action aimed to promote the sustainable development of the Country.

Eni participation to global governance
on sustainability themes

In 2010 Eni strengthened its participation to the Global Compact trough the support to the Global Compact Leaders Summit of June, the adhesion to the Global Compact LEAD Program, Caring for Climate and working groups on Anti-Corruption and Human Rights. During the Global Compact Leaders Summit Eni announced an important partnership with the Earth Institute of the Columbia University related to key projects on the promotion of sustainable development in Africa.

Technological innovation
Eni is committed in frontier initiatives in the field of renewable energies. Eni and the Massachusetts Institute of Technology (MIT) celebrated the opening of the Eni-MIT Solar Frontiers Centre (SFC), a centre promoting research on advanced solar technologies. In 2010 Eni received the "2009 Oscar Masi prize for industrial innovation" for innovative technological research in the field of renewable energy and, more specifically, in photovoltaics.

Clients and consumers
Among the results achieved, the G&P Division reached the 2nd position in the ranking of the Authority for Electricity and Gas for the quality of its telephone services. In 2010, the R&M Division continued the re-branding process of the service stations, with the inauguration of approximately 500 service stations with the new brand.

 

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Eni Annual Report / Profile of the year

Financial Highlights       2008   2009   2010
Net sales from operations   (euro million)   108,082   83,227   98,523
Operating profit       18,517   12,055   16,111
Adjusted operating profit (a)       21,608   13,122   17,304
Net profit (b)       8,825   4,367   6,318
Adjusted net profit (a) (b)       10,164   5,207   6,869
Net cash provided by operating activities       21,801   11,136   14,694
Capital expenditures       14,562   13,695   13,870
Dividends to Eni shareholders pertaining to the period (c)       4,714   3,622   3,622
Cash dividends to Eni shareholders       4,910   4,166   3,622
Total assets at year end       116,673   117,529   131,860
Debts and bonds at year end       20,837   24,800   27,783
Shareholders’ equity including non-controlling interest at year end       48,510   50,051   55,728
Net borrowings at year end       18,376   23,055   26,119
Net capital employed at year end       66,886   73,106   81,847
Share price at year end   (euro)   16.74   17.80   16.34
Number of shares outstanding at year end   (million)   3,622.4   3,622.4   3,622.5
Market capitalization (d)   (euro billion)   60.6   64.5   59.2
i i i
(a) i For a detailed explanation of adjusted profits (net and operating), that exclude inventory holding gain/loss and special items, see paragraph "Reconciliation of reported operating profit and reported net profit to results on an adjusted basis".
(b) i Profit attributable to Eni’s shareholders.
(c) i The amount of dividends for the year 2010 is based on the Board’s proposal.
(d) i Number of outstanding shares by reference price at year end.

 

Summary financial data       2008   2009   2010
Net profit                
- per share (a)   (euro)   2.43   1.21   1.74
- per ADR (a) (b)   (USD)   7.15   3.36   4.62
Adjusted net profit                
- per share (a)   (euro)   2.79   1.44   1.90
- per ADR (a) (b)   (USD)   8.21   4.01   5.04
Return On Average Capital Employed (ROACE)                
- reported   (%)   15.7   8.0   10.0
- adjusted   (%)   17.6   9.2   10.7
Leverage       0.38   0.46   0.47
Dividends pertaining to the year   (euro per share)   1.30   1.00   1.00
Pay-out   (%)   53   83   57
Dividend yield (c)   (%)   7.6   5.8   6.1
i i i
(a) i Fully diluted. Ratio of net profit and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by ECB for the period presented.
(b) i One American Depositary Receipt (ADR) is equal to two Eni ordinary shares.
(c) i Ratio of dividend for the period and the average price of Eni shares as recorded in December.

 

Key market indicators       2008   2009   2010
Average price of Brent dated crude oil (a)       96.99   61.51   79.47
Average EUR/USD exchange rate (b)       1.471   1.393   1.327
Average price in euro of Brent dated crude oil       65.93   44.16   59.89
Average European refining margin (c)       6.49   3.13   2.66
Average European refining margin Brent/Ural (c)       8.85   3.56   3.47
Average European refining margin in euro       4.41   2.25   2.00
Euribor - three-month euro rate   (%)   4.6   1.2   0.8
Libor - three-month dollar rate   (%)   2.9   0.7   0.3
i i i
(a) i In USD per barrel. Source: Platt’s Oilgram.
(b) i Source: ECB.
(c) i In USD per barrel FOB Mediterranean Brent dated crude oil. Source: Eni calculations based on Platt’s Oilgram data.

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Eni Annual Report / Profile of the year

Summary operating data       2008   2009   2010
     Exploration & Production                
Estimated net proved reserves of hydrocarbons (at year end) (a)   (mmboe)   6,600   6,571   6,843
- Liquids   (mmbbl)   3,335   3,463   3,623
- Natural gas   (bcf)   18,748   17,850   17,882
Average reserve life index   (year)   10.0   10.2   10.3
Production of hydrocarbons (a)   (kboe/d)   1,797   1,769   1,815
- Liquids   (kbbl/d)   1,026   1,007   997
- Natural gas   (mmcf/d)   4,424   4,374   4,540
Production sold (a)   (mmboe)   632.0   622.8   638.0
     Gas & Power                
Worldwide gas sales (b)   (bcm)   104.23   103.72   97.06
LNG sales (c)   (bcm)   12.0   12.9   15.0
Customers in Italy   (million)   6.63   6.88   6.88
Gas volumes transported in Italy   (bcm)   85.64   76.90   83.32
Electricity sold   (TWh)   29.93   33.96   39.54
     Refining & Marketing                
Refinery throughputs on own account   (mmtonnes)   35.84   34.55   34.80
Retail sales of petroleum products in Europe   (mmtonnes)   12.03   12.02   11.73
Service stations in Europe at year end   (units)   5,956   5,986   6,167
Average throughputs of service stations in Europe   (kliters)   2,502   2,477   2,353
     Petrochemicals                
Production   (ktonnes)   7,372   6,521   7,220
Sales of petrochemical products   (ktonnes)   4,684   4,265   4,731
     Engineering & Construction                
Orders acquired   (euro million)   13,860   9,917   12,935
Order backlog at year end   (euro million)   19,105   18,730   20,505
i i i
(a) i From April 1, 2010, the natural gas conversion factor from cubic feet to boe has been updated to 1 barrel of oil = 5,550 cubic feet of gas (it was 1 barrel of oil = 5,742 cubic feet of gas). For further information see the paragraph "Summary of significant accounting policies" in the Notes to the Consolidated Financial Statements.
(b) i Includes Exploration & Production sale volumes of 5.65 bcm (6.00 and 6.17 bcm in 2008 and 2009, respectively) of which 2.33 bcm market by the Exploration & Production Division in Europe (3.36 and 2.57 bcm in 2008 and 2009) and 3.32 bcm in the Gulf of Mexico (2.64 and 3.60 bcm in 2008 and 2009, respectively).
(c) i Refers to LNG sales of the G&P Division (included in worldwide gas sales) and the Exploration & Production Division.

 

Key sustainability indicators       2008   2009   2010
Employees at period end (a)   (number)   78,094   77,718   79,941
of which:                
- women       12,221   12,564   12,754
- outside Italy       41,971   42,633   45,967
Employee injury frequency rate   (number of injuries/million of worked hours)   1.45   1.00   0.91
Contractor injury frequency rate       1.40   1.18   0.88
Oil spills   (barrels)   4,738   6,285   3,850
Oil spills due to sabotage and terrorism       2,286   15,289   18,721
GHG emissions   (million tonnes CO2 eq)   61.99   57.66   60.68
R&D expenditures   (euro million)   217   207   221
Total expenditures for the territory (b)       87   99   108
i i i
(a) i In 2010 the method for calculating the number of employees has been changed. Employees are allocated to Italy and abroad according to their permanent employment base. Prior year data have been restated accordingly.
(b) i Includes investments for local communities, charities, association fees, sponsorships, payments to Eni Enrico Mattei Foundation and Eni Foundation.

 

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Eni Annual Report / Eni share performance

Eni share performance in 2010
As of December 31, 2010, the Company’s share capital was euro 4,005,358,876, fully paid-up and represented by 4,005,358,876 ordinary registered shares, each with a nominal value of euro 1.00 (the same number of December 31, 2010). The average number of shares outstanding in the period, considering the treasury shares in Eni’s portfolio, was 3,622,454,738 (3,622,495,143 in December 31, 2009).
In the last session of 2010 the Eni share price, quoted on the Italian Stock Exchange, was euro 16.34, down 8.2 percentage points from the price quoted at the end of 2009 (euro 17.80). 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,
  decreased by 13.2 percentage points.
At the end of 2010, the Eni ADR listed on the NYSE was $43.74, down 13.6% compared to the price registered in the last session of 2009 ($50.61). One ADR is equal to two Eni ordinary shares. In the same period the S&P500 index increased by 12.8% percentage points.
Eni market capitalization at the end of 2010 was euro 59.2 billion (euro 64.5 billion at the end of 2009), confirming Eni as the first company for market capitalization listed on the Italian Stock Exchange.
Eni share was one of the more liquid of the Italian market. Shares traded during the year totaled almost 5.3 billion, with an average number of shares traded daily of 20.7 million (27.9 million in 2009). The total trade value of Eni share amounted to over euro 86 billion (euro 118 billion in 2009), equal to a daily average of euro 336 million.

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Eni Annual Report / To our shareholders

 

2010 has been a very good year for Eni. We have delivered a solid set of financial and operational achievements, laying the foundations for our future growth.
The Exploration & Production Division reported an outstanding performance.
In Iraq, we achieved a major milestone in the rehabilitation of the giant Zubair oilfield, increasing production by more than 10% compared to the initial rate. This has enabled us to start recovering our costs and earning the remuneration fee. The next development phase targets a production plateau of 1.2 mmbbl/d, which will be achieved by 2016.
In Venezuela we established a joint venture with PDVSA to develop the giant Junin 5 field, which has certified oil in place of 35 billion barrels and which we expect to start up in 2013. Appraisal activities performed in 2010 also confirmed Perla as a major gas discovery – one of the most significant in recent years and the largest ever in Venezuela – with gas in place of over 14,000 billion cubic feet. We will fast-track Perla, targeting start-up in 2013.
New discoveries have been one of the highlights of the year, with explorations successes in Indonesia, Brazil and Angola as well as Venezuela.
2010 also marked Eni’s entry in new high-potential Countries and plays such as the Democratic Republic of Congo, with the acquisition of a 55% stake and the operatorship of the Ndunda onshore exploration block; Togo with two blocks in the Tano Basin in the Gulf of Guinea; and Poland where we acquired exploration licenses in highly prospective shale gas plays.
Our new strategic agreements, pivotal to our industrial plan, are based on our commitment to cooperate with partnering
  Countries, local companies and communities as well as to our endorsement of sustainable development.
The Gas & Power Division suffered from a challenging trading environment in the European market. Supply exceeded demand, depressing spot gas prices at continental hubs which have increasingly been adopted as benchmarks for sales contracts outside Italy. This affected our margins, as spot prices fell well below our average purchase cost which is mainly indexed to the price of oil.
We have taken steps to preserve the competitiveness of our merchant gas business, first among which is the renegotiation of gas purchase contracts with our suppliers.
The Refining & Marketing Division improved its performance in spite of a harsh trading environment and unprofitable refining margins. Our Petrochemicals Division also achieved better operating results compared to the previous year. We will improve the prospects of this business by launching an environment-friendly industrial project for the reconversion of the Porto Torres site. The Engineering & Construction segment again delivered an excellent performance, further enhancing its strong commercial franchise.
In the field of new technologies, we reconfirmed our commitment to produce hydrocarbons in an ever more efficient and safe manner, and develop renewable energy sources. An achievement worthy of note is the inauguration of the Solar Frontiers Centre in Massachusetts, in partnership with the MIT.
We have been confirmed in the main sustainability indexes and have enrolled in the new Global Compact LEAD Program of the United Nations, which will bring together global companies with excellent sustainability track records. Eni will also provide its expertise as international energy company to the preparation of

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Eni Annual Report / To our shareholders

the Rio+20 World Conference.
In 2011, the global economic recovery looks stronger, despite signs of volatility and uncertainty deriving from ongoing tensions in Libya, a Country with which Eni has long-standing relationships. Our thoughts are with the Libyan people at this difficult time, and we offer our sincerest hopes of a rapid return to order and stability so as to resume our common growth and development path.
Against this backdrop we reaffirm our strategic focus on growth and efficiency. We will deliver strong production growth, both in the next four years and beyond, and overcome challenges in the Gas & Power segment by strengthening our leadership in European markets, whilst preserving a sound financial position.

Financial performance

In 2010, net profit attributable to Eni’s shareholders was euro 6.32 billion. Adjusted net profit was 6.87 billion, an increase of 32% from 2009, reflecting the excellent operating performance of the Exploration & Production Division (up 46% from 2009). The Engineering & Construction Division also reported a robust performance (up 18%). The Refining & Marketing and Petrochemical Divisions reduced their operating losses by 52% and 73%, respectively. These positives more than offset the sharp decline in the Gas & Power Division’s performance, driven by poor results in the Marketing business.
Return on Average Capital Employed (ROACE) calculated on an adjusted basis was 10.7%. Cash inflows for the year mainly comprised cash flow from operations of euro 14.69 billion and disposal proceeds of euro 1.11 billion. These inflows enabled Eni to partially fund outflows associated with capital expenditures of euro 13.87 billion to support organic growth and exploration activities, dividends to Eni shareholders amounting to euro 3.62 billion, and dividends to non-controlling interests, mainly relating to Snam Rete Gas and Saipem, amounting to euro 0.51 billion. The ratio of net borrowings to total equity was virtually unchanged at 0.47.
The results achieved in 2010 enable us to propose a dividend of euro 1.00 per share to the Annual General Shareholders Meeting, of which euro 0.50 was paid as an interim dividend in September 2010.

In Exploration & Production Division we achieved an outstanding financial and operational performance. Adjusted net profit reached euro 5.6 billion, up 44% compared to 2009, driven by a favorable trading environment for oil prices and the depreciation of the euro against the dollar. Oil and gas production was a record 1,815 kboe/d, 1.1% higher than in 2009. This growth was driven by the timely delivery of all 12 of our planned start-ups, which contributed 40 kboe/d of new production in 2010 and will account for 230 kboe/d at peak. The all sources replacement ratio of reserves was 125%, rising to 135% at constant prices, corresponding to a reserve life index of 10.3 years at December 31, 2010 (10.2 years in 2009).
Over the course of the year we added approximately 0.9 billion boe to our resource base thanks to successful exploration activities in Venezuela, Angola, Indonesia and Brazil, at the very competitive cost of 1.5 $/bbl. The Junin 5 project in Venezuela and acquisition of new acreage in the Democratic Republic of Congo, in Togo and in shale gas in Poland further enhanced our upstream portfolio.
We target an average annual production increase of more than 3% in the 2011-2014 plan, based on our $70 per barrel Brent price

  scenario and return of the Libyan production to its normal rate at some point in the future. Growth will be fuelled by our strong pipeline of projects, with 15 new major fields and other projects planned to start production in the four-year period. Planned start-ups will add 630 kbbl/d of new production by 2014. The booking of new reserves will enable us to replace reserves produced in the period, keeping the reserve life index stable. In the longer term, we expect to drive production growth leveraging on our giant fields, particularly Kashagan, Junin, Perla, Goliath, MLE-CAFC, Russian projects, Block 15/06 in Angola and unconventional opportunities. We will pursue the maximization of returns through selective exploration, the reduction in the time to market of our projects, and growing the share of operated production which – through the deployment of Eni standards and technologies – enables us to deliver tighter cost control and a better monitoring of operating risks.

After delivering solid returns for many years, in 2010 the Gas & Power Division posted a 12% decline in profits compared to 2009. Marketing activities reported sharply lower results (adjusted operating profit was down 57%) owing to heightened competitive pressure. Sales in Italy declined by 14% (down approximately 6 bcm), corresponding to a market share decline of ten percentage points. Sales in target European markets maintained a growth trend, with volumes up 2.5% (up 1 bcm). Short-term prospects remain challenging, while in the next four years we expect a gradual recovery in fundamental trends.
We are tackling this challenging environment by developing our business model and implementing new pricing and risk management strategies to preserve profitability. In Italy, we will regain volumes and market share by leveraging on differentiated marketing initiatives, excellent customer service, the repositioning of our "luce e gas" brand and value-creating management of our assets (transport capacity, modulation, and supply). In Europe we will continue to pursue an aggressive growth strategy in our main target markets, in particular France, Germany and Austria.
We target a substantial recovery in profitability by 2014, even taking into account the expected divestment of our international pipelines. The achievement of this target will be supported by the renegotiation of our long-term supply contracts, with new pricing terms and contractual flexibility ensuring the competitiveness of our cost position. In the Regulated businesses in Italy, our industrial strategy aims at maximizing efficiency and implementing a capital expenditure program to combine outstanding service quality and steady growth in returns.

Compared to 2010, the Refining & Marketing Division reduced its adjusted net loss by 75% to euro 49 million. In the context of weak refining margins caused by excess capacity, low demand and high feedstock costs, the improvement was driven by greater efficiency and operational enhancement. The Marketing business achieved good results: in Italy, successful commercial initiatives offset a difficult trading environment (lower consumption and strong competition), while we continued to grow sales in selected European markets. Over the next four years, we target a substantial improvement in the profitability and free cash generation of our refining operations against the backdrop of continuing weakness in the trading environment. Our strategy in refining will leverage on selective capital expenditures to increase the complexity and

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flexibility of our refineries, particularly by completing and starting up the EST project at the Sannazzaro site. This will enable us to capture opportunities offered by demand for middle distillates and to process low quality feedstock. Margin recovery will be underpinned by cost efficiencies and the integration of refinery cycles.
We plan to increase volume throughputs to 37 million tonnes by 2014 (up 2 million from 2010) and plant utilization rate to 90%. In marketing we will boost sales by approximately 10% in the next four years and increase our market share, leveraging on a network of modern and efficient service stations, which will be revamped in design and style. Sales and market share targets will also be supported by promotional campaigns, targeted pricing actions and an enhanced non-oil offer.
The re-branding of the Italian network with the Eni brand will be completed by 2014. Abroad, we will grow selectively in Central Eastern Europe and France leveraging on the consolidation of the network acquired in Austria, commercial initiatives and the opening of new service stations.

The Engineering & Construction segment reported adjusted net profit of nearly euro 1 billion, up 11% compared to 2009, driven by revenue growth and the higher profitability of projects. The order backlog at year end reached a record euro 20.5 billion. Saipem is an established leader in the area of oilfield services, particularly in executing large EPC projects. Its strong competitive position is underpinned by distinctive skills in engineering and project management, the availability of a world class fleet that will be fully upgraded by 2012 and the local content of operations. In the next four years we target steady growth in revenues and profits.

Polimeri substantially improved from a year earlier, reducing its adjusted net loss by 75% to euro 85 million. The improvement was driven by increased sales volumes on the back of a recovery in

  demand, efficiency enhancements and higher margins. Eni aims to recover profitability and generate free cash flow in the 2012-2013 period, leveraging on increasing efficiency, selective investments to optimize the yields and consumption of our crackers, the upgrading of plants in areas of excellence (elastomers) and opportunities to develop environment-friendly projects. An improving commercial performance will support margins, also with the contribution of licensing activities.

Supporting growth and profitability
for shareholders

We expect to make capital expenditures amounting to euro 53.3 billion over the next four-year plan to fuel growth and value creation. This plan represents a slight increase compared to the previous one due to new initiatives in E&P (particularly new projects in Angola and additional activities Iraq). Cash flow from operations and planned divestment proceeds will enable us to fund our capital expenditure program and remunerate our shareholders, while at the same time strengthening our balance sheet. Our cost reduction program, which has delivered savings of euro 2.4 billion from 2006 to date, is expanded by euro 1.7 billion of further savings, targeting cumulated savings of euro 4.1 billion by 2014.

In conclusion, 2010 was a successful year for Eni. We progressed on our strategy focused on growth and efficiency, and laid the foundations for our future growth. In the next four years, while the global economy is expected to progressively recover, we expect that Eni – thanks to its excellent strategic position – will deliver industry-leading results, and create sustainable value for its shareholders and stakeholders.

March 10, 2011

In representation of the Board of Directors

Chairman Chief Executive Officer and General Manager

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Key performance/sustainability indicators       2008   2009   2010
Employee injury frequency rate   (No. of accidents per million hours worked)   0.84   0.49   0.72
Net sales from operations (a)   (euro million)   33,042   23,801   29,497
Operating profit       16,239   9,120   13,866
Adjusted operating profit       17,222   9,484   13,884
Adjusted net profit       7,900   3,878   5,600
Capital expenditures       9,281   9,486   9,690
of which: exploration expenditures (b)       1,918   1,228   1,012
Adjusted capital employed, net at year end       30,362   32,455   37,646
Adjusted ROACE   (%)   29.2   12.3   16.0
Average hydrocarbons realizations   ($/boe)   68.13   46.90   55.60
- Liquids   ($/bbl)   84.05   56.95   72.76
- Natural gas   ($/mmcf)   8.01   5.62   6.02
Production of hydrocarbons (c) (d)   (kboe/d)   1,797   1,769   1,815
- Liquids   (kbbl/d)   1,026   1,007   997
- Natural gas   (mmcf/d)   4,424   4,374   4,540
Estimated net proved reserves of hydrocarbons (c) (d)   (mmboe)   6,600   6,571   6,843
- Liquids   (mmbbl)   3,335   3,463   3,623
- Natural gas   (bcf)   18,748   17,850   17,882
Reserve life index (d)   (years)   10.0   10.2   10.3
All sources reserve replacement ratio net of updating the natural gas conversion factor (c) (d)   (%)   135   96   125
Employees at year end   (units)   10,236   10,271   10,276
of which: outside Italy       6,182   6,388   6,370
Oil spills   (bbl)   4,738   6,285   3,850
Oil spills from sabotage and terrorism       2,286   15,289   18,721
Direct GHG emissions   (mmtonnes CO2 eq)   33.21   29.69   31.22
of which: from flaring       16.54   13.73   13.83
Community investments   (euro million)   65   67   72
(a) i Before elimination of intragroup sales.
(b) i Includes exploration bonuses.
(c) i Includes Eni’s share of equity-accounted entities.
(d) i From April 1, 2010, Eni has updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. The effect of this update on production expressed in boe was 26 kboe/d for the full-year 2010 and on the initial reserves balance as of January 1, 2010, amounted to 106 mmboe. For further information see the paragraph "Summary of significant accounting policies" in the Notes to the Consolidated Financial Statements.

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Libyan tensions
› From February 22, 2011, some liquids and natural gas production activities and the gas export through the GreenStream pipeline have been halted. Facilities have not suffered any damage and such standstill does not affect Eni’s ability to ensure natural gas supplies to its customers. Eni is technically able to resume gas production at or near previous level once the situation stabilizes. The overall impact of the Libyan tensions on Eni’s results in terms of operations and cash flows will depend on how long such tensions will last, which management is currently unable to predict. Eni’s production is currently fluctuating at around 70-75 kboe/d, down from the expected level of approximately 280 kboe/d, and is made of gas which is totally delivered to local power generation plants. Net capital employed in Eni’s upstream activities in Libya amounted to approximately $2.5 billion at year end including Eni’s interest (50%) in the GreenStream BV venture. For further information on the impact of Libyan tensions on liquids and natural gas production and gas sales outlook see page 92 "Outlook"; for the take-or-pay clauses outlook see page 86 "Risks and uncertainties associated with the competitive environment in the natural gas market".
 

Development projects in Iraq and Venezuela
› Achieved an increase in production by more than 10% above the initial production rate of approximately 180 kbbl/d at the giant Zubair oilfield thus beginning cost recovery for its work on the field, including recognition of remuneration fee. Eni, with a 32.8% share, is leading the consortium in charge of redeveloping the Zubair field over a 20 year period, targeting a production plateau of 1.2 mmbbl/d in the next six years.
› Established a joint-venture with the Venezuelan National Oil Company PDVSA for the development of the giant Junin 5 oilfield, located in the Orinoco Oil Belt with certified volumes of oil in place of 35 billion barrels. First oil is expected in 2013 at an initial rate of 75 kbbl/d, targeting a long-term production plateau of 240 kbbl/d to be reached in 2018.
› Appraisal activities performed in 2010 confirmed Perla as a major gas discovery, one of the most significant in recent years and the largest ever in Venezuela, with volumes of gas in place of over 14,000 bcf. The partners are planning fast track of Perla through an early production phase of approximately 300 mmcf/d, targeted to start-up by 2013.


Portfolio
› Acquired a 55% stake and operatorship in the Ndunda Block located in the Democratic Republic of Congo.
› Awarded operatorship of two offshore Blocks (Eni’s interest 100%) in the Dahomey Basin as part of its agreements with the Government of Togo to develop the Country’s offshore mineral resources.
› Acquired Minsk Energy Resources operating 3 licenses in the Polish Baltic Basin, a highly prospective shale gas play. Drilling operations are expected to start in the second half of 2011.
› Awarded rights to explore and the operatorship of deep offshore Block 35 in Angola, with a 30% interest. This deal is subject to the approval of the relevant authorities.
› Signed a Strategic Framework Agreement with the Egyptian Ministry of Petroleum for new upstream and downstream initiatives.
› Signed a Memorandum of Understanding with the national oil company PetroChina to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in China and outside China.
› Signed with the Government of Ecuador new terms for the service contract for the Villano oilfield, due to expire in 2023. Under the new agreement, the operated area is enlarged to include the Oglan oil discovery, with volumes in place of 300 mmbbl. Development will be achieved in synergy with existing facilities.
› Sanctioned the West Hub project to readily put in production the oil discoveries made in offshore Block 15/06 (Eni operator with a 35% interest), located in Angola. Start-up is expected in 2013 with production peaking at 22 kbbl/d.
› Awarded new exploration leases in Pakistan and Venezuela.
› As part of the rationalizing its upstream portfolio, Eni divested its subsidiary Società Padana Energia to Gas Plus. The divested subsidiary includes exploration leases and concessions for developing and producing oil and natural gas in Northern Italy.


Financial results
› In 2010 the E&P Division reported an excellent performance amounting to euro 5,600 million of adjusted net profit, representing an increase of 44.4% from 2009. This was driven by higher oil realizations in dollar terms, the depreciation of the euro against the dollar and higher volumes sold.
› Return on average capital employed calculated on an adjusted basis was 16% in 2010 (12.3% in 2009).


Production
› Reported oil and natural gas production for the full year was 1,815 kboe/d. Production grew by 1.1%, excluding the effect of the updated gas conversion factor. Production growth was driven by the timely delivery of all the 12 planned start ups, particularly the Zubair field in Iraq, and production ramp-ups at fields which were started-up in 2009 for a total increase of 40 kboe/d in 2010. These start-ups will account for 230 kboe/d of production at peak.
› Leveraging on organic growth, Eni expects to deliver more than 3% compound average growth rate over the next four-year period, targeting a production level in excess of 2.05 mmboe/d by 2014 under a Brent scenario at $70 per barrel.

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Reserves
› Estimated net proved reserves at December 31, 2010, were 6.84 bboe (up 2.5% from 2009 on comparable basis) based on a 12-month average Brent price of $79 per barrel. The all sources reserve replacement ratio was 125%, net of the gas conversion factor update. Also excluding price effect, the replacement ratio would be 135%. The reserve life index is 10.3 years (10.2 years in 2009).
 

Exploration and development expenditures
› In 2010, capital expenditures amounted to euro 9,690 million to enhance assets in well established areas of Africa, the Gulf of Mexico and Central Asia. Exploration activities (euro 1,012 million) achieved a number of successes such as the appraisal activity at the large Perla gas discovery in Venezuela and oil discoveries in the Block 15/06 located in the Angolan offshore basin. Further discoveries were made in the North Sea, Egypt, Pakistan, Indonesia, Nigeria and Brazil, through Galp (Eni’s interest 33%).
› A total of 47 new exploratory wells were drilled (23.8 of which represented Eni’s share), in addition to 9 exploratory wells in progress at year end (3.8 net to Eni). The overall commercial success rate was 41% (39% net to Eni).
› Development expenditures were euro 8,578 million to fuel the growth of major projects in Kazakhstan, Congo, the United States, Algeria, Egypt and Norway.

 

Reserves

Overview
The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable US Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices1 are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under Production Sharing Agreements (PSAs) are calculated so that the sale of production entitlements should cover expenses incurred by the

  Group to develop a field (Cost Oil) and on the Profit Oil set contractually (Profit Oil). A similar scheme applies to buy-back and service contracts.

Reserves Governance
Eni exercises rigorous control over the process of booking proved reserves, through a centralized model of reserve governance. The Reserves Department of the Exploration & Production Division is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation.
Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the SEC rules2. D&M has also stated that the company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by others entities, Eni estimates its share of proved reserves on the basis of the above guidelines.
The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditures, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers at the head office verify estimates carried out by business unit managers; (iv) the Planning and Control Department provides the economic evaluation of reserves; (v) the Reserve Department, through the Division Reserves Evaluators (DRE), provides independent reviews of fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserve data.

 


(1)  i  Year-end liquids and natural gas prices were used in the estimate of proved reserves until 2008.
(2)    The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2009.

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The Head of the Reserve Department attended the "Politecnico di Torino" and received a Master of Science degree in Mining Engineering in 1985. He has more than 20 years of experience in the oil and gas industry and more than 10 years of experience directly in evaluating reserves.
Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality respecting professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

Reserves independent evaluation
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation3 of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserve audit is included in the third party audit report4. In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal

  process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.
In order to calculate the economic value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided. In 2010 Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of 28% of Eni’s total proved reserves at December 31, 20105, confirming, as in previous years, the reasonableness of Eni internal evaluation4.
In the 2008-2010 three year period, 78% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2010, the principal Eni properties not subjected to independent evaluation in the last three years were Karachaganak (Kazakhstan), Samburgskoye and Yaro-Yakhinskoye (Russia).

Movements in estimated net proved reserves
Eni’s estimated proved reserves were determined taking into account Eni’s share of proved reserves of equity accounted entities. Movements in Eni’s 2010 estimated proved reserves were as follows:

i

  (mmboe)       Consolidated subsidiaries     Equity-accounted entities     Total  
Estimated net proved reserves at December 31, 2009             6,209         362           6,571  
Extensions, discoveries and other additions, revisions of previous estimates, improved recovery and other factors             788         158           946  
of which:                                      
Price effect       (80 )                   (80 )      
Effect of updating the natural gas conversion factor       97           9         106        
Sales of mineral-in-place             (12 )                   (12 )
Production of the year             (653 )       (9 )         (662 )
Estimated net proved reserves at December 31, 2010             6,332         511           6,843  
Reserve replacement ratio, all sources (a)   (%)         104         ..           125  
Reserve replacement ratio, all sources and excluding price effect (a)   (%)         114         ..           135  
                                       
     
(a)   Net of updating the natural gas conversion factor. This factor has been updated to 1 barrel of oil = 5,550 cubic feet of gas in 2010.

i

Additions to proved reserves booked in 2010 were 946 mmboe (including the impact of gas conversion factor update equal to 106 mmboe) and derived from: (i) revisions of previous estimates were 680 mmboe mainly reported in Libya, Nigeria, Egypt, Iraq and Italy; (ii) extensions, discoveries and other factors were 252 mmboe, with major increases booked in Venezuela, the United Kingdom and Algeria; (ii) improved recovery were 14 mmboe mainly reported in Venezuela. The unfavorable effect of higher oil prices on reserve entitlements in certain PSAs and service contracts (down 80 mmboe) resulted from higher oil prices from one year ago (the Brent prices used in the reserve estimation   process was $79 per barrel in 2010 compared to $59.9 per barrel in 2009). Higher oil prices also resulted in upward revisions associated with improved economics of marginal productions.
Sales of mineral-in-place resulted mainly from the divestment of wholly-owned subsidiary Società Padana Energia to Gas Plus, which holds exploration, development and production properties in Northern Italy.
In 2010, Eni achieved an all-sources reserve replacement ratio6 net of gas conversion factor update of 125%. Excluding price effects, the replacement ratio would be 135%. The reserve life index is 10.3 years (10.2 years in 2009).

 


(3) i From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
(4) i The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2010.
(5) i Includes Eni’s share of proved reserves of equity accounted entities.
(6)   Ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions, discoveries and sales or purchases of minerals in place, to production for the year. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserve Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks.

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Estimated net proved hydrocarbons reserves (a)   (mmboe)                            
    Italy   Rest of Europe   North Africa   West Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total consolidated subsidiaries   Equity- accounted entities   Total
Year ended December 31, 2008 (b)   681   525   1,922   1,146   1,336   265   235   132   6,242   358   6,600
Developed   465   417   1,229   827   647   168   133   62   3,948   68   4,016
Undeveloped   216   108   693   319   689   97   102   70   2,294   290   2,584
Year ended December 31, 2009   703   590   1,922   1,141   1,221   236   263   133   6,209   362   6,571
Developed   490   432   1,266   799   614   139   168   122   4,030   74   4,104
Undeveloped   213   158   656   342   607   97   95   11   2,179   288   2,467
Year ended December 31, 2010   724   601   2,096   1,133   1,126   295   230   127   6,332   511   6,843
Developed   554   405   1,215   812   543   139   141   117   3,926   96   4,022
Undeveloped   170   196   881   321   583   156   89   10   2,406   415   2,821
                                             
Estimated net proved liquids reserves   (mmbbl)                            
    Italy   Rest of Europe   North Africa   West Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total consolidated subsidiaries   Equity-accounted entities   Total
Year ended December 31, 2008 (b)   186   277   823   783   911   106   131   26   3,243   92   3,335
Developed   111   222   613   576   298   92   74   23   2,009   27   2,036
Undeveloped   75   55   210   207   613   14   57   3   1,234   65   1,299
Year ended December 31, 2009   233   351   895   770   849   94   153   32   3,377   86   3,463
Developed   141   218   659   544   291   45   80   23   2,001   34   2,035
Undeveloped   92   133   236   226   558   49   73   9   1,376   52   1,428
Year ended December 31, 2010   248   349   978   750   788   139   134   29   3,415   208   3,623
Developed   183   207   656   533   251   39   62   20   1,951   52   2,003
Undeveloped   65   142   322   217   537   100   72   9   1,464   156   1,620
                                             
Estimated net proved natural gas reserves   (bcf)                            
    Italy   Rest of Europe   North Africa   West Africa   Kazakhstan   Rest of Asia   America   Australia and Oceania   Total consolidated subsidiaries   Equity-accounted entities   Total
Year ended December 31, 2008 (b)   2,844   1,421   6,311   2,084   2,437   911   600   606   17,214   1,534   18,748
Developed   2,031   1,122   3,537   1,443   2,005   439   340   221   11,138   230   11,368
Undeveloped   813   299   2,774   641   432   472   260   385   6,076   1,304   7,380
Year ended December 31, 2009   2,704   1,380   5,894   2,127   2,139   814   629   575   16,262   1,588   17,850
Developed   2,001   1,231   3,486   1,463   1,859   539   506   565   11,650   234   11,884
Undeveloped   703   149   2,408   664   280   275   123   10   4,612   1,354   5,966
Year ended December 31, 2010   2,644   1,401   6,207   2,127   1,874   871   530   544   16,198   1,684   17,882
Developed   2,061   1,103   3,100   1,550   1,621   560   431   539   10,965   246   11,211
Undeveloped   583   298   3,107   577   253   311   99   5   5,233   1,438   6,671
i i i
(a) i From April 1, 2010, Eni has updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. For further information see the paragraph "Summary of significant accounting policies" in the Notes to the Consolidated Financial Statements.
(b) i Includes a 29,4% stake of the reserves of the three equity-accounted Russian companies participated by the joint-venture 000 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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Proved undeveloped reserves
Proved undeveloped reserves as of December 31, 2010 totaled 2,821 mmboe. At year-end, liquids proved undeveloped reserves amounted to 1,620 mmbbl, mainly concentrated in Africa and Kazakhstan. Natural gas proved undeveloped reserves accounted for 6,671 bcf, mainly located in Africa and Russia.
In 2010, total proved undeveloped reserves increased by 354 mmboe. The main reasons for the variation are revisions and new projects sanction, mainly in Libya, Venezuela and Iraq.
During 2010, Eni converted 295 mmboe of proved undeveloped reserves to proved developed reserves. The main reclassification to proved developed were related to development activities, revisions and production start-up of the following fields/projects: Cerro Falcone (Italy), M’Boundi (Congo), Wafa (Libya), Bhit and Sawan (Pakistan), Morvin (Norway), Tuna and Hapy (Egypt) and Karachaganak (Kazakhstan).
In 2010, capital expenditures amounted to approximately euro 1.7 billion and were made to progress the development of proved undeveloped reserves.
Reserves that remain proved undeveloped for five or more years are a result of several physical factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructure or plant capacities and contractual limitations that establish production levels.
The Company estimates that approximately 0.9 bboe of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.6 bboe) where development activities are progressing and production start-up is targeted by the end of 2012. For more details regarding this project please refer to "Main exploration and development projects-Kashagan"; (ii) some Libyan gas fields where development activities and production start-up is dependent upon a long-term gas supply agreement; and (iii) other minor projects where development activities are progressing.

Delivery commitments
Eni sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities.
Eni is contractually committed under existing contracts or agreements to deliver in the next three years almost exclusively natural gas to third parties for a total of approximately 1,852 bcf from producing assets located in Australia, Egypt, India, Indonesia, Libya, Nigeria, Norway, Pakistan, Tunisia and the United Kingdom.
The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products.
Management believes it can satisfy these contracts from quantities available from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 68% of delivery commitments.
The temporary shut down of the GreenStream pipeline due to ongoing tensions and unrest in Libya will not materially impair the Company’s ability to fulfill its contractual delivery

  commitments with third parties as the Company can make use of its gas availability form various sources to meet those commitments.
Eni has met all contractual delivery commitments as of December 31, 2010.

Oil and gas production

Eni reported oil and natural gas production for the full year of 1,815 kboe/d. This was calculated assuming a natural gas conversion factor to barrel equivalent which was updated to 5,550 cubic feet of gas equal 1 barrel of oil from April 1, 2010. On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production showed an increase of 1.1% for the full year. Production growth was driven by additions from 12 new field start-ups, particularly the Zubair field (Eni’s interest 32.8%) in Iraq, and production ramp-ups at fields which were started-up in 2009 (for a total increase of 40 kboe/d). These increases were partially offset by mature field declines. Lower entitlements in the Company’s PSAs due to higher oil prices, as well as lower gas uplifts in Libya as a result of oversupply conditions in the European market were partly offset by lower OPEC restrictions resulting in a net negative impact of approximately 7 kboe/d. The share of oil and natural gas produced outside Italy was 90% (90% in 2009).
Liquids production (997 kbbl/d) decreased by 10 kbbl/d from 2009 (down 1%). The impact of mature field declines was partly offset by organic growth and production start-ups achieved in particular in Nigeria, due to the ramp-up of the Oyo project (Eni’s interest 40%), in Italy as a result of the ramp-up of the Val d’Agri enhanced development project (Eni’s interest 60.77%), in Tunisia due to the production start-up/ramp-up of the Baraka and Maamoura projects (Eni operator with a 49% interest) as well as Zubair in Iraq.
Natural gas production (4,540 mmcf/d) increased by 166 mmcf/d from 2009 (up 4%). The main increases were registered in Nigeria, due to projects start-up in the Block OML 28 (Eni’s interest 5%), in Australia, due to ramp-up of the Blacktip project (Eni’s interest 100%), in Congo, due to ramp-up of the M’Boundi gas project (Eni operator with a 83% interest), in Egypt, due to start-up of the Tuna field (Eni operator with a 50% interest), in Italy, due to start-up of the Annamaria project (Eni operator with a 90% interest) and in India, due to organic growth of the PY-1 project (Eni’s interest 47.18%). These increases were offset in part by mature field declines.
Production started at all 12 fields planned for the year. The main projects, in addition to Zubair in Iraq, were the following: Annamaria located in an offshore area between Italy and Croatia, Baraka in Tunisia, Rom Integrated in Algeria, M’Boundi IPP (Eni’s interest 100%) in Congo, Morvin (Eni’s interest 30%) in Norway, Arcadia (Eni operator with a 56% interest) and Tuna in Egypt, as well as other start-ups in China, Congo, Nigeria and the United Kingdom.
Oil and gas production sold amounted to 638 mmboe. The 24.5 mmboe difference over production (662.5 mmboe) reflected volumes of natural gas consumed in operations (20.9 mmboe).
Approximately 58% of liquids production sold (361.3 mmbbl) was destined to Eni’s Refining & Marketing Division (of which 18% was processed in Eni’s refinery); about 28% of natural gas production sold (1,536 bcf) was destined to Eni’s Gas & Power Division.

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Eni Annual Report / Operating review

Oil and natural gas production (a) (b) (c)
    Liquids (kbbl/d)   Natural gas (mmcf/d)   Hydrocarbons (kboe/d)   Liquids (kbbl/d)   Natural gas (mmcf/d)   Hydrocarbons (kboe/d)   Liquids (kbbl/d)   Natural gas(mmcf/d)   Hydrocarbons (kboe/d)
    2008   2009   2010
   
 
 
Italy   68   749.9   199   56   652.6   169   61   673.2   183
Rest of Europe   140   626.7   249   133   655.5   247   121   559.2   222
     Croatia       68.7   12       95.5   17       45.3   8
     Norway   83   264.8   129   78   273.7   126   74   271.6   123
     United Kingdom   57   293.2   108   55   286.3   104   47   242.3   91
North Africa   338   1,761.6   645   292   1,614.2   573   301   1,673.2   602
     Algeria   80   18.5   83   80   19.7   83   74   20.2   77
     Egypt   98   818.4   240   91   793.7   230   96   755.1   232
     Libya   147   907.6   306   108   780.4   244   116   871.1   273
     Tunisia   13   17.1   16   13   20.4   16   15   26.8   20
West Africa   289   260.7   335   312   274.3   360   321   441.5   400
     Angola   121   28.1   126   125   29.3   130   113   31.9   118
     Congo   84   12.7   87   97   27.3   102   98   67.9   110
     Nigeria   84   219.9   122   90   217.7   128   110   341.7   172
Kazakhstan   69   244.7   111   70   259.0   115   65   237.0   108
Rest of Asia   49   426.2   124   57   444.8   135   48   463.9   131
     China   6   10.9   8   7   8.2   8   6   6.7   7
     India                   3.7   1   1   36.6   8
     Indonesia   2   99.7   20   2   104.8   21   2   94.4   19
     Iran   28       28   35       35   21       21
     Iraq                           5       5
     Pakistan   1   315.6   56   1   328.1   58   1   326.2   59
     Turkmenistan   12       12   12       12   12       12
America   63   311.5   117   79   424.7   153   71   396.0   143
     Ecuador   16       16   14       14   11       11
     Trinidad & Tobago       54.6   9       67.0   12       63.6   12
     United States   42   256.9   87   57   357.7   119   50   332.4   110
     Venezuela   5       5   8       8   10       10
Australia and Oceania   10   42.2   17   8   48.6   17   9   95.7   26
     Australia   10   42.2   17   8   48.6   17   9   95.7   26
Total   1,026   4,423.5   1,797   1,007   4,373.7   1,769   997   4,539.7   1,815
Oil and natural gas production net of updating the natural gas conversion factor   -   -   1,797   -   -   1,769   -   -   1,789
i i i
(a) i From April 1, 2010, Eni has updated the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent. For further information see the paragraph "Summary of significant accounting policies" in the Notes to the Consolidated Financial Statements.
(b) i Includes volumes of gas consumed in operations (318, 300 and 281 mmcf/d in 2010, 2009 and 2008, respectively).
(c) i Includes Eni’s share of equity-accounted entities production.

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Eni Annual Report / Operating review

Drilling and other exploratory
and development activities

Exploration
In 2010, a total of 47 new exploratory wells7 were drilled (23.8 of which represented Eni’s share), as compared to 69 exploratory wells drilled in 2009 (37.6 of which represented Eni’s share) and 111 exploratory wells drilled in 2008 (58.4 of which represented Eni’s share).

The following tables show the number of net productive, dry and in progress exploratory wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of the FASB Extractive Activities - Oil & Gas (Topic 932).

Overall commercial success rate was 41% (39% net to Eni) as compared to 41.9% (43.6% net to Eni) and 36.5% (43.4% net to Eni) in 2009 and 2008, respectively.

 

Development
In 2010 a total of 399 development wells were drilled (178 of which represented Eni’s share) as compared to 418 development wells drilled in 2009 (175.1 of which represented Eni’s share) and 366 development wells drilled in 2008 (155.1 of which represented Eni’s share).

The drilling of 122 wells (43 of which represented Eni’s share) is currently underway. Oil and natural gas producing wells were 8,153 (2,895.6 of which represented Eni’s share).

The following tables show the number of net productive, dry and in progress development wells as well as productive wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of the FASB Extractive Activities - Oil & Gas (Topic 932).

 

Net exploration and development drilling activity

(units)

i

Italy

i

Rest
of Europe

i

North Africa

i

West Africa

i

Kazakhstan

i

Rest of Asia

i

America

i

Australia and Oceania

i

Total

2008   0.7   3.7   22.9   7.4       16.2   3.4   1.4   55.7
Exploratory                                    
     Productive       0.7   8.7   4.0       9.4   1.4       24.2
     Dry (a)   0.7   3.0   14.2   3.4       6.8   2.0   1.4   31.5
Development   12.9   5.5   47.6   37.2   2.6   43.0   6.3       155.1
     Productive   11.3   5.5   46.4   36.4   2.6   36.5   6.3       145.0
     Dry (a)   1.6       1.2   0.8       6.5           10.1
2009   1.0   4.3   8.6   2.7       6.2   4.8   2.2   29.8
Exploratory                                    
     Productive       4.1   4.8           2.3   1.0   0.8   13.0
     Dry (a)   1.0   0.2   3.8   2.7       3.9   3.8   1.4   16.8
Development   18.3   12.5   41.1   37.7   3.8   42.9   16.6   2.2   175.1
     Productive   18.3   12.5   40.7   35.8   3.8   38.6   15.6   2.2   167.5
     Dry (a)           0.4   1.9       4.3   1.0       7.6
2010   0.5   2.8   17.4   7.0       3.8   6.3   1.4   39.2
Exploratory                                    
     Productive       1.7   9.3   2.3       1.0       1.0   15.3
     Dry (a)   0.5   1.1   8.1   4.7       2.8   6.3   0.4   23.9
Development   24.9   3.1   44.6   30.5   1.8   43.5   28.1   1.5   178.0
     Productive   23.9   2.9   44.3   28.0   1.8   41.7   27.6   1.5   171.7
     Dry (a)   1.0   0.2   0.3   2.5       1.8   0.5       6.3
i i i
(a) i 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.

 


(7) i Including drilled exploratory wells that have been suspended pending further evaluation.

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Eni Annual Report / Operating review

Present activities

Drilling activity in progress  

(units)

                   

i

i

Italy

i

Rest
of Europe

i

North Africa

i

West Africa

i

Kazakhstan

i

Rest of Asia

i

America

i

Australia and Oceania

i

Total

2010                                    
Exploratory (a)                                    
     Gross   6.0   19.0   11.0   52.0   13.0   22.0   13.0   1.0   137.0
     Net   4.4   5.0   8.7   12.6   2.3   11.7   4.0   0.4   49.1
Development                                    
     Gross   4.0   18.0   18.0   23.0   8.0   11.0   40.0       122.0
     Net   3.5   2.9   8.1   8.4   1.5   5.8   12.8       43.0
     
(a)   Includes temporary suspended wells pending further evaluation.

Oil and gas properties, wells, operations and acreage

Productive oil and gas wells (a)  

(units)

                   

i

i

Italy

i

Rest
of Europe

i

North Africa

i

West Africa

i

Kazakhstan

i

Rest of Asia

i

America

i

Australia and Oceania

i

Total

2010                                    
Oil wells                                    
     Gross   224.0   408.0   1,240.0   3,002.0   91.0   618.0   134.0   4.0   5,721.0
     Net   184.4   63.1   601.1   515.3   29.6   383.8   63.6   2.6   1,843.5
Gas wells                                    
     Gross  

525.0

  206.0   131.0   505.0       762.0   289.0   14.0   2,432.0
     Net   479.3   93.2   52.6   37.1       290.5   96.1   3.3   1,052.1
     
(a)   Includes 2,320 gross (700 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.

 

Acreage
As of December 31, 2010, Eni’s mineral right portfolio consisted of 1,176 exclusive or shared rights for exploration and development in 43 Countries on five continents for a total acreage of 320,961 square kilometers net to Eni of which developed acreage of 41,386 square kilometers and undeveloped acreage of 279,575 square kilometers.
In 2010, changes in total net acreage mainly derived from: (i) new leases in Poland, Democratic Republic of Congo, Togo, Angola, Pakistan and Venezuela for a total acreage of approximately
  13,000 square kilometers; (ii) the divestment of the wholly-owned subsidiary Società Padana Energia and leases in Nigeria for a total acreage of approximately 1,500 square kilometers; (iii) the total relinquishment of mainly exploration leases in Pakistan, Australia, Congo, Italy, Egypt, Russia and East Timor, covering an undeveloped acreage in excess of 23,000 square kilometers; and (iv) the decrease in net acreage due to partial relinquishment or interest reduction in Mali and Indonesia for a total net acreage of approximately 15,000 square kilometers.

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Eni Annual Report / Operating review

Oil and natural gas interests
 

December 31, 2009

 

December 31, 2010

 
 
   

Total net acreage (a)

 

Number
of interests

 

Gross developed acreage (a) (b)

 

Gross undeveloped acreage (a) (b)

 

Total gross acreage (a)

 

Net
developed
acreage
(a) (b)

 

Net undeveloped acreage (a) (b)

 

Total net acreage (a)

   
 
 
 
 
 
 
 
EUROPE   31,607   287   17,430   28,293   45,723   11,142   17,937   29,079
Italy   22,038   154   10,951   12,945   23,896   8,995   10,102   19,097
Rest of Europe   9,569   133   6,479   15,348   21,827   2,147   7,835   9,982
     Croatia   987   2   1,975       1,975   987       987
     Norway   3,412   49   2,276   5,956   8,232   338   2,080   2,418
     Poland       3       1,968   1,968       1,968   1,968
     United Kingdom   1,469   73   2,228   1,364   3,592   822   329   1,151
     Other Countries   3,701   6       6,060   6,060       3,458   3,458
AFRICA   158,749   274   68,350   211,830   280,180   20,153   132,518   152,671
North Africa   46,011   116   31,723   48,530   80,253   13,802   30,475   44,277
     Algeria   17,244   38   2,177   17,433   19,610   730   16,514   17,244
     Egypt   8,328   54   5,135   12,669   17,804   1,847   4,747   6,594
     Libya   18,165   13   17,947   18,428   36,375   8,951   9,214   18,165
     Tunisia   2,274   11   6,464       6,464   2,274       2,274
West Africa   60,524   152   36,627   86,076   122,703   6,351   49,830   56,181
     Angola   3,393   68   4,532   15,569   20,101   589   3,931   4,520
     Congo   8,188   25   1,900   9,680   11,580   1,044   5,030   6,074
     Democratic Republic of Congo       1       1,118   1,118       615   615
     Gabon   7,615   6       7,615   7,615       7,615   7,615
     Ghana   1,086   2       2,300   2,300       1,086   1,086
     Mali   31,668   1       32,458   32,458       21,640   21,640
     Nigeria   8,574   47   30,195   11,144   41,339   4,718   3,721   8,439
     Togo       2       6,192   6,192       6,192   6,192
     Other Countries   52,214   6       77,224   77,224       52,213   52,213
ASIA   125,641   78   18,825   191,203   210,028   6,352   106,393   112,745
Kazakhstan   880   6   324   4,609   4,933   105   775   880
Rest of Asia   124,761   72   18,501   186,594   205,095   6,247   105,618   111,865
     China   18,322   10   138   18,256   18,394   22   18,210   18,232
     East Timor   7,999   4       8,087   8,087       6,470   6,470
     India   10,089   14   303   27,861   28,164   143   9,946   10,089
     Indonesia   16,519   12   1,735   24,054   25,789   656   12,256   12,912
     Iran   820   4   1,456       1,456   820       820
     Iraq   640   1   1,950       1,950   640       640
     Pakistan   18,201   18   9,122   17,224   26,346   2,708   8,639   11,347
     Russia   2,323   4   3,597   1,529   5,126   1,058   449   1,507
     Saudi Arabia   25,844   1       51,687   51,687       25,844   25,844
     Turkmenistan   200   1   200       200   200       200
     Yemen   20,560   2       23,296   23,296       20,560   20,560
     Other Countries   3,244   1       14,600   14,600       3,244   3,244
AMERICA   11,523   522   4,659   17,356   22,015   3,063   8,124   11,187
     Brazil   1,067   1       745   745       745   745
     Ecuador   2,000   1   2,000       2,000   2,000       2,000
     Trinidad and Tobago   66   1   382       382   66       66
     USA   6,450   506   1,899   8,536   10,435   899   4,997   5,896
     Venezuela   614   5   378   2,528   2,906   98   1,056   1,154
     Other Countries   1,326   8       5,547   5,547       1,326   1,326
AUSTRALIA AND OCEANIA   20,342   15   1,057   43,153   44,210   676   14,603   15,279
     Australia   20,304   14   1,057   42,389   43,446   676   14,565   15,241
     Other Countries   38   1       764   764       38   38
Total   347,862   1,176   110,321   491,835   602,156   41,386   279,575   320,961
i i i
(a) i Square kilometers.
(b) i Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

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Eni Annual Report / Operating review

Main exploration and development projects

Italy

In October 2010, with a view to rationalizing its upstream portfolio, Eni closed the divestment of the entire share capital of its subsidiary Società Padana Energia to Gas Plus. The divested subsidiary includes exploration leases and concessions for developing and producing oil and natural gas in Northern Italy. Cash consideration for the deal amounted to euro 179 million, subject to a possible adjustment of up to euro 25 million related to achieving certain production targets at assets under development. Further price adjustments are foreseen in connection with appraising the underlying exploration potential.
On August 26, 2010 became effective the Law Decree No. 128 of June 29, 2010 issued by the Italian Government that introduced certain restrictions for hydrocarbons exploration and production activities mainly in certain offshore and coastline areas due to environmental constraints without impacting the titles already granted to conduct oil and gas operations.
Eni and other operators in the industry have commenced discussions with the Ministry for Economic Development and the Ministry for the Environment to clarify uncertainties in correctly interpreting and applying the new regulations. During the year the Group did not incur any significant impact on its operations related with this new decree, while certain projects initially planned for 2011 have been rescheduled.
In 2010 production started-up at: (i) the Annamaria B production platform (Eni operator with a 90% interest), located at the border with Croatian territorial waters. During the course of the year the field reached its production plateau at approximately 40 mmcf/d; (ii) the Bonaccia Est field flowing at the initial rate of approximately 36 mmcf/d.
Development activities progressed at the Val d’Agri concession (Eni’s interest 60.77%) as wells at Cerro Falcone were connected to the oil treatment centre. Other activities were performed including: (i) optimization of producing fields by means of sidetrack and work over activities (Barbara, Annalisa and Azalea); (ii) sidetrack programs and facility upgrading in Val d’Agri; (iii) upgrading activities of compression plants and treatment facilities at the Crotone plants; (iv) development activities at the Capparuccia, Tresauro and Guendalina fields.

Rest of Europe

Norway Exploration activities yielded positive results in: (i) the Prospecting License 128 (Eni’s interest 11.5%) with the Fossekal oil discovery that will exploit synergies with the Norne (Eni’s interest 6.9%) production facilities; (ii) the PL 473 license (Eni’s interest 29.4%) with the Flyndretind oil discovery.
In 2010 production was started up at the Morvin field (Eni’s interest 30%) through the first three wells of the development program. Production is expected to peak at 15 kboe/d net to Eni in 2011 when the project is completed.
Development activities have been progressing at the Goliat field (Eni operator with a 65% interest) in the Barents Sea. In 2010, EPC contracts have been awarded for building an FPSO unit that will

  be linked to an underwater production system, onshore facilities and an offshore supply system designed to reduce CO2 emissions. Start-up is expected in 2013 with a production plateau at 100 kbbl/d. Development activities progressed to put in production discovered reserves near the Asgaard field (Eni’s interest 14.82%) with the Marulk development plan (Eni operator with a 20% interest). Start-up is expected in 2012.
Other ongoing activities aimed at maintaining and optimizing production at the Ekofisk field by means of infilling wells, the development of the South Area, upgrading of existing facilities and optimization of water injection.

United Kingdom Exploration activity concerned the drilling of an appraisal well at the Culzean gas discovery (Eni’s interest 16.95%), near the Elgin/Franklin producing field (Eni’s interest 21.87%) for assessing its possible development options.
In 2010, Eni signed a Sale and Purchase Agreement to divest its 18% stake of the Blane producing field and closed the divestment of its entire working interest in the Laggan (Eni’s interest 20%) and Tormore (Eni’s interest 22.5%) pre-development fields.
Production started-up at the Burghley field (Eni’s interest 21.92%). Ongoing activities are aimed at optimizing production at the Elgin/Franklin field and infilling activity at the J-Block (Eni’s interest 33%).
In the fourth quarter of 2010 the following projects were sanctioned by partners and relevant authorities: (i) development program at the Jasmine discovery (Eni’s interest 33%). Engineering activities are ongoing. Start-up is expected in 2012; (ii) Phase 2 of the development program of the West Franklin field (Eni’s interest 21.87%). This project provides the construction of a production platform, drilling additional wells and linkage to the Elgin/Franklin treatment plant.
Pre-development activities started at the Kinnoul oil and gas discovery (Eni’s interest 16.67%) to be developed in synergy with the production facilities of the Andrew field (Eni’s interest 16.21%).

North Africa

Algeria Development activity progressed on the MLE and CAFC integrated project (Eni’s interest 75%) purchased in 2008 from the Canadian company First Calgary. The final investment decision of projects was sanctioned (MLE in 2009; CAFC in April 2010). The MLE development plan foresees the construction of a natural gas treatment plant with a capacity of 350 mmcf/d and of four export pipelines with linkage to the national grid system. These facilities will also receive gas from the CAFC field. As of December 31, 2010, 61% of the project was completed. The CAFC project provides the construction of an oil treatment plant and will also benefit from synergies with existing MLE production facilities. As of December 31, 2010, 27% of the project was completed. Oil and natural gas production start-up is expected in 2012 and 2011, respectively, with a production plateau of approximately 33 kboe/d net to Eni by 2014.
Other development activity regarded mainly: (i) the development of the integrated Rom project and satellites (Zea, Zec and Rec) reserves following the area’s mineral potential revaluation. The project has been approved by the relevant authorities. Current production is collected at the Rom Central Production Facility

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Eni Annual Report / Operating review

(CPF) and delivered to the treatment plant in Bir Rebaa North. An export pipeline has been completed and a new multiphase pumping system is under construction in compliance with applicable Country law to reduce gas flaring; (ii) the El Merk project. Drilling activities and the construction of treatment facilities are underway. The 60% of the project was completed at year-end. Production start-up is expected in 2012.

Egypt Exploration activities yielded positive results in the: (i) Belayim concession (Eni’s interest 100%) with two discovery wells containing oil that were linked to existing facilities; (ii) El Qara North (Eni’s interest 75%) and Zaafaran East (Eni’s interest 75%) gas discoveries which were linked to the existing nearby facilities; (iii) Melehia development lease (Eni’s interest 56%) with the Jana and Arcadia oil discoveries. The latter was started-up in the second half of the year.
In July 2010, Eni signed a Strategic Framework Agreement with the Egyptian Ministry of Petroleum for new upstream and downstream initiatives. The agreement provides for: (i) a joint study to evaluate a number of upstream activities in the Mediterranean basin and outside Egypt, including Gabon and Iraq; and (ii) an initiative to secure rights for Eni to acquire gas transport capacity in the Arab Gas Pipeline system in compliance with existing intergovernmental agreements.
In May 2010, Eni divested a 50% interest in the Ashrafi offshore field located in the Gulf of Suez. Eni will retain operatorship and a 50% interest.
Production start-up was achieved at the Tuna field (Eni operator with a 50% interest) through linkage to the El Gamil facility with a production plateau at approximately 70 mmcf/d net to Eni.
Other development activities mainly regarded: (i) the basic engineering of the Belayim field for the upgrading of water injection facilities to recover residual reserves; (ii) the second phase of the Denise field (Eni operator with a 50% interest); (iii) the upgrading of the El Gamil plant by adding new compression capacity to support production.
Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 bcf/y of feed gas. Eni is currently supplying 35 bcf/y for a twenty-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 kboe/d net to Eni of feed gas.

Libya For further information about Libyan Tensions see page 13. Main development activities underway concerned the Western Libyan Gas project (Eni’s interest 50%) for the monetization of gas reserves ratified in the strategic agreements between Eni and NOC. Activities were performed for maintaining gas production profiles at the Wafa and Bahr Essalam fields through increasing compression capacity at the Wafa field and drilling additional wells at both fields. In 2010 volumes delivered through the GreenStream pipeline were 309 bcf. In addition, 53 bcf were sold on the Libyan market for power generation and approximately 7 bcf to feed the GreenStream compressor station.

Tunisia In 2010 Eni signed new terms for the El Borma concession (Eni’s interest 50%), due to expire in 2043. Development activities concerned the completion of the operated Baraka project (Eni’s

  interest 49%) and ramp-up of production at Maamoura field (Eni operator with a 49% interest).
Optimization of production was carried out at the Adam (Eni operator with a 25% interest), Djebel Grouz (Eni’s interest 50%), Oued Zar (Eni’s interest 50%) and El Borma fields.

West Africa

Angola Exploration activities yielded positive results in: (i) Block 0 (Eni’s interest 9.8%) with the liquids and gas discovery located in the Vanza area; (ii) Development Areas in former Block 14 (Eni’s interest 20%) with the Lucapa 6 appraisal oil well. Activities are underway for assessing its possible development opportunities following the area’s mineral potential revaluation; (iii) operated Block 15/06 (Eni’s interest 35%) with the appraisal wells of the Cinguvu (Cinguvu-1), Cabaça (Cabaça South East-2) and Mpungi (Mpungi 1 e 2) oil discoveries. The appraisal activities were completed ahead of schedule with commitments increasing the initial resource estimate to develop the East Hub and West Hub projects. In February 2010, the West Hub concept definition (FEED) was approved while the final investment decision was sanctioned at year end. Start-up is expected in 2013 with peaking production at 22 kbbl/d.
In January 2011, Eni was awarded rights to explore and the operatorship of deep offshore Block 35, with a 30% interest. The agreement foresees the drilling of 2 commitment wells to be carried out in the first 5 years of exploration phase. This deal is subject to the approval of the relevant authorities.
Within the activities for reducing gas flaring in Block 0, activity progressed at the Nemba field in Area B. Completion is expected in 2013 reducing flared gas by approximately 85%. Other ongoing projects include: (i) completion of linkage and treatment facilities at the Malongo plant; (ii) installation of a second compression unit at the platform in the Nemba field in Area B. Flaring down of the Malongo area is still underway with completion expected in 2011.
In the Development Areas of former Block 14, infilling activity was carried out at the Benguela-Belize/Lobito-Tomboco fields.
Main projects underway in the Development Areas of former Block 15 (Eni’s interest 20%) regarded: (i) the satellites of Kizomba Phase 1, with start-up expected before mid 2012 and peaking production at 100 kbbl/d (21 kbbl/d net to Eni) in 2013; (ii) drilling activity at the Mondo and Saxi/Batuque fields to finalize their development plan. The subsea facility of the Gas Gathering project has been already completed. The project provides the construction of a pipeline collecting all the gas of the Kizomba, Mondo and Saxi/Batuque fields.
Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers North of Luanda. It will be designed with a processing capacity of approximately 1 bcf/d of natural gas and produce 5.2 mmtonnes/y of LNG, condensates and LPG. The project has been sanctioned by relevant Angolan authorities. It envisages the development of 10,594 bcf of gas in 30 years. Start-up is expected in the first quarter of 2012. LNG is expected to be delivered to the United States market at the re-gasification plant in Pascagoula, currently under construction, (Eni’s capacity amounting to approximately 205 bcf/y) in Mississippi.
During the year Eni signed a Memorandum of Understanding with

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the other project partners to assess further possible marketing opportunities.
In 2010 the following activities were carried out: (i) engineering and procurement; (ii) linkage to onshore facilities; (iii) increase in storage capacity of LNG, condensates and LPG; (iv) fuel gas supplies from Block 15.
In addition, Eni is part of a second gas consortium with the national Angolan company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or other marketing projects to deliver gas and associated liquids. Eni is technical advisor with a 20% interest.

Congo Production started-up at Zingali and Loufika (Eni operator with an 85% interest) onshore satellites of the M’Boundi field. Ongoing development activities concerned offshore fields with start-up expected in the 2011-2012 period.
Activities on the M’Boundi field (Eni operator with an 83% interest) moved forward with the application of advanced recovery techniques and a design to monetize associated gas within the activities aimed at reducing flared gas. Eni signed a long term agreement to supply associated gas from the M’Boundi field to feed three facilities in the Pointe Noire area: (i) the under construction potassium plant, owned by Canadian Company MAG Industries; (ii) the existing Djeno power plant (CED - Centrale Electrique du Djeno); (iii) the recently built CEC Centrale Electrique du Congo power plant (Eni’s interest 20%). These facilities will also receive gas in the future from the offshore discoveries of the Marine XII permit. Development activities to build the CEC power plant moved forward as scheduled in the cooperation agreement signed by Eni and the Republic of Congo in 2007, with the start-up of the first and second turbo-generator.
Within the activities aimed to monetize gas reserves, the RIT project moved forward with the rehabilitation plan of the Pointe Noire-Brazzaville power grid. In 2010 the RIT project - Phase 1 (DEPN - electric power distribution) started-up in Pointe Noire.

Nigeria Exploration activity yielded positive results with the Tuomo 4 oil discovery (Eni’s interest 20%).
In Blocks OML 60, 61, 62 and 63 (Eni operator with a 20% interest), within the activities aimed at guaranteeing production to feed gas to the Bonny liquefaction plant development activity concerned: (i) the completion of basic engineering to increase capacity at the Obiafu/Obrikon plant; (ii) the installation of a new treatment plant and transport facilities to ensure 155 mmcf/d of feed gas for a twenty-year period. To the same end the development plan of the Tuomo gas field has been progressing along with its linkage to the Ogbainbiri treatment plant. In 2010 a new compressor plant was started up aiming to feed gas for the liquefaction trains 4 and 5, amounting to 311 mmcf/d (60 mmcf/d net to Eni). In Block OML 61 flaring down of the Ebocha oil plant was completed.
The Forcados/Yokri oil and gas field (Eni’s interest 5%) is under development as part of the integrated associated gas gathering project aimed at supplying gas to the domestic market. First gas is expected in 2013 and project completion in 2015.
In the Block OML 28 (Eni’s interest 5%) within the integrated oil and natural gas project in the Gbaran-Ubie area, the first treatment unit started-up with first gas production. The development plan provides for the construction of a Central Processing Facility (CPF)

  with treatment capacity of about 1 bcf/d of gas and 120 kbbl/day of liquids, the drilling of producing wells and the construction of a pipeline to carry the gas to the Bonny liquefaction plant.
Eni holds a 10.4% interest in Nigeria LNG Ltd responsible for the management of the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 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. In 2010, total supplies were 1,870 mmcf/d (191 mmcf/d net to Eni corresponding to 34 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 of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100 kilometers west of Bonny. This plant is expected to start operating in 2016 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 60 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity (corresponding to approximately 81 bcf/y). LNG will be delivered to the United States market mainly at the re-gasification plant in Cameron, in Louisiana, USA. Eni’s capacity amounts to approximately 201 bcf/y. Front end engineering activities progressed. The final investment decision is expected in 2011.

Kazakhstan

Kashagan Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. Management believes this field contains a large amount of hydrocarbon resources which will eventually be developed in phases.
The exploration and development activities of the Kashagan field and the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The new 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:

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Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and the onshore part of Phase 2. The Consortium is currently focused on completing Phase 1 and starting commercial oil production. Management estimates that the degree of completion of Phase 1 was 80% as of end of December 2010. Tranches 1 and 2 of the scope of work which target commercial production start-up reached a degree of completion of approximately 90% by the end of December 2010.
The partners of the venture are currently discussing an update of the expenditures and time schedule to complete the Phase 1 which were included in the development plan approved in 2008 by the relevant Kazakh Authorities. The Consortium continues to target the achievement of first commercial oil production by end of 2012. However, the timely delivery of Phase 1 depends on a number of factors which are presently under review.
The Phase 1 of the project targets an initial production capacity of 150 kbbl/d. In the following 12-15 months subsequent to the start-up, treatment and compression plant for gas re-injection will be completed and come online enabling an increase in the production capacity to 370 kbbl/d by 2014. A further increase of production capacity to 450 kbbl/d is expected as additional compression capacity for gas re-injection becomes available with the start-up of Phase 2 offshore facilities. Early engineering studies of Phase 2 are underway aiming at optimizing the development scheme.
However, taking into account that future development expenditures will be incurred over a long time horizon and subsequently to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets.
As of December 31, 2010, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $5.8 billion (euro 4.4 billion at the EUR/USD exchange rate of December 31, 2010). This capitalized amount included: (i) $4.5 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $1.3 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years.
As of December 31, 2010, Eni’s proved reserves booked for the Kashagan field amounted to 569 mmboe, recording a decrease of 19 mmboe with respect to 2009 due to price effect.

Karachaganak The execution of the fourth treatment unit has been progressing towards completion and will enable to increase export of oil volumes to Western markets of currently non-stabilized liquids delivered to the Orenburg terminal.
Phase 3 of the Karachaganak project is aimed at increasing the development of gas and condensates reserves. The engineering activities identified a new design to complete development activities in multiple phases. The project provides for the installation of gas producing and re-injection facilities to increase gas sales at the Orenburg plant up to 565 bcf/y and the liquids production up to approximately 14 mmtonnes/y. The sanction of

  relevant Authorities to the start-up with Phase 3 is currently in the phase of technical and marketing discussion.
As of December 31, 2010, Eni’s proved reserves booked for the Karachaganak field amounted to 557 mmboe, recording a decrease of 76 mmboe with respect to 2009 due to price effect and production of the year.

Rest of Asia

Indonesia Exploration activity yielded positive results in the Muara Bakau permit (Eni operator with a 55% interest), located offshore Borneo, where the Jangkrik 2 and 3 appraisal wells significantly increased the initial reserve evaluations to over 1,400 bcf.
Eni is also involved in the ongoing study phase of joint development of the oil and gas discoveries in the Bukat permit (Eni operator with a 66.25% interest) and the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%). In 2010 the exploration activities related to the coal bed methane project were started in the Sanga Sanga PSC (Eni’s interest 37.8%). In case of commercial discovery, the project will exploit the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant.

Iran In 2010 the activities were completed at the Darquain project which related to plant commissioning and start-up in view of making formal hand over of operations to local partners. Darquain was the sole Eni-operated project in the Country. When hand over of operations will be completed, Eni’s involvements essentially consist of being reimbursed for its past investments.

Iraq In January 2010, Eni leading a consortium of partners including international companies and the national oil company Missan Oil signed a technical service contract to develop the Zubair oil field (Eni 32.8%)with the Iraqi South Oil Company, under a 20-year term with an option for further 5 years extension. The field was awarded to the Eni-led consortium following a successful first bid round and was offered under a competitive bid starting on June 30, 2009. The development of the project foresees to gradually increase production to a target plateau level of 1.2 mmbbl/d over the next six years. The contract provides for the recovery of expenditures incurred from the incremental production of the field and the recognition of a remuneration fee once the production has been raised by 10% from its initial level of approximately 180 kbbl/d. Development provides for two phases: (i) Rehabilitation plan, approved in June 2010, aimed at improving the current production level and the knowledge of the reservoir; (ii) Redevelopment plan allowing to reach the scheduled targets.
In 2010 all the milestones planned for the initial phase of the project were achieved. In particular in September 2010, production was raised by more than 10% above the initial production rate allowing the Consortium, based on the contact provisions, to begin recovery of costs and recognition of remuneration fee. Therefore Eni starting from the last quarter of 2010 booked its equity production in relation to its share of cost recovery and remuneration.

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Pakistan Exploration activity yielded positive results with the Latif North 1 appraisal well (Eni’s interest 33.33%) which started-up in 2010.
Development activities concerned: (i) the Bhit field (Eni operator with a 40% interest) with the completion of a compressor plant and the drilling of new wells aimed at maintaining current production plateau; (ii) the Sawan field (Eni’s interest 23.68%) with a review of production facilities and reservoir to mitigate the current decline; (iii) the Zamzama permit (Eni’s interest 17.75%) with the start-up of the Front End Compressor.

America

Trinidad and Tobago In 2010 the development plan of the Poinsettia, Bougainvillea and Heliconia fields in the North Coast Marine Area 1 (Eni’s interest 17.4%) was completed through the installation of a production platform on the Poinsettia field and the linkage to the Hibiscus treatment facility which was already upgraded. The new scheme platform was started-up in 2010.

United States Exploration activity yielded positive results with the oil and natural gas Hadrian West appraisal well, located in offshore Block KC 919 (Eni’s interest 25%), in the Gulf of Mexico.
The main development activities concerned the Nikaitchuq operated field (Eni’s interest 100%), located in North Slope basins offshore Alaska, with resources of 220 million barrels. Production start-up was achieved at the end of January 2011. Peak production is expected at 28 kbbl/d.
In 2010 the development plan of the Alliance area (Eni’s interest 27.5%), in the Fort Worth basin in Texas moved forward. This area, including gas shale reserves, was acquired in 2009 following a strategic alliance Eni signed with Quicksilver Resources Inc. Production plateau at 10 kboe/d net to Eni is expected in 2012.
Drilling activities in the Gulf of Mexico were impacted by the incident at the BP-operated Macondo well.

  The US Government has imposed a six months moratorium on new offshore drilling activities that was suspended in October 2010. Through the end of 2010, development or drilling activities were still suspended, due to the delay in getting the relevant authorizations. For further detailed information on this matter, see the section "Risk factors and uncertainties".

Venezuela Exploration activities yielded positive results with the Perla 2 and 3 appraisal wells, located in the Cardon IV Block (Eni’s interest 50%) in the Gulf of Venezuela. The results exceeded the initial resource estimation by 50%. The development plan provides for a production target of approximately 300 mmcf/d in 2013. In 2010 Front End Engineering Design contracts related to offshore facility and transport infrastructure were assigned.
In June 2010 Eni was awarded gas exploration and development permits with a 40% interest in Punta Pescador and Golfo de Paria Ovest, the latter coinciding with the Corocoro oil field area (Eni’s interest 26%). Commitment activities are under negotiation with the relevant authorities
On January 26, 2010, Eni and the Venezuelan National Oil Company PDVSA signed an agreement for the joint development of the giant field Junin 5 with 35 bbbl of certified heavy oil in place, located in the Orinoco oil belt. The two partners plan to achieve first oil by 2013 at an initial rate of 75 kbbl/d, targeting a long-term production plateau of 240 kbbl/d to be reached in 2018.
As part of the agreement, on November 22, 2010, Eni and PDVSA signed the contracts to set up two Empresas Mixtas (Eni’s interest 40%, PDVSA’S interest 60%) for the development of the Junin 5 field and the construction and operation of a refinery with a capacity of 350 kbbl/d that will allow also the treatment
of intermediate streams from other PDVSA facilities. Eni, at the publication of the contract of incorporation of the Junin 5 project "Empresa Mixta" in December 2010 paid a bonus of $300 million; the balance of $346 million will be paid in tranches according to the achievement of milestones of the project.

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Capital expenditures

Capital expenditures of the Exploration & Production Division (euro 9,690 million) concerned development of oil and gas reserves (euro 8,578 million) directed mainly outside Italy, in particular in Egypt, Kazakhstan, Congo, the United States and Algeria. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri as well as sidetrack and work over activities in mature fields.   About 97% of exploration expenditures that amounted to euro 1,012 million were directed outside Italy in particular to Angola, Nigeria, the United States, Indonesia and Norway. In Italy, exploration activities were directed mainly to the offshore of Sicily.As compared to 2009, capital expenditures increased by euro 204 million, up 2.2%, due to higher development activities in Egypt, Algeria, Norway, Venezuela, the United States and Iraq.

 

Capital expenditures (euro million)   2008   2009   2010   Change     % Ch.  
Acquisition of proved and unproved properties     836   697       (697 )   ..  
North Africa     626   351                
West Africa     210   73                
Rest of Asia         94                
America         179                
Exploration     1,918   1,228   1,012   (216 )   (17.6 )
Italy     135   40   34   (6 )   (15.0 )
Rest of Europe     227   113   114   1     0.9  
North Africa     379   317   84   (233 )   (73.5 )
West Africa     485   284   406   122     43.0  
Kazakhstan     16   20   6   (14 )   (70.0 )
Rest of Asia     187   159   223   64     40.3  
America     441   243   119   (124 )   (51.0 )
Australia and Oceania     48   52   26   (26 )   (50.0 )
Development     6,429   7,478   8,578   1,100     14.7  
Italy     570   689   630   (59 )   (8.6 )
Rest of Europe     598   673   863   190     28.2  
North Africa     1,246   1,381   2,584   1,203     87.1  
West Africa     1,717   2,105   1,818   (287 )   (13.6 )
Kazakhstan     968   1,083   1,030   (53 )   (4.9 )
Rest of Asia     355   406   311   (95 )   (23.4 )
America     655   706   1,187   481     68.1  
Australia and Oceania     320   435   155   (280 )   (64.4 )
Other expenditures     98   83   100   17     20.5  
      9,281   9,486   9,690   204     2.2  

Main R&D projects

In 2010 overall expenditure in R&D amounted to approximately euro 98 million, excluding general and administrative expenses. A total of 23 new patents applications were filed. Below are outlined the main R&D results achieved in 2010 with an impact on the Division’s strategic results.

Advanced exploration techniques
- Reverse Time Migration (RTM): Emerging technology for the processing of seismic data in depth aimed at reconstructing the image of highly complex underground areas. In 2010 the proprietary version has been successfully applied for the first time to an exploration project in Angola, allowing to identify new oil bearing structures that had not been visible with conventional tools.

  - Depth Velocity Analysis (DVA): Proprietary technology based on calculations on speed data from seismic prospecting for visualizing underground areas. In 2010 it has been further developed and successfully applied to all seismic processing projects in exploration projects.
- Basin simulation (e-simbaTM): This proprietary package contains about 20 integrated software items for assessing the amount and type of hydrocarbons potentially trapped. In 2010 a few functions of have been developed and have been applied in about 30 research project in Countries such as Venezuela, Ghana, Mozambique, Poland Australia, Angola and Congo, allowing a better probabilistic assessment of mineral potential.

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Drilling and completion technologies
- Extended reach drilling: Proprietary technology and equipment (Eni continuous circulation device, e-cdTM and aluminium rods) have been used to drill wells in China and Alaska. In China costs were reduced by 50% as compared to earlier works.
- Innovative technologies to improve drilling safety: A portfolio of projects for increasing drilling safety reached an advanced stage with the in-field testing of special surface valves to be integrated in the proprietary equipment for an optimal control of drilling (e-cdTM). An innovative system for blow-out control within the well (downhole blow-out isolation packer) has also been tested. In 2010 Eni continued the development of the Dual ROV assisted top kill system that provides an efficient technique for blow-outs in deepwater wells. The system will be validated in the sea in 2011.

Technologies for field characterization and increase in recovery rates
- Polymer enhanced water injection: The design phase has been completed for the implementation of the project of polymer enhanced water injection in a well in Egypt. The studies performed suggest an approximately 3% increase in the recovery factor (with reference to original oil in place). The start-up of Enhanced Oil Recovery is scheduled in 2011.
- Bright Water Injection: This emerging technology is based on an additive that is injected in the ground and selectively blocks the rock parts where water is present, thus potentially increasing the extraction of crude from mature fields. It has been applied in 2010 in two fields in North Africa with positive results and further applications in Congo are scheduled for 2011.
- Tar recovery from tar sands: A mixed water-solvent process for obtaining high recovery rates of tar from tar sands (>90% in weight as compared to tar contained in sands) has been developed and applied to different types of sand. A concept design study has been completed for facilities in a pilot plant for the testing of in situ

  recovery techniques. Detailed engineering is scheduled in 2011.
- EOR with acoustic stimulation: This process is based on inputting sound waves into a field through a mechanical lifting system designed for this purpose. In 2010 field tests in Egypt were made in order to assess the potential of this well known but little tested technology in controlled conditions. Early results indicated a positive effect on oil production in the mature field where the test was made.

Marketing of marginal gas resources
- Gas to liquids (GtL): In 2010 the industrial development of this proprietary technology has been completed. Performance data acquired in operation and properly engineered supported an economic assessment and improved profitability.
- Enhanced Gas Recovery with CO2 (EGR): In 2010 various alternatives for production, treatment and reinjection of CO2 in the Palino Candela field have been tested. Aim of the test was to compare innovative and traditional technologies
- Compressed Natural Gas (CNG): Within the field of projects for the monetization of gas and associated gas, various studies have been performed on the technical and economic feasibility of compressed gas transport on vessels for onshore and offshore development projects.

Conversion of heavy crude and heavy fractions into lighter products (oil upgrading)
- Eni Slurry Technology (EST): The EST proprietary process consists in the conversion of heavy crudes and fractions into middle distillates for vehicles. In 2010, in addition to the upgrading of feasibility studies in Venezuela, as an implementation of the Memorandum of Understanding signed with PDVSA, Eni agreed to projects of technical cooperation aimed at developing a customized basic on the Zuata crude including elements of Eni’s proprietary technologies such as EST and HDHPlus.

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Key performance/sustainability indicators       2008   2009   2010
Employee injury frequency rate   (No. of accidents per million hours worked)   5.30   3.85   3.74
Net sales from operations (a)   (euro million)   37,062   30,447   29,576
Operating profit       4,030   3,687   2,896
Adjusted operating profit       3,564   3,901   3,119
- Market       1,309   1,721   733
- Regulated businesses in Italy (b)       1,732   1,796   2,043
- International transport       523   384   343
Adjusted net profit       2,648   2,916   2,558
EBITDA pro-forma adjusted       4,310   4,403   3,853
- Market       2,271   2,392   1,670
- Regulated businesses in Italy       1,284   1,345   1,486
- International transport       755   666   697
Capital expenditures       2,058   1,686   1,685
Adjusted capital employed, net at year end       22,273   25,024   27,270
Adjusted ROACE   (%)   12.2   12.3   9.8
Worldwide gas sales (c)   (bcm)   104.23   103.72   97.06
LNG sales (d)       12.0   12.9   15.0
Customers in Italy   (million)   6.63   6.88   6.88
Gas volumes transported in Italy   (bcm)   85.64   76.90   83.32
Electricity sold   (TWh)   29.93   33.96   39.54
Employees at year end   (units)   11,692   11,404   11,245
Direct GHG emissions   (mmtonnes CO2 eq)   14.60   14.60   15.79
Customer satisfaction index   (likert scale)   7.3   7.8   7.7
(a) i Before elimination of intragroup sales.
(b) i From January 1, 2010, amortization and depreciation in the transportation business segment were determined taking into account an increase in the useful life of pipelines (from 40 to 50 years), which was revised recently by the Authority for Electricity and Gas for tariff purposes. Taking into account the ways of recognizing tariff components linked to new amortization and depreciation, the Company decided to adjust the useful life of these assets in line with the conventional tariff duration. The impact on operating results in 2010 was euro 31 million.
(c) i Includes volumes marketed by the Exploration & Production Division of 5.65 bcm (6.00 and 6.17 bcm in 2008 and 2009, respectively), of which 2.33 bcm in Europe (3.36 and 2.57 bcm in 2008 and 2009, respectively) and 3.32 bcm in the Gulf of Mexico (2.64 and 3.60 bcm in 2008 and 2009, respectively).
(d) i Refers to LNG sales of the G&P Division (included in worldwide gas sales) and the E&P Division.

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France
› In December 2010, Eni increased its share in Altergaz, a company marketing natural gas in France to retail and middle market clients, to 55.2%, as founding partners of the company exercised a put option on a 15% stake. Eni now controls the entity.
 

Brazil: divestment of interest in Gas Brasiliano Distribuidora
› In May 2010, Eni signed a preliminary agreement with an affiliate of Petrobras for the divestment of its 100% interest in Gas Brasiliano Distribuidora, a company that markets and distributes gas in an area of the São Paulo state, Brazil. The completion of the transaction is subject to approval of the relevant Brazilian authorities.


Sale of 25% of the share capital of GreenStream BV
› In April 2010, Eni sold to NOC (Libyan National Oil Corporation) a 25% stake in the share capital and the control of GreenStream BV, the Company owning and managing the gas pipeline for importing to Italy natural gas produced in Libya.


New pricing and risk management model
› Against the changed backdrop of the natural gas market, in 2010 Eni implemented new pricing and risk management strategies to manage economic margins and to optimize asset value (supply contracts, client base, capacity).


Divestment of international pipelines
› Procedures for the divestment of Eni’s interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas transport pipelines are progressing. The divestment is part of the commitments presented by Eni to the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market ascribed to Eni without the ascertainment of any illicit behavior and consequently without imposition of any fines or sanctions. The Commission accepted Eni’s commitments as of September 29, 2010.


Financial results
› In 2010, adjusted net profit was euro 2,558 million, down 12.3% from 2009 due to a sharply lower operating performance of the Marketing business as a result of shrinking marketing margins and volume losses in Italy. These lower results were partly offset by a robust operating performance delivered by the Regulated businesses in Italy.
› Worldwide gas sales: considering risks associated with the natural gas market scenario in 2011 depending on the evolution of the Libyan crisis (see "Outlook" page 92), in the medium term Eni expects to increase natural gas sales in Italy and in European target markets with a 5% average annual growth rate. The achievement of this target will be supported by strengthening the Company’s leadership on the European market, marketing actions intended to strengthen the customer base in the domestic market and renegotiating the Company’s long-term gas supply contracts.
› Return on average capital employed (ROACE) on an adjusted basis was 9.8% (12.3% in 2009).
› Capital expenditures totaled euro 1.685 million and mainly related to the development and upgrading of Eni’s transport and distribution networks in Italy, the upgrading of storage capacity and the ongoing plan for improving power generation efficiency standards.


Operating results
› In 2010, sales of natural gas were 97.06 bcm, down 6.66 bcm or 6.4%, mainly due to unfavorable trends on the Italian market.
This decline was driven by lower sales recorded in the power generation business, as clients opted to directly purchase gas on the marketplace, while lower sales to industrial customers and wholesalers were caused by increased competitive pressure fuelled by oversupply and weak demand. These negatives were offset by organic growth in some European markets.
› Electricity volumes sold were 39.54 TWh, increasing by 5.58 TWh, or 16.4%, from 2009.
› Natural gas volumes transported on the Italian network were 83.32 bcm, up 8.3% from 2009.

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Marketing

Natural gas

Supply of natural gas
In 2010, Eni’s consolidated subsidiaries supplied 82.49 bcm of natural gas, representing a decrease of 6.16 bcm, or 6.9% from

  2009. Gas volumes supplied outside Italy (75.20 bcm from consolidated companies), imported in Italy or sold outside Italy, represented approximately 92% of total supplies, a decrease of 6.59 bcm, or 8.1%, from 2009, mainly reflecting a decline in natural gas sales. Lower volumes were purchased from Russia (down 7.73 bcm), where Eni reduced its off-takes, in particular of volumes directed to Italy, from the Netherlands (down 1.57 bcm), and from Norway (down 1.17 bcm) also due to the impact of the accident occurred at the Transitgas import pipeline in August 2010. In 2010 increases were recorded in gas purchases from Algeria (up 2.41 bcm) and from the UK (up 1.08 bcm), as well as in LNG availability.
Supplies in Italy (7.29 bcm) increased by 0.43 bcm from 2009, or 6.3%, also due to higher domestic production.
In 2010, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 bcm); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2010 these two fields supplied 2.5 bcm net to Eni; (iii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.6 bcm); and (iv) other European areas (Croatia with 0.4 bcm).
Considering also direct sales of the Exploration & Production Division in Europe and in the Gulf of Mexico and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 20 bcm representing 21% of total volumes available for sale.

 

Supply of natural gas   (bcm)   2008     2009     2010     Change     % Ch.  
ITALY       8.00     6.86     7.29     0.43     6.3  
Russia       22.91     22.02     14.29     (7.73 )   (35.1 )
Algeria (including LNG)       19.22     13.82     16.23     2.41     17.4  
Libya       9.87     9.14     9.36     0.22     2.4  
Netherlands       9.83     11.73     10.16     (1.57 )   (13.4 )
Norway       6.97     12.65     11.48     (1.17 )   (9.2 )
United Kingdom       3.12     3.06     4.14     1.08     35.3  
Hungary       2.84     0.63     0.66     0.03     4.8  
Qatar (LNG)       0.71     2.91     2.90     (0.01 )   (0.3 )
Other supplies of natural gas       4.07     4.49     4.42     (0.07 )   (1.6 )
Other supplies of LNG       2.11     1.34     1.56     0.22     16.4  
OUTSIDE ITALY       81.65     81.79     75.20     (6.59 )   (8.1 )
Total supplies of Eni’s consolidated subsidiaries       89.65     88.65     82.49     (6.16 )   (6.9 )
Offtake from (input to) storage       (0.08 )   1.25     (0.20 )   (1.45 )   ..  
Network losses, measurement differences and other changes       (0.25 )   (0.30 )   (0.11 )   0.19     63.3  
Available for sale by Eni’s consolidated subsidiaries       89.32     89.60     82.18     (7.42 )   (8.3 )
Available for sale by Eni’s affiliates       8.91     7.95     9.23     1.28     16.1  
E&P volumes       6.00     6.17     5.65     (0.52 )   (8.4 )
TOTAL AVAILABLE FOR SALE       104.23     103.72     97.06     (6.66 )   (6.4 )

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Sales of natural gas
In 2010, sales of natural gas were 97.06 bcm, down 6.66 bcm or 6.4%, mainly due to unfavorable trends on the Italian market. Sales included Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico.
Sales volumes on the Italian market declined by 5.75 bcm, or

  14.4%, to 34.29 bcm. The decline was driven by lower sales recorded in the power generation business (down 5.64 bcm), as clients opted to directly purchase gas on the marketplace. Lower sales to industrial customers (down 1.17 bcm) and wholesalers (down 1.08 bcm) were caused by increased competitive pressure fuelled by oversupply and weak demand. Sales on the Italian exchange for gas and spot markets increased by 2.28 bcm, while sales volumes to the residential sector (6.39 bcm, up 0.09 bcm) were nearly unchanged.
International sales were down 0.91 bcm, or 1.4%, to 62.77 bcm, due to a decline by 2.04 bcm (down 19.5%) of sales to importers in Italy related to oversupply on the Italian market.
Despite strong competitive pressures, sales on target markets in Europe showed a positive trend, increasing by approximately 1 bcm, or 2.5%, to 46.08 bcm. The main drivers behind the increase were organic growth achieved in France (up 1.18 bcm due to organic growth), Northern Europe (including the UK, up 0.91 bcm), Germany/Austria (up 0.31 bcm) and the Iberian Peninsula (up 0.30 bcm). Declines were recorded in Turkey (down 0.84 bcm), Belgium (down 0.80 bcm) and Hungary (down 0.22 bcm).
Sales to markets outside Europe (2.60 bcm) increased by 0.54 bcm, or 26.2%, from 2009.
E&P sales in Europe and in the United States (5.65 bcm) declined by 0.52 bcm.

 

Gas sales by market   (bcm)   2008     2009     2010     Change     % Ch.  
ITALY       52.87     40.04     34.29     (5.75 )   (14.4 )
Wholesalers       7.52     5.92     4.84     (1.08 )   (18.2 )
Gas release       3.28     1.30     0.68     (0.62 )   (47.7 )
Italian gas exchange and spot markets       1.89     2.37     4.65     2.28     96.2  
Industries       9.59     7.58     6.41     (1.17 )   (15.4 )
Medium-sized enterprises and services       1.05     1.08     1.09     0.01     0.9  
Power generation       17.69     9.68     4.04     (5.64 )   (58.3 )
Residential       6.22     6.30     6.39     0.09     1.4  
Own consumption       5.63     5.81     6.19     0.38     6.5  
INTERNATIONAL SALES       51.36     63.68     62.77     (0.91 )   (1.4 )
Rest of Europe       43.03     55.45     54.52     (0.93 )   (1.7 )
Importers in Italy       11.25     10.48     8.44     (2.04 )   (19.5 )
European markets       31.78     44.97     46.08     1.11     2.5  
Iberian Peninsula       7.44     6.81     7.11     0.30     4.4  
Germany - Austria       5.29     5.36     5.67     0.31     5.8  
Belgium       5     14.86     14.06     (0.80 )   (5.4 )
Hungary       2.82     2.58     2.36     (0.22 )   (8.5 )
Northern Europe       3.21     4.31     5.22     0.91     21.1  
Turkey       4.93     4.79     3.95     (0.84 )   (17.5 )
France       2.66     4.91     6.09     1.18     24.0  
Other       0.86     1.35     1.62     0.27     20.0  
Extra European markets       2.33     2.06     2.60     0.54     26.2  
E&P in Europe and in the Gulf of Mexico       6.00     6.17     5.65     (0.52 )   (8.4 )
WORLDWIDE GAS SALES       104.23     103.72     97.06     (6.66 )   (6.4 )

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Gas sales by entity   (bcm)   2008     2009     2010     Change     % Ch.  
Total sales of subsidiaries       89.32     89.60     82.00     (7.60 )   (8.5 )
Italy (including own consumption)       52.82     40.04     34.23     (5.81 )   (14.5 )
Rest of Europe       35.61     48.65     46.74     (1.91 )   (3.9 )
Outside Europe       0.89     0.91     1.03     0.12     13.2  
Total sales of Eni’s affiliates (net to Eni)       8.91     7.95     9.41     1.46     18.4  
Italy       0.05     -     0.06     0.06        
Rest of Europe       7.42     6.80     7.78     0.98     14.4  
Outside Europe       1.44     1.15     1.57     0.42     36.5  
E&P in Europe and in the Gulf of Mexico       6.00     6.17     5.65     (0.52 )   (8.4 )
WORLDWIDE GAS SALES       104.23     103.72     97.06     (6.66 )   (6.4 )

 

LNG
In 2010, LNG sales (15 bcm) increased by 2.1 bcm from 2009, up 16.3%, mainly reflecting higher volumes sold by the Gas & Power
  i
segment (11.2 bcm, included in worldwide gas sales) that increased by 1.4 bcm from 2009, due to increased marketing and trading activities.

 

LNG sales   (bcm)   2008     2009     2010     Change     % Ch.  
G&P sales       8.4     9.8     11.2     1.4     14.3  
Italy       0.3     0.1     0.2     0.1     100.0  
Rest of Europe       7.0     8.9     9.8     0.9     10.1  
Outside Europe       1.1     0.8     1.2     0.4     50.0  
E&P sales       3.6     3.1     3.8     0.7     22.6  
Terminals:                                  
Bontang (Indonesia)       0.7     0.8     0.7     (0.1 )   (12.5 )
Point Fortin (Trinidad & Tobago)       0.5     0.5     0.6     0.1     20.0  
Bonny (Nigeria)       2.0     1.4     2.2     0.8     57.1  
Darwin (Australia)       0.4     0.4     0.3     (0.1 )   (25.0 )
        12.0     12.9     15.0     2.1     16.3  

 

Power

Availability of electricity
Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and Bolgiano. In 2010, power generation was 25.63 TWh, up 1.54 TWh, or 6.4% from 2009, mainly due to higher production in particular at the Brindisi and Livorno plant.
As of December 31, 2010, installed operational capacity was 5.3 GW1 (5.3 GW in 2009).
Power availability in 2010 was supported by the growth in electricity trading activities (up 4.04 TWh, or 40.9%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices.
By 2014 Eni intends to complete its plan for expanding its power generation capacity, targeting an installed capacity of 5.7 GW.

  The power generation development plan mainly refers to: (i) revamping of the recently acquired Bolgiano plant (Eni 100%); (ii) upgrading of the Taranto plant (Eni 100%); and (iii) construction of a new biomass power generation plant at Eni’s Porto Torres industrial site which is currently under remediation.

Power sales
In 2010 electricity sales (39.54 TWh) were directed to the free market (70%), the Italian power exchange (18%), industrial sites (8%) and others (4%).
In 2010, electricity sales increased by 16.4% to 39.54 TWh, driven by a slight recovery in electricity demand and growth in the client base, and mainly related to higher sales on open-markets (up 2.74 TWh) benefiting from higher trading and higher volumes traded on the Italian power exchange (up 2.43 TWh).

 


(1) i Capacity available after completion of dismantling of obsolete plants.

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        2008     2009     2010     Change     % Ch.  
Purchases of natural gas   (mmcm)   4,530     4,790     5,154     364     7.6  
Purchases of other fuels   (ktoe)   560     569     547     (22 )   (3.9 )
Power generation   (TWh)   23.33     24.09     25.63     1.54     6.4  
Steam   (ktonnes)   10,584     10,048     10,983     935     9.3  
                                   
                                   
Availability of electricity   (TWh)   2008     2009     2010     Change     % Ch.  
Power generation       23.33     24.09     25.63     1.54     6.4  
Trading of electricity (a)       6.60     9.87     13.91     4.04     40.9  
        29.93     33.96     39.54     5.58     16.4  
                                   
Free market       22.89     24.74     27.48     2.74     11.1  
Italian Exchange for electricity       3.82     4.70     7.13     2.43     51.7  
Industrial plants       2.71     2.92     3.21     0.29     9.9  
Other (a)       0.51     1.6     1.72     0.12     7.5  
Power sales       29.93     33.96     39.54     5.58     16.4  
i i i
(a) i Includes positive and negative imbalances.

Regulated businesses in Italy

Transport and regasification of natural gas

Volumes of gas transported in Italy in 2010 were 83.32 bcm increasing by 6.42 bcm from 2009 due to higher gas deliveries related to a recovery in domestic demand.   In 2010, the LNG terminal in Panigaglia (La Spezia) regasified 1.98 bcm of natural gas (1.32 bcm in 2009).

 

Gas volumes transported (a) and regasified in Italy   (bcm)   2008     2009     2010     Change     % Ch.  
Gas volumes transported       85.64     76.90     83.32     6.42     8.3  
Gas volumes regasified       1.52     1.32     1.98     0.66     50.0  
i i i
(a) i Includes amounts destined to domestic storage.

Storage

In 2010, 7.59 bcm (down 1.12 bcm from 2009) were input to the Company’s storage deposits, while 8 bcm of gas were offtaken (up 0.19 bcm from 2009). Storage capacity amounted to 14.2 bcm, of   which 5 bcm were destined to strategic storage.
The share of modulation storage capacity used by third parties was about 71% (70% in 2009).

 

Storage       2008     2009     2010     Change     % Ch.  
Total storage capacity:   (bcm)   13.7     13.9     14.2     0.3     2.2  
- of which strategic storage       5.1     5.0     5.0              
- of which available storage       8.6     8.9     9.2     0.3     3.4  
Available capacity: share utilized by Eni   (%)   39     30     29     (1 )   (3.3 )
Total offtake from (input to) storage:   (bcm)   11.57     16.52     15.59     (0.93 )   (5.6 )
- input to storage       6.30     7.81     8.00     0.19     2.4  
- offtake from storage       5.27     8.71     7.59     (1.12 )   (12.9 )
Total customers   (No.)   48     56     60     4     7.1  

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Main development projects for 2010

Natural gas
France
In December 2010, Eni increased its share in Altergaz, a company marketing natural gas in France to retail and middle market clients, to 55.2%, as founding partners of the company exercised a put option on a 15% stake. Eni now controls the entity.

Divestment of interest in Gas Brasiliano Distribuidora
On May 27, 2010, Eni signed a preliminary agreement to divest its 100% interest in Gas Brasiliano Distribuidora, a company that markets and distributes natural gas in Brazil, to Petrobras Gàs, a fully owned subsidiary of Petróleo Brasileiro ("Petrobras"). Total cash consideration is expected to amount to approximately $250 million. The completion of the transaction is subject to the approval of the relevant Brazilian authorities.

LNG
USA - Cameron 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 regasification capacity of the Cameron terminal that was started up in the third quarter of 2009. 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, on March 3, 2011 Eni USA Gas Marketing Llc obtained from the American Department of Energy the authorization to export the LNG previously imported in the USA. This authorization will enhance operation flexibility, and will enable the company to exploit price differentials between American and European gas markets.
Start-up of the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant is expected in 2016.

South Stream
On June 18, 2010, Eni and Gazprom signed a Memorandum of Understanding to define terms and conditions for the French company EDF entering the South Stream project. As part of the agreement, EDF is expected to acquire an interest in the venture that is planning to build a new infrastructure to transport Russian gas across the Black Sea and Bulgaria to European markets.

Divestment of a 25% share capital interest in GreenStream BV
On April 27, 2010, Eni sold a 25% stake in the share capital of GreenStream BV to NOC (Libyan National Oil Corporation), the company owning and managing the gas pipeline for importing to Italy natural gas produced in Libya. Following the decrease of Eni’s shareholding in the company to 50% and implementation of renewed shareholders arrangements, Eni no longer controls the company and it has therefore been excluded from consolidation as of May 1, 2010. In 2010, GreenStream transported approximately 9 bcm of natural gas.

  GreenStream pipeline activity suspension
From February 22, 2011, in consideration of the current crisis in Libya, some oil&gas activities and supplies of natural gas through the GreenStream pipeline have been suspended. Assets were not damaged and the above-mentioned suspension does not affect Eni’s ability to fulfill its supply obligations with customers.

Regulatory framework

Legislative Decree No. 130 of August 13, 2010, containing measures for increasing competition in the natural gas market and transferring the ensuing benefits to final customers according to Article 30, lines 6 and 7, of Law July 23, 2009, No. 99
Implementing the provisions of Law 99/2009, on August 13, 2010, the Italian Council of Ministers approved a Legislative Decree for introducing thresholds of wholesale market shares for operators inputting natural gas in the Italian transport network which substitutes the existing antitrust ceilings introduced by Legislative Decree No. 164/2000 due to expire at the end of 2010, also identifying new measures for increasing competition in the natural gas market. The Decree provides that antitrust ceilings be calculated with reference to the market share of each operator, taking into account the amount of natural gas input into the national network, purchases in spot markets, and sales to importers in Italy made at national network entry points. Consequently, market shares will not be lower than the amount input to the network. Operators in the natural gas market will have to comply with a maximum share of 40% of domestic consumption. A mechanism of gas release at regulated prices is provided in case an operator fails to comply with the mandatory ceilings on the market share. This ceiling can be raised to 55% in case an operator commits itself to building new storage capacity in Italy for a total of 4 bcm within five years. Eni plans to build to new storage capacity and, has committed to: (i) allow third parties (such as industrial customers, groups of companies, consortia of final customers and power generation customers) participating in the construction of storage infrastructure either by means of direct investment or of long term contracts for storage services; (ii) bear the costs associated with giving to third parties 50% of the expected benefits of new capacities under conditions defined by the Ministry of Economic Development and the Authority for Electricity and Gas (AEEG).
The decree introduces measures for increasing competition in the natural gas market aiming at transferring the ensuing benefits to final customers, increasing storage capacity, supporting the security of supplies and enhancing flexibility in the gas system. To achieve this target, compensation to municipalities interested by the construction of new storage fields has been provided. Furthermore, in 2011 AEEG is expected to publish a new regulation concerning economic compensation mechanisms in the natural gas market.
Eni’s management is monitoring this area and evaluating any possible financial or economic impact associated with the proposed measures and their normative evolution.

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Resolution AR G/gas 89/10 - Change in the criteria for determining and upgrading tariffs applied to residential customers
On June 18, 2010, the Authority published a resolution, ARG/gas 89/10, applied to the October 1, 2010-September 30, 2011 thermal year, providing for a 7.5% reduction in the raw material cost component of those supplies in determining tariffs for residential users consuming less than 200,000 cm/y.
Considering the new calculation does not cover supply costs of an efficient portfolio of long-term contracts and considering the relevant impact on its consolidated accounts deriving from this new resolution, Eni’s management has appealed against the ARG/gas 89/10 resolution.
This appeal is part of an ongoing administrative litigation which follows the partial annulment of AEEG Resolution No. 79/07, pronounced by the Administrative Court of Lombardy in November 2010, with reference to the mechanism of indexation of the cost of raw material supplies to residential customers.

Negotiation Platform for gas trading
On March 18, 2010 the Ministry for Economic Development published a decree that implements a trading platform for natural gas starting from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform are entrusted to an independent operator, the GME (Gestore del Mercato Elettrico). On this platform are traded volumes of gas corresponding to the legal obligations on part of Italian importers and producers as per Law Decree No. 7/2007. Under these provisions, importers from non-European countries were expected to supply given amounts of gas (from 5% to 10% of total gas import) to the virtual exchange in order to receive permission to import, as well as volumes corresponding to royalties due by owners of mineral rights to the Italian state (and to the Regions Basilicata and Calabria). Eni is required to offer at that platform about 200 mmcm related to the residual obligation for volumes imported in thermal year October 1, 2008-September 30, 2009, and to the offer obligation for the October 1, 2009-September 30, 2010 thermal year, as well as approximately 215 mmcm related to royalties due for 2009 full year. Operators, also non-importers, are allowed to negotiate additional gas volumes over the compulsory amounts on the platform according to the supply rules determined by the Authority for Electricity and Gas. Since December 2010, the GME is also traders’ counterparty in

  transactions on spot natural gas market (divided into day-ahead market and intraday market).

European Directive No. 2009/73/EC of the European Parliament and Council on common regulations for the internal natural gas market
On July 13, 2009, European Directive No. 2009/73/EC on the regulation of the internal natural gas market was issued. Member states are expected to implement it in their legislation by March 3, 2011, and to choose one of two options for guaranteeing the independence of transport companies.
The two options provided are:
(i) Separation of ownership under two alternative modes:
- Ownership Unbundling (OU): the company that owns the networks and manages transport activities is unbundled from its integrated parent company that will retain supply/production and sale activities;
- Independent System Operator (ISO): the vertically integrated company retains ownership of the networks but confers their management to a third independent party.
(ii) Strengthened functional separation:
- Independent Transmission Operator (ITO): the vertically integrated company retains control of the company that manages transport activities and owns transport networks, provided the vertically integrated company refrains from interfering in the decision making process of the controlled carrier company.
On March 3, 2010, the Italian Council of Ministers presented a draft Legislative Decree to implement Directive 2009/73/EC. Among the possible options, the Decree provides for the adoption of the ITO model by Snam Rete Gas before March 3, 2012.

Capital expenditures

In 2010, capital expenditures in the Gas & Power segment totaled euro 1,685 million and mainly related to: (i) developing and upgrading Eni’s transport network in Italy (euro 842 million); (ii) developing and upgrading Eni’s distribution network in Italy (euro 328 million); (iii) developing and upgrading Eni’s storage capacity in Italy (euro 250 million); (iv) completion of construction of the combined cycle power plants at the Ferrara site, upgrading and other initiatives to improve flexibility (euro 115 million); (v) the upgrading plan of international pipelines (euro 17 million).

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Capital expenditures (euro million)   2008   2009   2010   Change     % Ch.  
Italy     1,750   1,564   1,575   11     0.7  
Outside Italy     308   122   110   (12 )   (9.8 )
      2,058   1,686   1,685   (1 )   (0.1 )
Marketing     198   175   248   73     41.7  
Marketing     91   102   133   31     30.4  
Italy     16   12   40   28     233.3  
Outside Italy     75   90   93   3     3.3  
Power generation     107   73   115   42     57.5  
Regulated businesses in Italy     1,627   1,479   1,420   (59 )   (4.0 )
Transport     1,130   919   842   (77 )   (8.4 )
Distribution     233   278   328   50     18.0  
Storage     264   282   250   (32 )   (11.3 )
International transport     233   32   17   (15 )   (46.9 )
      2,058   1,686   1,685   (1 )   (0.1 )

Main R&D projects

In 2010 overall expenditure in R&D amounted to approximately euro 2 million, excluding general and administrative expenses. A total of 2 new patents applications were filed. Below are outlined the main R&D results achieved in 2010 with an impact on the Division’s strategic results.

TPI - Intermediate Pressure Transport
Eni is examining the potential and maturity of this transport option (pressure over 100 bar high grade steel pipes). The TPI project was started in 2008 in cooperation with various partners, such as Centro Sviluppo Materiali (CSM). In 2009 welding and

  tests on a real scale simulating operating conditions have been started. The process continued in 2010 and a patent application has been filed on a new welding process.

Kassandra Meteo Project
Since 2009 the Gas & Power Division has been developing a new weather forecast process in cooperation with Centro Meteo Operations Italia (MOPI) to explore the trends of temperatures at regional scale and by seasons. The project can be applied to the Italian and European natural gas market where Eni operates. A patent application was filed in 2010 on this long-medium term weather forecasting method.

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Key performance/sustainability indicators       2008     2009     2010  
Employee injury frequency rate   (No. of accidents per million hours worked)   2.88     3.18     1.77  
Net sales from operations (a)   (euro million)   45,017     31,769     43,190  
Operating profit       (988 )   (102 )   149  
Adjusted operating profit (b)       580     (357 )   (171 )
Adjusted net profit       521     (197 )   (49 )
Capital expenditures       965     635     711  
Adjusted capital employed, net at year end       8,260     7,560     7,859  
Adjusted ROACE   (%)   6.5     (2.6 )   (0.6 )
Refinery throughputs on own account   (mmtonnes)   35.84     34.55     34.80  
Conversion index   (%)   58     60     61  
Balanced capacity of refineries   (kbbl/d)   737     747     757  
Retail sales of petroleum products in Europe   (mmtonnes)   12.03     12.02     11.73  
Service stations in Europe at year end   (units)   5,956     5,986     6,167  
Average throughput per service station in Europe   (kliters)   2,502     2,477     2,353  
Employees at year end   (units)   8,327     8,166     8,022  
Direct GHG emissions   (mmtonnes CO2 eq)   7.74     7.29     7.76  
SO2 emissions   (ktonnes)   23.18     21.98     27.14  
Customer satisfaction index   (likert scale)   8.14     7.93     7.90  
(a) i Before elimination of intragroup sales.
(b) i From January 1, 2010, management has reviewed the residual useful lives of refineries and related facilities due to a change in the expected pattern of consumption of the expected future economic benefit embodied in those assets. In doing so, the Company has aligned with practices prevailing among integrated oil companies, particularly the European companies. Management’s conclusions have been supported by an independent technical review. The impact on 2010 operating profit has been euro 76 million.
i
Portfolio developments and main projects
› In 2010, the acquisition of downstream activities in Austria was finalized. It includes a retail network, wholesale activities, as well as commercial assets in the aviation business and related logistic and storage activities.
› The re-branding of Eni’s service stations and the upgrading of Eni’s retail network are ongoing. In 2010, 463 service stations in Italy were re-branded to the "eni" brand, corresponding to approximately 10% of the retail network, with priority awarded to high throughput service stations with non-oil activities.
 

Financial results
› In 2010, the Refining & Marketing Division reported a substantial recovery from 2009 with adjusted net loss improving from euro -197 million to euro -49 million due to more positive trends in the refining business, an improved performance of the marketing business and

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increased earnings reported by equity-accounted subsidiaries.
› Return on average capital employed on an adjusted basis was a negative 0.6% (-2.6% in 2009).
› Capital expenditures totaled euro 711 million and related mainly to projects designed to improve the conversion rate and flexibility of refineries, logistic assets, the upgrade of the refined product retail network in Italy and in the rest of Europe.
› In the medium term, notwithstanding persisting negative trends in the market scenario, management plans to recover profitability and to generate positive free cash flows from 2011. Eni intends to focus on efficiency improvements, optimization of refinery processes, selection of capital projects, and, in marketing, increase retail sales and market share in Italy.
 

Operating results
› In 2010, refining throughputs were 34.80 mmtonnes, up 0.7% from 2009. Higher volumes were processed in Italy (up 0.5%) at the Livorno, Gela and Taranto plants as the trading environment improved from a year ago and optimization of refining cycles was implemented. In addition, higher volumes were processed due to the coming on stream of a new hydro-cracking unit in Taranto and lower planned standstills affected the partially-owned Milazzo refinery. These effects were partly offset by the termination of a process contract on a third-party refinery. Eni’s refining throughputs outside Italy increased by 1.7% supported by higher throughput in the Czech Republic as a consequence of increased margins and demand recovery.
› Retail sales in Italy (8.63 mmtonnes for the full year) decreased by approximately 400 ktonnes, down 4.4%, driven by lower demand which mainly impacted gasoline and, to a lesser extent gasoil, and rising competitive pressure as well as demand price elasticity. Eni’s a market share for 2010 averaged 30.4%, down 1.1 percentage points from 2009 (31.5%).
› Retail sales in the rest of Europe (3.10 mmtonnes) increased by 3.7% from 2009. The increase was driven by volume additions in Austria, reflecting the finalization of the purchase of service stations in the second half of 2010, and by enhanced performance in certain Eastern European Countries, Germany and France.
› In 2010, the offer of products and non-oil services improved in Eni’s retail network in Italy, due to the opening/restructuring of 257 outlets under the new "eni cafè" and "eni shop" format, and 50 car wash units.

Supply and trading

In 2010, a total of 68.25 mmtonnes of crude were purchased by the Refining & Marketing Division (67.40 mmtonnes in 2009), of which 30.14 mmtonnes from Eni’s Exploration & Production Division. Volumes amounting to 20.95 mmtonnes were purchased on the spot market, while 17.16 mmtonnes were purchased under long-term supply contracts with producing Countries. Approximately 25% of crude purchased in 2010 came from Russia, 22% from West Africa, 12% from the North Sea, 12% from the Middle East, 11% from North   Africa, 5% from Italy, and 13% from other areas.
In 2010 some 36.17 mmtonnes of crude purchased were marketed, (up of approximately 60 ktonnes, or 0.2%, from 2009). In addition, 3.05 mmtonnes of intermediate products were purchased (2.92 mmtonnes in 2009) to be used as feedstock in conversion plants and 15.28 mmtonnes of refined products (13.98 mmtonnes in 2009) were purchased to be sold on markets outside Italy (10.72 mmtonnes) and on the domestic market (4.56 mmtonnes) as a complement to available production.

 

Purchases (mmtonnes)   2008     2009     2010     Change     % Ch.  
Equity crude oil                                
Eni’s production outside Italy     26.14     29.84     26.90     (2.94 )   (9.9 )
Eni’s production in Italy     3.57     2.91     3.24     0.33     11.3  
      29.71     32.75     30.14     (2.61 )   (8.0 )
Other crude oil                                
Purchases on spot markets     12.09     14.94     20.95     6.01     40.2  
Purchases under long-term contracts     16.11     19.71     17.16     (2.55 )   (12.9 )
      28.20     34.65     38.11     3.46     10.0  
Total crude oil purchases     57.91     67.40     68.25     0.85     1.3  
Purchases of intermediate products     3.39     2.92     3.05     0.13     4.5  
Purchases of products     17.42     13.98     15.28     1.30     9.3  
TOTAL PURCHASES     78.72     84.30     86.58     2.28     2.7  
Consumption for power generation     (1.00 )   (0.96 )   (0.92 )   0.04     4.2  
Other changes (a)     (1.04 )   (1.64 )   (2.69 )   (1.05 )   (64.0 )
      76.68     81.70     82.97     1.27     1.6  
i i i
(a) i Includes change in inventories, decrease in transportation, consumption and losses.

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Refining

Availability of refined products (mmtonnes)   2008     2009     2010     Change     % Ch.  
ITALY                                
At wholly-owned refineries     25.59     24.02     25.70     1.68     7.0  
Less input on account of third parties     (1.37 )   (0.49 )   (0.50 )   (0.01 )   (2.0 )
At affiliated refineries     6.17     5.87     4.36     (1.51 )   (25.7 )
Refinery throughputs on own account     30.39     29.40     29.56     0.16     0.5  
Consumption and losses     (1.61 )   (1.60 )   (1.69 )   (0.09 )   (5.6 )
Products available for sale     28.78     27.80     27.87     0.07     0.3  
Purchases of refined products and change in inventories     2.56     3.73     4.24     0.51     13.7  
Products transferred to operations outside Italy     (1.42 )   (3.89 )   (4.18 )   (0.29 )   (7.5 )
Consumption for power generation     (1.00 )   (0.96 )   (0.92 )   0.04     4.2  
Sales of products     28.92     26.68     27.01     0.33     1.2  
OUTSIDE ITALY                                
Refinery throughputs on own account     5.45     5.15     5.24     0.09     1.7  
Consumption and losses     (0.25 )   (0.25 )   (0.24 )   0.01     4.0  
Products available for sale     5.20     4.90     5.00     0.10     2.0  
Purchases of refined products and change in inventories     15.14     10.12     10.61     0.49     4.8  
Products transferred from Italian operations     1.42     3.89     4.18     0.29     7.5  
Sales of products     21.76     18.91     19.79     0.88     4.7  
Refinery throughputs on own account     35.84     34.55     34.80     0.25     0.7  
of which: refinery throughputs of equity crude on own account     6.98     5.11     5.02     (0.09 )   (1.8 )
Total sales of refined products     50.68     45.59     46.80     1.21     2.7  
Crude oil sales     26.00     36.11     36.17     0.06     0.2  
TOTAL SALES     76.68     81.70     82.97     1.27     1.6  

 

In 2010, refining throughputs were 34.80 mmtonnes, up 0.7% from 2009.
Higher volumes of approximately 160 ktonnes were processed in Italy (up 0.5% from 2009) mainly due to a better performance at the Livorno, Gela and Taranto plants as the trading environment improved from a year ago and optimization of refining cycles was implemented. In addition higher volumes were processed due to the coming on stream of a new hydro-cracking unit in Taranto and lower planned standstills affected the partially-owned Milazzo refinery. These effects were partly offset by the termination of a process contract on the Saras third-party refinery (down 1,966 ktonnes). Eni’s refining throughputs outside Italy increased by 1.7% supported by higher refinery throughput in the Czech Republic as a consequence of increased margins and demand recovery.
Total throughputs in wholly-owned refineries were 25.70 mmtonnes, up by approximately 90 mmtonnes (or 1.7%) from 2009, reflecting an improved refinery utilization rate which reached 91%. This increase reflects feedstock integration in refinery cycles and improved throughput margins, in particular for lubricants.
Approximately 15.8% of volumes of processed crude was supplied by Eni’s Exploration & Production segment (16.3% in
  2009) representing a 0.5 percentage point decrease from 2009, corresponding to a lower volume of approximately 90 ktonnes.

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Marketing of refined products

In 2010, sales volumes of refined products (46.80 mmtonnes) were up of 1.21 mmtonnes from 2009, or 2.7%, mainly due to   higher volumes sold to oil companies and traders in Italy and outside Italy.

 

Product sales in Italy and outside Italy by market (mmtonnes)   2008   2009   2010   Change     % Ch.  
Retail     8.81   9.03   8.63   (0.40 )   (4.4 )
Wholesale     11.15   9.56   9.45   (0.11 )   (1.2 )
Petrochemicals     1.70   1.33   1.72   0.39     29.3  
Other sales     7.26   6.76   7.21   0.45     6.7  
Sales in Italy     28.92   26.68   27.01   0.33     1.2  
Retail rest of Europe     3.22   2.99   3.10   0.11     3.7  
Wholesale rest of Europe     3.94   3.66   3.88   0.22     6.0  
Wholesale outside Italy     0.56   0.41   0.42   0.01     2.4  
Other sales     12.52   11.85   12.39   0.54     4.6  
Sales outside Italy     20.24   18.91   19.79   0.88     4.7  
      49.16   45.59   46.80   1.21     2.7  
Iberian Peninsula     1.52                    
of which:                          
     Retail     0.64                    
     Wholesale     0.88                    
TOTAL SALES     50.68   45.59   46.80   1.21     2.7  

 

Retail sales in Italy
In 2010, retail sales in Italy of 8.63 mmtonnes decreased by approximately 400 ktonnes, down 4.4% driven by lower demand which mainly impacted gasoline and, to a lesser extent gasoil, reflecting a decline in domestic fuel demand, as well as rising competitive pressure and price elasticity. Average gasoline and gasoil throughput (2,322 kliters) decreased by approximately 160 kliters from 2009. Eni’s retail market share for 2010 was 30.4%, down 1.1 percentage point from 2009 (31.5%).
At December 31, 2010, Eni’s retail network in Italy consisted of 4,542 service stations, 68 more than at December 31, 2009 (4,447 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (74 units), the opening of new service stations (11 units), partly offset by the closing of service stations with low throughput (13 units) and the release of 4 service stations under highway concession.
In 2010, also fuel sales of the Blu line – fuels with high performance and low environmental impact – recorded lower sales from 2009, reflecting weak domestic consumption. In particular, sales of BluDieselTech declined slightly from 2009,
  approximately amounting to 573 ktonnes (689 mmliters), and represented 10.3% of gasoil sales on Eni’s retail network. At December 31, 2010, service stations marketing BluDieselTech totaled 4,071 units (4,104 at 2009 year-end) covering approximately 90% of Eni’s network. Retail sales of BluSuper amounted to 70 ktonnes (approximately 94 mmliters), decreasing by approximately 12 ktonnes from 2009, and covered 2.6% of gasoline sales on Eni’s retail network (down 0.1% from a year ago).
At December 31, 2010, service stations marketing BluSuper totaled 2,672 units (2,679 at December 31, 2009), covering approximately 59% of Eni’s network.
In February 2010, in replacement of the previous promotional campaign "You&Agip", Eni launched the new "you&eni" loyalty points program, lasting 3 years.
As of December 31, 2010, the number of customers that actively used the card in the year amounted to approximately 5 million. The average number of cards active each month was approximately 2.8 million. Volumes of fuel marketed under this initiative represented approximately 40% of overall volumes marketed on Eni’s network.

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Retail and wholesales sales of refined products (mmtonnes)   2008   2009   2010   Change     % Ch.  
Italy     19.96   18.59   18.08   (0.51 )   (2.7 )
Retail sales     8.81   9.03   8.63   (0.40 )   (4.4 )
Gasoline     3.11   3.05   2.76   (0.29 )   (9.5 )
Gasoil     5.50   5.74   5.58   (0.16 )   (2.8 )
LPG     0.19   0.22   0.26   0.04     18.2  
Lubricants     0.01   0.02   0.03   0.01     50.0  
Wholesale sales     11.15   9.56   9.45   (0.11 )   (1.2 )
Gasoil     4.52   4.30   4.36   0.06     1.4  
Fuel Oil     0.85   0.72   0.44   (0.28 )   (38.9 )
LPG     0.38   0.35   0.33   (0.02 )   (5.7 )
Gasoline     0.15   0.12   0.16   0.04     33.3  
Lubricants     0.12   0.09   0.10   0.01     11.1  
Bunker     1.70   1.38   1.35   (0.03 )   (2.2 )
Other     3.43   2.60   2.71   0.11     4.2  
Outside Italy (retail+wholesale)     7.72   7.06   7.40   0.34     4.8  
Gasoline     2.12   1.89   1.85   (0.04 )   (2.1 )
Gasoil     3.80   3.54   3.95   0.41     11.6  
Jet fuel     0.47   0.35   0.40   0.05     14.3  
Fuel Oil     0.23   0.28   0.25   (0.03 )   (10.7 )
Lubricants     0.11   0.10   0.10   0.00     0.0  
LPG     0.52   0.50   0.49   (0.01 )   (2.0 )
Other     0.47   0.40   0.36   (0.04 )   (10.0 )
      27.68   25.65   25.48   (0.17 )   (0.7 )
Iberian Peninsula     1.52                    
TOTAL SALES     29.20   25.65   25.48   (0.17 )   (0.7 )

 

Retail sales in the Rest of Europe
In 2010 retail sales of refined products marketed in the rest of Europe (3.10 mmtonnes) were up 3.7% from 2009. The increase was driven by volume additions in Austria, reflecting the purchase of service stations, and by enhanced performance in Eastern Europe (particularly in Slovakia and Romania), as well as in Germany and France.

  At December 31, 2010, Eni’s retail network in the rest of Europe consisted of 1,625 units, an increase of 113 units from December 31, 2009 (1,512 service stations). The network evolution was as follows: (i) positive balance of acquisitions/releases of lease concessions (19 units) with positive changes in Austria and Hungary; (ii) purchased 114 service stations; (iii) opened 5 new outlets; and (iv) closed 25 low throughput service stations were.
Average throughput (2,441 kliters) slightly decreased from 2009 (2,461 kliters).

Wholesale and other sales
Wholesale sales in Italy (9.45 mmtonnes) decreased by approximately 110 ktonnes, down 1.2% from 2009, mainly due to a decline in domestic consumption (down 6.7%) in particular of fuel oil by industrial customers.
Eni’s wholesale market share for 2010 averaged 29.2%, up 1.6 percentage points from 2009 (27.6%).
Wholesale sales in the rest of Europe increased by 220 ktonnes, or 6%, to 3.88 mainly in Austria, reflecting recent acquisition of service stations, in France, due to higher bitumen sales, and in Germany, thanks to a large product availability and a recovery in consumption.
Supplies of feedstock to the petrochemical industry (1.72 mmtonnes) increased by approximately 390 ktonnes due to demand recovery.
Other sales (19.60 mmtonnes) increased by approximately 990 ktonnes, or 5.3%, mainly due to higher sales volumes to the cargo market and to oil companies.

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Capital expenditures

In 2010, capital expenditures in the Refining & Marketing Division amounted to euro 711 million and regarded mainly: (i) refining, supply and logistics in Italy (euro 446 million), with projects designed to improve the conversion rate and flexibility of refineries, in particular   the Sannazzaro and Taranto refineries, as well as expenditures on health, safety and environmental upgrades; (ii) upgrade of the refined product retail network in Italy and in the rest of Europe (euro 246 million). Expenditures on health, safety and the environment amounted to euro 143 million.

 

Capital expenditures (euro million)   2008   2009   2010   Change     % Ch.  
Italy     850   581   633   52     9.0  
Outside Italy     115   54   78   24     44.4  
      965   635   711   76     12.0  
Refinery, supply and logistics     630   436   446   10     2.3  
Italy     630   436   444   8     1.8  
Outside Italy             2   2        
Marketing     298   172   246   74     43.0  
Italy     183   118   170   52     44.1  
Outside Italy     115   54   76   22     40.7  
Other     37   27   19   (8 )   (29.6 )
      965   635   711   76     12.0  

 

Main R&D projects

In 2010 overall expenditure in R&D amounted to approximately euro 20 million, excluding general and administrative expenses. A total of 16 new patents applications were filed. Below are outlined the main R&D results achieved in 2010 with an impact on the Division’s strategic results.

Eni Slurry Technology (EST)
The EST proprietary technology is an innovative process for hydroconversion by means of a nanodispersed catalyst (slurry) and a peculiar process scheme to refine various kinds of heavy feedstock: residues from the distillation of heavy and extra-heavy crude (such as the ones from the Orinoco Belt in Venezuela) or non conventional products such as tar sands, characterized by high contents of sulphur, nitrogen, metals, asphaltenes and other pollutants that are hard to manage in conventional refineries. EST does not give rise to by-products and simply converts feedstocks into distillates. In 2010 testing continued mainly directed to validating the technology from the point of view of the upgrading performance and plant management, to the preparation of a customized basic on Zuata crude. The first industrial plant with a 23 kbbl/d capacity is under construction at the Sannazzaro refinery, with start-up scheduled for 2012.

Hydrogen SCT-CPO (Short Contact Time - Catalytic Partial Oxidation)
It is a reforming technology that can convert gaseous and liquid hydrocarbons (also derived from biomass) into synthetic gas

  (carbon monoxide and hydrogen). This technology can contribute to process intensification as it allows to produce synthetic gas and hydrogen using reactors up to 100 times smaller than those currently in use, with relevant savings. The development of this technology, that makes use of oxygen enriched air, has been completed and another version making use of pure oxygen is under development.

Nanomaterials
The use of structured nanomaterials is one of the key elements for innovation and intensification of processes because innovation thus obtained in materials is multiplied to the whole system. Projects are underway to study and enhance nanomaterials that could introduce radical improvements in conversion processes. The Dual Catalyst technology is based on nanocatalysts and its current tests could lead to breakthrough developments in EST, as it can increase productivity and quality of end products. The development of a bi-functional catalyst is underway that hydrogenates and desulphorates feesdtocks and increases the cracking rate and nitrogen removal. In the Flexible FCC (fluid catalytic cracking) line of products, new proprietary zeolite and zeolite-like materials have been developed for increasing the conversion of heavier fractions without increasing residues. This additive, associated to a new process scheme could change the gasoline/gasoil ratio in favor of the latter. In 2010 application testing continued and confirmed the results obtained so that scale up has started with the aim of finding the final formulation to be used in an industrial reactor. This application too is covered by a patent application and received the Eni Award for innovation.

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Key performance/sustainability indicators       2008     2009     2010  
Employee injury frequency rate   (No. of accidents per million hours worked)   2.57     2.34     1.54  
Net sales from operations (a)   (euro million)   6,303     4,203     6,141  
- Basic petrochemicals       3,060     1,832     2,833  
- Polymers       2,961     2,185     3,126  
- Other sales       282     186     182  
Operating profit       (845 )   (675 )   (86 )
Adjusted operating profit       (398 )   (426 )   (113 )
Adjusted net profit       (323 )   (340 )   (85 )
Capital expenditures       212     145     251  
Production   (ktonnes)   7,372     6,521     7,220  
Sales of petrochemical products       4,684     4,265     4,731  
Average plant utilization rate   (%)   68.6     65.4     72.9  
Employees at year end   (units)   6,274     6,068     5,972  
Direct GHG emissions   (mmtonnes CO2 eq)   4.90     4.63     4.64  
VOC emissions   (ktonnes)   3.61     3.83     4.63  
(a)   Before elimination of intragroup sales.

 

› In 2010, the petrochemical segment reported a reduction of adjusted net loss (euro 85 million, down euro 255 from 2009) due to a recovery in industrial demand and to stronger industry fundamentals.
› Sales of petrochemical products were 4,731 ktonnes, up 466 ktonnes from last year, or 10.9%, as a result of a recovery in demand from the very low levels of the same period of last year.
› Petrochemical production volumes were 7,220 ktonnes, increased by 699 ktonnes, or 10.7%, due to an increase in demand for petrochemical products in all business areas.

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Sales - production - prices

In 2010 sales of petrochemical products (4,731 ktonnes) increased by 466 ktonnes (or 10.9%) from 2009 as a result of a recovery in demand from the very low levels of last year and a limited supply of products in the first six months of the year.
Petrochemical production (7,220 ktonnes) increased by 699 ktonnes from 2009, or 10.7% in all business areas. The recovery in demand determined a production increase in all Eni’s main plants, in Italy and outside Italy, that last year required unexpected outages in order to avoid excess of stock. Nominal production capacity decreased by one percentage point from 2009 due to the

  closing of the styrene plant in Hythe. The average plant utilization rate, calculated on nominal capacity increased from 65.4% to 72.9% as a result of higher volumes produced, in particular in the Priolo, Brindisi and Porto Torres plants.
Average unit sale prices increased by 35.6% from the depressed levels registered in 2009. The most relevant increase was registered in the average price of olefins (up 48% on average) due to the positive impact of the oil price scenario (virgin naphtha prices increased by 41% due to an increase in demand while supply was low). Average unit prices of styrene and polyethylene increased on average by 30%, while elastomers achieved lower increases.

 

Product availability (ktonnes)   2008     2009     2010     Change     % Ch.  
Basic petrochemicals     5,110     4,350     4,860     510     11.7  
Polymers     2,262     2,171     2,360     189     8.7  
Production     7,372     6,521     7,220     699     10.7  
Consumption and losses     (3,539 )   (2,701 )   (2,912 )   (211 )   (7.8 )
Purchases and change in inventories     851     445     423     (22 )   (4.9 )
      4,684     4,265     4,731     466     10.9  

 

Business trends

Basic petrochemicals
Basic petrochemical revenues (euro 2,833 million) increased by euro 1,001 million (up 54.6%) from 2009 in all the main business segments due to the steep increase in average unit prices (olefins up 48%; intermediates and aromatics up more than 30%)as a result of the improved scenario and higher volumes sold (14% on average). In particular sales volumes of olefins increased by 17%, intermediates by 10%, while aromatics registered lower increases (up 8%) due to the decreases registered in xylene sales (down 5%). Basic petrochemical production (4,860 ktonnes) increased by 510 ktonnes from 2009 (up 11.7%) due to the recovery in the demand for monomers.

Polymers
Polymer revenues (euro 3,126 million) increased by euro 941 million from 2009 (up 43.1%) due to average unit prices increasing by 30%. Sales volumes increased on average by 8% (elastomers up 11%; styrene up 10%, polyethylene up 6%) due to positive trends in demand.
Polymer production (2,360 ktonnes) increased by 189 ktonnes from 2009 (up 8.7%) as a result of the recovery in production started in the first months of 2010 due to the recovery in the main end-markets (automotive, construction and packaging).
Production volumes of elastomers, and styrene increased on average by 10% from 2009 due to higher production of EPR, nytrilic rubbers, compact polystyrene and ABS. Polyethylene production registered a lower increase (up 7.7%) due to the maintenance shutdown of the Dunkerque plant.

  Capital expenditures

In 2010 capital expenditures amounted to euro 251 million (euro 145 million in 2009) and regarded mainly plant upgrades (euro 116 million), upkeeping (euro 59 million), energy recovery (euro 45 million), environmental protection, safety and environmental regulation compliance (euro 29 million).

Main R&D projects

In 2010 overall expenditure in R&D amounted to approximately euro 31 million, excluding general and administrative expenses.
A total of 10 new patent applications were filed. Below are outlined the main R&D results achieved in 2010 with an impact on the Division’s strategic results.

- Basic petrochemicals: Within the study of a new catalytic process for cumene oxidation, the unit operation for catalyst recovery has been consolidated, an operation essential for the economic sustainability of the whole process.

- Elastomers: A new grade of thermoplastic co-polymer has been industrially homologated to be used in adhesives with lower viscosity (remaining equal its adhesive/cohesive properties) leading to lower energy consumption in the formulation of the final adhesive. At a pilot scale, new hydrogenated styrene-butadiene co-polymers to be used as viscosity index improvers have been produced and are scheduled to be homologated by the reference customer. In the lab and pilot plant the advantage

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of using a new activator in the polymerization of terpolymers EPDM with vanadium based catalysts has been confirmed and provided higher yields, improved quality and lower consumption of chlorine in the production process.

- Polyethylene: The production of two new grades of LLDPE (linear low density polyethylene) continued with wide distribution of molecular weight and therefore improved processability and retention of basic mechanic properties. In a gas phase plant a new grade of LLDPE for rotomolding application with exenes has been produced entailing a significant improvement of certain basic properties (such as resistance to chemicals). New formulas have been developed for HDPE (high density

  polyethylene) to be used in rotomolding applications in the field of phytochemicals. In a high pressure tubular plant LLDPE products with higher density have been developed and led to improved optical properties.

- Styrenic polymers: A new formula of ABS (acrylonitryl-butadiene-styrene polymer) grade from continuous mass has been developed for injection moulding. This formula dramatically increases the mechanical properties of products adjusting their performance to products deriving from emulsions. This allows a relevant recovery in penetration into injection moulding. After the first industrial campaign, customers expressed their satisfaction.

 

 

 

 

 

 

 

 

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Key performance/sustainability indicators       2008   2009   2010
Employee injury frequency rate   (No. of accidents per million hours worked)   0.70   0.40   0.45
Net sales from operations (a)   (euro million)   9,176   9,664   10,581
Operating profit       1,045   881   1,302
Adjusted operating profit       1,041   1,120   1,326
Adjusted net profit       784   892   994
Capital expenditures       2,027   1,630   1,552
Adjusted ROACE   (%)   16.8   15.4   14.0
Orders acquired   (euro million)   13,860   9,917   12,935
Order backlog       19,105   18,730   20,505
Employees at year end   (units)   35,629   35,969   38,826
Direct GHG emissions   (mmtonnes CO2 eq)   1.34   1.29   1.18
(a)   Before elimination of intragroup sales.

 

› Adjusted net profit was euro 994 million, up euro 102 million from a year ago, or 11.4%, driven by an higher turnover.
› Adjusted operating profit was euro 1,302, up euro 421 million from a year ago, or 47.8%, due to an increase in project profitability and a higher turnover. A non recurring charge has been accounted for in the adjusted operating profit amounting to $30 million (or euro 24 million) reflecting the transaction with the Nigerian Government in relation with the investigation related to the TSKJ consortium. For further information see the paragraph "Legal Proceedings" in the Notes to the Consolidated Financial Statements.
› Return on average capital employed calculated on an adjusted basis was 14% in 2010 (15.4% in 2009).
› Orders acquired amounted to euro 12,935 million, up euro 3,018 million from 2009 (up 30.4%), in particular in onshore activity.
› Order backlog was euro 20,505 million at December 31, 2010 (euro 18,730 million at December 31, 2009), related in particular to projects in the Middle East (27%), North Africa (18%) and the Americas (16%).
› Capital expenditures amounted to euro 1,552 million, slightly lower than in 2009 (down euro 78 million, or 4.8%). The main projects related to the upgrade of the construction and drilling fleet.

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Activity for the year

Among the main orders acquired in 2010 were:
- EPC contracts on behalf of Abu Dhabi Gas Development for the construction of a gas processing plant (with a treatment capacity of 1 billion cubic feet per day of gas), a sulphur recovery unit and the related transporting facilities as part of the Shah Gas development program in the United Arab Emirates;
- an EPC contract on behalf of Husky Oil for the realization of the Central Processing Facilities designed for a total of 60,000 barrels per day of bitumen production for the first phase of the Sunrise Oil Sands project near Fort Murray, Alberta, Canada;
- an EPC contract on behalf of Kharafi National for the construction of Early Production Facilities, which will have an oil and gas treatment capacity of 150,000 barrels per day and a sulphur granulation plant, for the development of the Jurassic field located in northern Kuwait;

  - an EPC contract on behalf of Kuwait Oil Company for the construction of a booster station made up of three high and low-pressure gas trains to produce 234 million cubic feet a day of dry gas and 69,000 barrels per day of condensates, fed from the existing gathering centers in Western Kuwait;
- the extension of the "Kashagan Trunklines" and "Kashagan Piles and Flares" contracts on behalf of Agip KCO for the installation of the offshore facilities system relating to the experimental phase of the Kashagan field development program in Kazakhstan.
Orders acquired amounted to euro 12,935 million, of these projects to be carried out outside Italy represented 94%, while orders from Eni companies amounted to 7% of the total. Eni’s order backlog was euro 20,505 million at December 31, 2010 (euro 18,730 million at December 31, 2009). Projects to be carried out outside Italy represented 94% of the total order backlog, while orders from Eni companies amounted to 16% of the total.

Orders acquired (euro million)   2008   2009   2010   Change     % Ch.  
Orders acquired     13,860   9,917   12,935   3,018     30.4  
Offshore construction     4,381   5,089   4,600   (489 )   (9.6 )
Onshore construction     7,522   3,665   7,744   4,079     111.3  
Offshore drilling     760   585   326   (259 )   (44.3 )
Onshore drilling     1,197   578   265   (313 )   (54.2 )
of which:                          
- Eni     540   3,147   962   (2,185 )   (69.4 )
- Third parties     13,320   6,770   11,973   5,203     76.9  
of which:                          
- Italy     831   2,081   825   (1,256 )   (60.4 )
- Outside Italy     13,029   7,836   12,110   4,274     54.5  

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Order backlog (euro million)   December
31, 2008
  December
31, 2009
  December
31, 2010
  Change     % Ch.  
Order backlog     19,105   18,730   20,505   1,775     9.5  
Offshore construction     4,682   5,430   5,544   114     2.1  
Onshore construction     9,201   8,035   10,543   2,508     31.2  
Offshore drilling     3,759   3,778   3,354   (424 )   (11.2 )
Onshore drilling     1,463   1,487   1,064   (423 )   (28.4 )
of which:                          
- Eni     2,547   4,103   3,349   (754 )   (18.4 )
- Third parties     16,558   14,627   17,156   2,529     17.3  
of which:                          
- Italy     435   1,341   1,310   (31 )   (2.3 )
- Outside Italy     18,670   17,389   19,195   1,806     10.4  

Capital expenditures

In 2010 capital expenditures in the Engineering & Construction segment (euro 1,552 million) mainly regarded:
(i) Offshore: construction of a new pipelayer and the ultra-deep water Field Development Ship FDS2, activities for the conversion of a tanker into an FPSO and the construction of a new fabrication yard in Indonesia;
  (ii) Offshore drilling: activities for the completion of the new ultra deep water drill ship Saipem 12000, construction of the semi-submersible rigs Scarabeo 8 and 9 and of the jack up Perro Negro 6;
(iii) Onshore drilling: development of operating structures;
(iv) Onshore: maintenance of the existing asset base.

 

Capital expenditures (euro million)   2008   2009   2010   Change     % Ch.  
Offshore construction     741   691   706   15     2.2  
Onshore construction     48   19   11   (8 )   (42.1 )
Offshore drilling     785   706   559   (147 )   (20.8 )
Onshore drilling     424   188   253   65     34.6  
Other expenditures     29   26   23   (3 )   (11.5 )
      2,027   1,630   1,552   (78 )   (4.8 )

Main R&D projects

In 2010 overall expenditure in R&D amounted to approximately euro 14 million (euro 17 million in 2009), excluding general and administrative expenses. In 2010, 60 full time equivalent employees were working in R&D. A total of 17 new patent applications were filed. Below are outlined the main R&D results achieved in 2010 with an impact on the Division’s strategic results broken down by development of operational assets (naval equipment and processes), offshore and onshore technologies.

Assets
Technological innovation on assets is pursued with the aim of improving sustainability, competitivity and reliability, and reducing the environmental impact of operations. In particular, in 2010 some of the projects underway reached the testing phase:
- Equipment: New systems for the construction of coverage for soldering joints on board of pipelaying vessels, techniques for the remote control of anomalous deformations during the laying of pipes into the sea and some technologies complementary to excavation activities for critical operating scenarios have been validated. Studies were completed on technologies

  for the sustainability for the construction for the infrastructure in environmentally highly sensitive areas.
- Vessels: Detailed development and implementation of the main technical systems and subsystems for production and laying of pipes on the new pipelaying vessel CastorOne continued.
During 2010 two important events took place for favoring dissemination of innovative knowledge: the Offshore and Arctic Development Workshop and the new edition of the Innovation Trophy.

Offshore
Activities were focused on programs dedicated to the continued improvement of innovative solutions for the development of oil and natural gas fields in the sea. Main activities concerned fields in frontier areas such as deep waters and the Arctic, monetization of offshore natural gas reserves by means of liquefaction technologies applied on floating plants (LNG offshore) and production from offshore renewable sources.
- Subsea processing: A new proprietary multipipe system for the gravitational separation of gas and liquids successfully completed the second testing phase in the framework of a Joint Industry Project supported by important oil companies. Results

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achieved confirmed the efficacy of the separator in real flow conditions.
- SURF: Activities started in 2009 on projects for developing solutions for new risers to be used in ultra deep (up to 3,000 meters) or intermediate depth (between 300 and 600 meters) waters continued. Work continued on technologies for thermal isolation and anticorrosion solutions for underwater operations.
- FLNG: activities intensified in 2010 in particular in the development of solutions for a medium-scale floating LNG system and a tandem offloading solution using a flexible cryogenic floating pipe.
- Offshore renewable sources: Activities focus mainly on a large scale prototype of an underwater turbine with 10 meter diameter called Sabella to be installed in the future off the coast of Brittany. The participation of the French government to the financing of the project has been officially announced at the end of 2010.

Onshore
Activity is dedicated to process technologies and their know-how and to the application of the most modern and state of the art technologies from third parties supporting our clients worldwide in the upstream, midstream and downstream areas in the various phases of completion from engineering to construction.
- Urea plants: Work was aimed at increasing the performance of our Snamprogetti™ Urea proprietary technology for the production of fertilizers, licensed worldwide and applied to date in 120 plants. After having planned and in some cases also built

  the largest urea plants in the world (Engro in Pakistan, Qafco V and VI in Qatar and Matix in India) based on the operation of single lines for 3,859 t/d, we developed a conceptual study for a future 5,000 t/d train using the same well established sequence of technologies. In addition we are designing a pilot unit for the recovery of ammonia within the Zero Emission Project that will be then built in a commercial plant.
- CCS: Within the Eni/Enel pilot program on Carbon Capture and Storage, Saipem is following the design of a pipe for carrying dense CO2. We completed the project phase of a line for pilot transport to be located in the Brindisi power station.
- ENSOLVEX: The first commercial unit based on this proprietary technology for the remediation of contaminated soil is under construction at the Gela refinery.
- Microalgae: The first semicommercial unit for removing carbon dioxide from refinery effluents through biofixation by means of microalgae was completed and delivered. The ensuing biomass can be used for the production of biofuels.
- Sulfur treatment: Saipem obtained a new patent for the technology for the treatment and transport of sulphur with zero emissions, a new method for solidifying liquid sulphur in blocks, thus consolidating its first class position in sulfur treatment technologies.
- EST: Saipem continues to support the management engineering and project for the development and implementation of the Eni Slurry Technology in various research programs. The first commercial unit is currently under construction at the Sannazzaro refinery.

 

 

 

 

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Profit and loss account

2008    

(euro million)

  2009     2010     Change     % Ch.  
108,082     Net sales from operations   83,227     98,523     15,296     18.4  
728     Other income and revenues   1,118     956     (162 )   (14.5 )
(80,354 )   Operating expenses   (62,532 )   (73,920 )   (11,388 )