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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 May 2012

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 TOC

Press Release dated May 8, 2012

Press Release dated May 9, 2012

Report Eni in 2011

Fact Book 2011

Notice of Shareholders Meeting Resolutions

Press Release dated May 16, 2012

Press Release dated May 25, 2012

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/TOC

SIGNATURES

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

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

Date: May 31, 2012

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Eni Shareholders Approve 2011 Financial Statements at Annual Meeting

2011 net profit euro 4.21 billion
Total dividend per share for 2011 of euro 1.04
Remuneration Report approved
Articles 17 and 28 of company by-laws amended, and new article 34 added for gender equality on the Board of Directors and Board of Statutory Auditors

Rome, May 8, 2012 - The Ordinary and Extraordinary General Meeting of Enis shareholders today resolved the following:

To approve financial statements for the year ending December 31, 2011, reporting net profit of euro 4,212,687,003.27;
To allocate euro 2,328,880,900.91 out of the 2011 profit of euro 4,212,687,003.27 which remains after the payment of an interim dividend of euro 0.52 per share as resolved by the Board of Directors on September 8, 2011, as follows: - A dividend to shareholders of euro 0.52 for each share owned and outstanding at the ex-dividend date, in addition to the interim dividend of euro 0.52 per share, thereby bringing the full year dividend for 2011 to euro 1.04 per share;
The amount remaining following the distribution of the proposed euro 1.04 per share dividend will be added to Retained Earnings;
To pay the balance of the 2011 dividend on May 24, 2012, with the ex-dividend date set for May 21, 2012;
To approve the first section of the Remuneration Report, which sets out the companys compensation policy for the Board of Directors, general managers and executives, and lays out the strategic responsibilities and procedures used to adopt and implement the new policy;
To approve amendments to articles 17.3, 17.5 and 28.2 of the companys by-laws, and the addition of article 34, aimed at establishing gender equality in the composition of the Board of Directors and Board of Statutory Auditors, pursuant to Law No. 120/2011.

Company Contacts:

Press Office Tel.: +39.0252031875 - +39.06598232030 Freephone for shareholders (from Italy): 800940924 Freephone for shareholders (from abroad): +39. 800 11 22 34 56 Switchboard: +39-0659821

[email protected] [email protected] [email protected]

Web site : www.eni.com

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The New Face of Eni's Chemicals Division New strategy and rebranding to Versalis

Milan, May 9, 2012 - The new face of Enis chemicals division is Versalis. Created following the rebranding of Polimeri Europa, it represents a tangible sign of the new strategy for Enis chemicals division and a renewal of the historical importance of the business within Eni. The name Versalis is the best example of this new strategy Daniele Ferrari, CEO of Versalis, explained today in Milan, at Plast 2012 as it brings to mind the concept of universality, widespread presence, stability, safety and security. Versalis sets out to operate as one of the most advanced chemicals and plastic materials businesses, through an ongoing commitment to research and innovation in products, processes and technology. The European chemical sector currently operates in a very complex environment which has undergone critical challenges in recent years due to the entry of new competitors, a great number of production plants moving to Asia, and the volatility of feedstock and energy prices. In addition, increased focus on protecting the environment has accelerated the trend of these changes. Today, the production of Green chemicals represents an evolution of traditional business, and presents high growth opportunities. Technological innovation is one of the fundamental elements of the re-launch of Eni's chemicals business and the Green District project at Porto Torres, which started from its partnership with Novamont in Matrìca, and will enable Versalis to be well positioned in this new sector. The project for the production of chemicals from renewable sources comprises the construction of one of the biggest industrial complexes in the world at Porto Torres, where bio-monomers and bio-polymers will be produced, through an investment of more than euro 500m (in addition to the investments of the plan). The construction of seven production plants is planned in three phases over the next five years, along with a research centre which was opened in February 2012. Eni's strategy for responding to both old and new challenges in the chemicals industry is based, first of all, on its focus on products with greater added value, through expansion and differentiation of its product portfolio, for which Eni estimates a sales growth target of 50%. In the four-year period from 2012 to 2015, investment necessary for the creation of market-oriented growth conditions will be equal to euro 1.6bn., 60% more than in the previous plan, and will mainly be aimed at the re-launch of critical Italian sites to deliver income, growth in the business, and entry into new business areas. A significant portion of this investment, over euro 350m, will be dedicated to the conversion of the chemical plant at Priolo (SR) from now until 2015, with

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special attention paid to the cracking and polyethylene plants, and the construction of new plants which will ensure the site's profitability and increase employment levels. The new plan highlights the development of the elastomers business, a sector in which Versalis is the leader in Europe, for which over euro 500m of investment is envisaged. The objective is to double the company's turnover, increasing the current 15% margin to 30% in the next 5 years, by strengthening the current production lines and developing existing capacity thanks to the construction of new plants at the sites of Ravenna, Ferrara and Grangemouth (UK). The new butadiene line at Dunkerque is fundamental to the supply of raw materials to the elastomer production sites, particularly in the UK. A fundamental characteristic of the business is our constant commitment to business expansion in emerging markets. An important driver will be the use of proprietary technology (licensing and patents) for the development of joint venture agreements with international players, in Asian markets in particular. As the first step, Versalis has recently entered China with Eni Chemicals Shanghai, directly distributing products in the Chinese market, and with Versalis Pacific (which also has offices in Shanghai), which operates in all Asian markets. Implementation of this renewal plan will provide an expected improvement in EBIT of over euro 400m in 2015.

Company Contacts:

Press Office Tel.: +39.0252031875 - +39.06598232030 Freephone for shareholders (from Italy): 800940924 Freephone for shareholders (from abroad): +39. 800 11 22 34 56 Switchboard: +39-0659821

[email protected] [email protected] [email protected]

Web site : www.eni.com

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4 6 14 20 24 26 30 34 35 37 39 46 50 54

"Eni in 2011" report comprises an extract of the description of the business, the managements discussion and analysis of financial condition and results of operations and certain other Company information from Enis Annual Report for the year ended December 31, 2011. It does not contain sufficient information to allow as full an understanding of financial results, operating performance and business developments of Eni as "Eni 2011 Annual Report". It is not deemed to be filed or submitted with any Italian or US market or other regulatory authorities. You may obtain a copy of "Eni in 2011" and "Eni 2011 Annual Report" on request, free of charge (see the request form on Enis web site eni.com under the section "Publications"). "Eni in 2011" and "Eni 2011 Annual Report" may be downloaded from Enis web site under the section "Publications". All financial data presented in this report is based on consolidated financial statements prepared in accordance with IFRS. For definitions of certain financial and operating terms see "Frequently used terms" section, on page 46. This report contains certain forward-looking statements particularly those 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; managements ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and regulations; development and use of new technologies; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. As Eni shares, in the form of ADRs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F has been filed with the US Securities and Exchange Commission in accordance with the US Securities Exchange Act of 1934. Hard copies may be obtained free of charge (see the request form on Enis web site eni.com under the section "Publications"). Eni discloses on its Annual Report on Form 20-F significant ways in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards. The term "shareholder" in this report means, unless the context otherwise requires, investors in the equity capital of Eni SpA, both direct and/or indirect. Eni shares are traded on the Italian Stock Exchange (Mercato Telematico Azionario) and on the New York Stock Exchange (NYSE) under the ticker symbol "E".

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2009 2010 2011

| Net sales from operations | (euro
million) | 83,227 | 98,523 | 109,589 |
| --- | --- | --- | --- | --- |
| Operating
profit | | 12,055 | 16,111 | 17,435 |
| Adjusted operating profit | | 13,122 | 17,304 | 17,974 |
| Net profit
attributable to Eni | | 4,367 | 6,318 | 6,860 |
| Adjusted net profit attributable to Eni | | 5,207 | 6,869 | 6,969 |
| Net cash
provided by operating activities | | 11,136 | 14,694 | 14,382 |
| Capital expenditures | | 13,695 | 13,870 | 13,438 |
| Investments | | 2,323 | 410 | 360 |
| Cash dividends to Eni shareholders | | 4,166 | 3,622 | 3,695 |
| Total
assets at year end | | 117,529 | 131,860 | 142,945 |
| Shareholders' equity including non-controlling
interests at year end | | 50,051 | 55,728 | 60,393 |
| Net
borrowings at year end | | 23,055 | 26,119 | 28,032 |
| Net capital employed at year end | | 73,106 | 81,847 | 88,425 |
| Adjusted
Return On Average Capital Employed (ROACE) | (%) | 9.2 | 10.7 | 9.9 |
| Leverage | | 0.46 | 0.47 | 0.46 |
| Return On
Average Equity (ROAE) | | 9.6 | 13.0 | 12.9 |
| Coverage | | 17.9 | 22.2 | 15.4 |
| Current
ratio | | 1.0 | 1.0 | 1.1 |
| Debt coverage | | 48.3 | 56.3 | 51.3 |
| Employees
at period end | (number) | 77,718 | 79,941 | 78,686 |
| Female managers | (%) | 17.0 | 17.7 | 18.2 |
| Employee
injury frequency rate | (number of
injuries/million of worked hours) | 1.00 | 0.91 | 0.71 |
| Contractor injury frequency rate | | 1.18 | 0.88 | 0.74 |
| Oil spills | (barrels) | 6,259 | 4,269 | 7,295 |
| Oil spills due to sabotage and terrorism | | 15,288 | 18,695 | 6,127 |
| GHG
emission | (million
ton CO 2 eq) | 57.69 | 60.64 | 51.10 |
| R&D expenditures | (euro million) | 207 | 221 | 191 |
| Estimated
net proved reserves of hydrocarbons (at year end) | (mmboe) | 6,571 | 6,843 | 7,086 |
| Average reserve life index | (years) | 10.2 | 10.3 | 12.3 |
| Production
of hydrocarbons | (kboe/d) | 1,769 | 1,815 | 1,581 |
| Worldwide gas sales | (bcm) | 103.72 | 97.06 | 96.76 |
| Customers
in Italy | (million) | 6.88 | 6.88 | 7.10 |
| Gas volumes transported in Italy | (bcm) | 76.90 | 83.32 | 78.30 |
| Electricity
sold | (TWh) | 33.96 | 39.54 | 40.28 |
| Refining throughputs on own account | (mmtonnes) | 34.55 | 34.80 | 31.96 |
| Retail
sales of petroleum products in Europe | (mmtonnes) | 12.02 | 11.73 | 11.37 |
| Service stations in Europe at period end | (units) | 5,986 | 6,167 | 6,287 |
| Average
throughput of service stations in Europe | (kliters) | 2,477 | 2,353 | 2,206 |
| Sales of petrochemical products | (ktonnes) | 4,265 | 4,731 | 4,040 |
| Average
petrochemical plant utilization rate | (%) | 65.4 | 72.9 | 65.3 |
| Orders acquired | (euro million) | 9,917 | 12,935 | 12,505 |
| Order
backlog at period end | | 18,730 | 20,505 | 20,417 |

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Eni in 2011 Profile of the year

| Eni's strategy |
| --- |
| The oil&gas industry is copying with a complex
scenario featured by the global economic slowdown,
particularly in the Euro-zone, and volatile market
conditions for energy commodities. In the medium to
long-term the main challenges will be driven by rising
competitive pressures in accessing reserves by new
players, stricter regulation addressing environmental
preservation and mitigation of the climate risk, growing
importance of renewable sources as well as the role of
unconventional resources in satisfying energy needs. Against this backdrop, Eni reaffirms its growth strategy
and the adoption of a sustainable business model founded
on the pillars of innovation, excellence, inclusiveness,
integration, responsibility and cooperation in a
framework of straightforward rules of corporate
governance. Eni believes that a sustainable business conduct
contributes to both the achievement of industrial
performance, and the mitigation of political, financial
and operational risks. This strengthens Enis role
as a trustworthy and reliable partner, who is ready to
capture new opportunities in the marketplace and able to
manage the complexities of the environment. Eni believes that those drivers will help the Company to
create value to its shareholders and stakeholders. Eni
has designed its industrial plan for the four-year period
2012-2015 along the following strategic guidelines:
growing profitably oil and gas production in the
upstream, strengthening market leadership in the European
gas market, improving downstream oil efficiency,
refocusing petrochemical operations and retaining top
spots among the best-in-class engineering and
construction players in the most technologically-
advanced segments. |

@ 90 $/bl in 2012-13; 85 $/bl in 2014-15
5 -

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2009 2010 2011

| Employees injury frequency rate | (No. of accidents per
million hours worked) | 0.49 | 0.72 | 0.41 |
| --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 0.59 | 0.48 | 0.41 |
| Fatality index | (No. of fatalities per
100 million hours worked) | 1.77 | 7.90 | 1.83 |
| Net sales
from operations (a) | (euro million) | 23,801 | 29,497 | 29,121 |
| Operating profit | | 9,120 | 13,866 | 15,887 |
| Adjusted
operating profit | | 9,484 | 13,884 | 16,077 |
| Adjusted net profit | | 3,878 | 5,600 | 6,866 |
| Capital
expenditures | | 9,486 | 9,690 | 9,435 |
| Adjusted capital employed, net at year end | | 32,455 | 37,646 | 42,024 |
| Adjusted
ROACE | (%) | 12.3 | 16.0 | 17.2 |
| Profit per boe (b) | ($/boe) | 8.14 | 11.91 | 16.98 |
| Opex per
boe (b) | | 5.77 | 6.14 | 7.28 |
| Cash Flow per boe | | 23.70 | 25.52 | 31.65 |
| Finding
& Development cost (c) | | 28.90 | 19.32 | 18.82 |
| Average hydrocarbons realizations (d) | | 46.90 | 55.60 | 72.26 |
| Production
of hydrocarbons (d) | (kboe/d) | 1,769 | 1,815 | 1,581 |
| Estimated net proved reserves of hydrocarbons (d) | (mmboe) | 6,571 | 6,843 | 7,086 |
| Reserves
life index (d) | (years) | 10.2 | 10.3 | 12.3 |
| All sources reserves replacement ratio (d) | (%) | 96 | 125 | 142 |
| Employees
at year end | (units) | 10,271 | 10,276 | 10,425 |
| of which: outside Italy | | 6,388 | 6,370 | 6,628 |
| Oil spills | (bbl) | 6,259 | 3,820 | 2,930 |
| Oil spills from sabotage and terrorism | | 15,288 | 18,695 | 6,127 |
| Produced
water re-injected | (%) | 39 | 44 | 43 |
| Direct GHG emissions | (mmtonnes CO 2 eq) | 29.73 | 31.20 | 23.59 |
| of which: from
flaring | | 13.84 | 13.83 | 9.55 |
| Community investment | (euro million) | 67 | 72 | 62 |

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

2011 Highlights

Performance of the year In 2011, employee and contractor injury frequency rates declined by 43.1% and 14.6% from 2010, respectively. Greenhouse gas emissions (total and from flared) reported a steep decline, reflecting the completion of certain gas recovery projects in Nigeria and the reduction in associated gas to feed the ramp-up of two turbo-generators in a power plant in Congo. Performance for the year was also impacted by lowered Libyan activities. In 2011, the E&P Division reported an excellent performance amounting to euro 6,866 million of adjusted net profit (up 22.6% from 2010), reflecting higher oil prices and the rapid recovery of Libyan output. Return on average capital employed calculated on an adjusted basis was 17.2% in 2011 (16% in 2010). In 2011, Eni reported liquids and gas production of 1,581 kboe/d, down by 12.9% from 2010, mainly due to a lowered output in Libya. Performance was also negatively impacted by lower entitlements in the Companys Production Sharing Agreements due to higher oil prices with an overall effect of approximately 30 kboe/d from 2010. Net of this effect and the above mentioned loss of Libyan output, production for the year was in line with 2010. In the year oil spills from accidents declined by 23% from 2010, due to significant prevention activities undertaken.

Contents

Eni in 2011 Business review / Exploration & Production

Estimated net proved reserves at December 31, 2011, were 7.09 bboe (up 3.6% from 2010) based on a 12-month average Brent price of $111 per barrel. All sources reserves replacement ratio was 142%. Excluding the price effect, the replacement ratio would be 159%. The reserves life index is 12.3 years (10.3 years in 2010). In 2011, capital expenditures amounted to euro 9,435 million to enhance assets in well established areas of Africa, the Gulf of Mexico and Central Asia. Exploration expenditure amounted to euro 1,210 million (up 19.6% from 2010) to execute a selective campaign with the completion of 56 new exploratory wells (28 net to Eni) and an overall commercial success rate of 42% (38.6% net to Eni). In addition 17 exploratory wells drilled are in progress at year end (9.9 net to Eni). Development expenditure was euro 7,357 million to fuel the growth of major projects in Norway, Kazakhstan, Algeria, the United States, Italy, Congo and Egypt. In 2011, overall R&D expenditure of Exploration & Production Division amounted to approximately euro 90 million (euro 98 million in 2010). Restarted Libyan operations The rapid restart of Enis Libyan operations reduced the impact of the Revolution on 2011 results. Production at Enis Libyan sites is currently flowing at approximately 240 kboe/d and management is targeting to achieve the pre-crisis production plateau of 280 kboe/d and full ramp-up by the second half of 2012. Giant discovery in Mozambique The giant Mamba discovery in Mozambique opens up extraordinary development opportunities and is ideally placed to serve the fast-growing Asian gas markets. The three exploration wells drilled in Area 4 in the Rovuma basin Mamba South, Mamba North and Mamba North East have found volumes of gas in place up to 40 Tcf. This is the largest operated discovery in the Companys history. Agreement with Rosneft On April 25, 2012, Eni and Rosneft signed a strategic cooperation agreement to jointly develop exploration licenses in the Russian offshore of the Barents Sea and the Black Sea. Under the agreement, joint ventures (Eni 33.33%) will explore for and develop the Fedynsky and Tsentralno-Barentsvesky licenses offshore the Barents Sea and the Zapadno-Cernomorsky license offshore the Black Sea. These licenses are estimated to hold recoverable resources of 36 bboe. Portfolio Signed a Gas Sales Agreement for developing the giant Perla gas discovery, containing over 17 Tcf of gas in place with the Venezuelan national oil company PDVSA. On December 14, 2011, the Republic of Kazakhstan and the contracting companies in the Final Production Sharing Agreement (FPSA) of the giant Karachaganak gas-condensate field reached an agreement to settle all pending claims. The agreement, effective from June 30, 2012 on satisfaction of conditions precedent, involves Kazakhstans KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies transferring 10% of their rights and interest in the Karachaganak FPSA to KMG. Signed with Chinese oil companies framework agreements to promote joint projects in conventional and unconventional hydrocarbon plays in China and outside China. Achieved a cooperation agreement with Sonatrach to explore for and develop unconventional hydrocarbons, particularly shale gas plays in Algeria. Signed a Memorandum of Understanding with South Africas State-owned oil company PetroSA to promote joint opportunities in conventional and unconventional hydrocarbons in South Africa and in Africa. Eni will also ensure long-term LNG supplies as well as flows of refined products to support the Countrys economic development. Acquired from Cadogan Petroleum plc an interest in two licenses for exploration and development in areas included in the Dniepr-Donetz basin in Ukraine. Reached an agreement with MEO Australia to farm-in the Heron and Blackwood gas discoveries in the NT/P-68 permit, located in the Timor Sea. In addition, Eni acquired a 32.5% stake in the Evans Shoal gas discovery in the Timor Sea with approximately 7 Tcf of volumes of gas in place. Awarded the Arguni I and the North Ganal operated gas exploration contracts located onshore and offshore Indonesia, respectively. The planned activities provide for the development of natural gas resources to feed existing LNG production plants nearby in both acquired areas. Awarded the operatorship of the PL657 license (Enis interest 80%) located in the Barents Sea nearby the Goliat operated field (Enis interest 65%). Any exploratory success will be supported by the existing facilities significantly reducing time-to-market. Signed with the Angolan authorities the Production Sharing Contract to explore Block 35 (Eni operator with a 30% interest) located in an offshore high potential mineral basin.

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Eni in 2011 Business review / Exploration & Production

Strategies

Enis Exploration & Production business boasts a strong competitive position in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and Sub-Saharan Africa, Venezuela and Iraq. Enis strategy is to deliver organic production growth with increasing returns and reserve replacement. Growth will be fuelled by increasing flows from Enis core areas leveraging Enis vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. We intend to drive higher returns and manage the operational risk in our upstream operations by reducing time to market, increasing total volumes of operated production, as operatorship is seen to be the safest way to control risks, as well as selectively picking partners in non-operated joint-projects. Our growth trajectory will be supported by our ongoing commitment in establishing and consolidating our partnerships with key host Countries, leveraging the Eni co-operation model. We expect that continuing technological innovation and competence build-up will drive production growth and increasing rates of reserve recovery, developing drilling techniques to be applied in complex environment, marginal fields and deep/ultra deep offshore areas. Consistent with the long-term nature of the business, strategic guidelines for our Exploration & Production Division have remained basically unchanged in the years, as follows: n Maintain strong profitable production growth n Invest in exploration to enhance growth prospects over the long-term and ensure reserve replacement n Develop new projects to fuel future growth n Consolidate our industry-leading cost position To execute these strategies, we plan to spend approximately euro 37.6 billion to explore for and develop new reserves over the next four years. Exploration projects will account for approximately euro 5.5 billion. Approximately euro 1.7 billion will be spent to build transportation infrastructures and LNG projects through equity-accounted entities.

| Maintain Strong Production Growth |
| --- |
| Our global oil and gas operations are conducted in 41
Countries, including Italy, Libya, Egypt, Norway, the
United Kingdom, Angola, Congo, Mozambique, Nigeria, the
United States, Kazakhstan, Russia, Algeria, Australia,
Venezuela and Iraq. Enis strategy is to deliver
strong profitable production growth via organic
developments, leveraging on the planned start-ups of over
60 major projects over the next four years and material
expenditures to support the current plateau at our
producing fields. Our plans also contemplate certain
development projects which will support the
Companys long-term production plateau, particularly
we plan to start developing the recent gas discovery
offshore Mozambique and to progress large and complex
projects in the Barents Sea, Nigeria and Indonesia. We project that new field start-ups will add
approximately 700 kboe/d to the Companys production
level in 2015 at our long-term Brent price of $85 a
barrel. The most important production start-ups are
planned in Nigeria, Angola, Norway, Venezuela, Russia and
Kazakhstan and will be mainly focused on key hubs where
we plan to benefit from technical and producing
synergies. We have a good level of visibility on those
new projects as most of them have been already sanctioned
and where we serve as operator. Most of these new
projects are giant fields characterized by steady and
long-lasting production plateaus. These giant fields
include three of our fields in the Yamal Peninsula in
Russia, Goliat in Norway, Perla and Junin 5 in Venezuela,
Block 15/06 in Angola and Kashagan. A second leg of our growth strategy is to sustain the
current plateau at producing fields by counteracting
natural field depletion and production optimization. We
plan to dedicate strong efforts to this area by executing
a huge infilling and work-over campaign. We expect that
continuing technological innovation and competence
build-up will drive increasing rates of reserve recovery. We intend to implement a number of initiatives to support
profitability by exercising tight cost control and
reducing the time span which is necessary to develop and
market reserves. We are making strong progress in
reducing the time to developing and marketing our
exploration resources. We have fine-tuned our process and
organization to consistently monitor the status and value
of resources in the different phases of conversion.
Through these actions, we will be able to develop more
than 90% of the exploration successes of the last three
years within 8 years of their discovery. Eni will pursue further growth options by developing
unconventional plays, gas- |

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Eni in 2011 Business review / Exploration & Production

| n Production
and reserves: 2011 and outlook In 2011, Eni reported liquids and gas production of
1,581 kboe/d, down by 12.9% from 2010. This reduction was
driven by a lowered flow from Enis activities in
Libya, which was affected by the shut down of almost all
the Company plants and facilities including the
GreenStream pipeline throughout the peak of the
Countrys internal crisis. In the last part of the
year the efforts made to restart the GreenStream pipeline
and recover production enabled the Company to bring back
online an average Libyan output of 112 kboe/d in the
year, partly offsetting the impact of force majeure (down
approximately 200 kboe/d). Performance was also
negatively impacted by lower entitlements in the
Companys PSAs due to higher oil prices with an
overall effect of approximately 30 kboe/d compared to the
previous year. Net of these effects, production for 2011
was in line with 2010. Ramp-ups and start-ups were offset
by lower-than-anticipated growth in Iraq and planned
facility downtime. In the year we achieved eleven start-ups which are
expected to add approximately 80 kboe/d at plateau to
Enis medium-term production. Main start-ups were:
(i) the Guendalina (Enis interest 80%) and
Capparuccia (Enis interest 95%) fields, in Italy,
with an overall production start-up at approximately 7
kboe/d; (ii) the Denise B field in the El Temsah
concession (Eni operator with a 50% interest), in | | Egypt. Production peak is
expected at 14 kboe/d in 2012; (iii) the Appaloosa field
(Enis interest 100%), in the Gulf of Mexico, with a
production of 7 kbbl/d through linkage to the Corral
operated platform with a treatment capacity of 33 kbbl/d
net to Eni; (iv) the Nikaitchuq operated field
(Enis interest 100%), located in North Slope basins
offshore Alaska, with resources of 220 million barrels.
Development plan completion is expected in 2014 with an
average production plateau at approximately 21 kbbl/d net
to Eni in 2016; (v) the Kitan oil field (Eni operator
with a 40% interest) located between Timor Leste and
Australia. Peak production of over 40 kbbl/d is expected
in 2012; (vi) the Libondo offshore field (Enis
interest 35%), in Congo with production of approximately
3 kboe/d net to Eni. Our production outlook remains strong as we plan to
achieve a compound average growth rate of over 3% in the
next 2012-2015 four-year period, targeting a production
plateau of 2.03 million boe per day in 2015. The growth
rate has been calculated excluding the impact of
disruptions in Libya on the 2011 baseline production. To
achieve that target, we intend: to
leverage our robust pipeline of projects start-ups,
particularly in Nigeria, Angola, Norway, Venezuela, the
Yamal Peninsula in Russia and Kazakhstan, most of which
is Eni operated and leveraging our vast knowledge of
reservoirs and geological basins, as well as technical
and producing synergies; |
| --- | --- | --- |
| i | i | i |

Oil and natural gas production (a) (b)

Liquids	Natural ga s	Hydrocarbons	Liquids	Natural gas	Hydrocarbons	Liquids	Natural gas	Hydrocarbons
(kbbl/d)	(mmcf/d)	(kboe/d)	(kbbl/d)	(mmcf/d)	(kboe/d)	(kbbl/d)	(mmcf/d)	(kboe/d)

2009 2010 2011

Italy	56	652.6	169	61	673.2	183	64	674.3	186
Rest of Europe	133	655.5	247	121	559.2	222	120	537.9	216
Croatia		95.5	17		45.3	8		29.9	5
Norway	78	273.7	126	74	271.6	123	80	284.0	131
United
Kingdom	55	286.3	104	47	242.3	91	40	224.0	80
North Africa	292	1,614.2	573	301	1,673.2	602	209	1,271.5	438
Algeria	80	19.7	83	74	20.2	77	69	19.0	72
Egypt	91	793.7	230	96	755.1	232	91	800.7	236
Libya	108	780.4	244	116	871.1	273	36	423.2	112
Tunisia	13	20.4	16	15	26.8	20	13	28.6	18
Sub-Saharan
Africa	312	274.3	360	321	441.5	400	278	508.0	370
Angola	125	29.3	130	113	31.9	118	95	34.7	102
Congo	97	27.3	102	98	67.9	110	87	119.1	108
Nigeria	90	217.7	128	110	341.7	172	96	354.2	160
Kazakhstan	70	259.0	115	65	237.0	108	64	231.0	106
Rest of Asia	57	444.8	135	48	463.9	131	34	430.1	112
China	7	8.2	8	6	6.7	7	7	5.0	8
India		3.7	1	1	36.6	8		19.6	4
Indonesia	2	104.8	21	2	94.4	19	2	84.3	18
Iran	35		35	21		21	6		6
Iraq				5		5	7		7
Pakistan	1	328.1	58	1	326.2	59	1	321.2	58
Turkmenistan	12		12	12		12	11		11
America	79	424.7	153	71	396.0	143	65	334.0	125
Brazil							1		1
Ecuador	14		14	11		11	7		7
Trinidad
& Tobago		67.0	12		63.6	12		56.7	10
United States	57	357.7	119	49	332.4	109	48	277.3	98
Venezuela	8		8	11		11	9		9
Australia and Oceania	8	48.6	17	9	95.7	26	11	97.8	28
Australia	8	48.6	17	9	95.7	26	11	97.8	28
	1,007	4,373.7	1,769	997	4,539.7	1,815	845	4,084.6	1,581
of which
equity-accounted entities:	17	38.3	23	19	35.6	25	19	34.0	26
Angola	3	0.7	3	3	0.8	3	3	1.9	4
Brazil							1		1
Indonesia	1	32.1	6	1	28.9	6	1	25.7	6
Tunisia	5	5.5	6	4	5.9	5	5	6.4	6
Venezuela	8		8	11		11	9		9

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.
(b)	i	Includes
volumes of gas consumed in operations (321, 318 and 300
mmcf/d in 2011, 2010 and 2009, respectively).
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Eni in 2011 Business review / Exploration & Production

| to maximize the
production recovery rate at our current fields by
counteracting natural field depletion. This will require
intense development activities of work-over and
infilling. We expect that continuing technological
innovation and competence build-up will drive increasing
rates of reserve recovery; to
monetize our reserves of associated gas in particular in
Algeria, Angola, Congo, Iraq, Italy, Libya, Nigeria,
Norway and Turkmenistan, targeting to cut the level of
gas flaring by 80% from 2007 levels over the next four
years-plan. Management is ready to invest approximately
euro 4 billion to achieve that target. Actual production volumes will vary from year to year
due to the timing of individual project start-ups,
operational outages, reservoir performance, regulatory
changes, asset sales, severe weather events, price
effects under production sharing contracts and other
factors. Estimated net proved reserves at December 31, 2011,
were 7.09 bboe (up 3.6% from 2010) based on a 12-month
average Brent price of $111 per barrel. Additions to
proved reserves booked in 2011 derived from: (i)
extensions, discoveries and other factors, with major
increases booked in Russia, Venezuela, the United States
and Angola; (ii) revisions of previous estimates mainly
reported in Norway, Russia, Italy, Egypt, Kazakhstan and
Iraq; (iii) improved recovery mainly reported in Norway
and Algeria. The reserves life index is 12.3 years (10.3
years in 2010). Eni intends to pay special attention to reserve
replacement in order to ensure the medium to long-term
sustainability of the business. In 2011, we achieved a
strong reserve replacement ratio of 142% through fast
sanctioning and timely start-ups of new projects. We made
final investment decisions to develop large projects such
as the jointly-operated Samburgskoye and Urengoskoye
giant gas fields in Siberia, the Perla project in
Venezuela, as well as projects in Norway and the Gulf of
Mexico which enabled us to book noticeable amounts of
reserves in the year. Eni will continue focusing on
well-established areas of presence where we have
experience and good knowledge of the geological model.
Those areas include Sub-Saharan Africa, Venezuela,
Norway, Russia, Kazakhstan and Iraq where availability of
production facilities will enable the Company to readily
put in production discovered reserves. Our reserve replacement will be underpinned by our strong
focus on exploration and timely conversion of resources
into reserves and production, while at the same time
fighting depletion and enhancing the recovery factor in
existing fields through effective reservoir management. |
| --- |
| Exploration activities play
a major role in our sustainable growth strategy by
fuelling new production and securing access to new
opportunities. In 2011, Eni exploration expenditures
amounted to euro 1,210 million (up 19.6% from 2010) to
execute a selected campaign with the completion of 56 new
exploratory wells, of which 80% were successful. 2011 has been an extraordinary year in terms of size and
reach of new discoveries. Exploration successes in the
year contributed to increase our resource base by 1.1
billion boe. Our exploration success supports our
capacity to deliver sustainable returns on new projects
under almost any oil-price scenario with a very
competitive exploration cost of $1.2 per boe, down from
the last three years average of $1.9 per boe. Enis
resource base achieved 32 bboe. We made the large Mamba
gas discovery (Eni operator with a 70% interest) off the
Mozambique coast, located in Area 4 in the Rovuma Basin.
According to field test results and our internal
estimates, we believe that the new discovery may contain
up to 40 Tcf amounts of high-quality gas in place. In a
final completion configuration, production per well is
expected to reach over 140 million cubic feet a day,
approximately 25 kboe/d. In the next two years up to 8
additional wells are expected to be drilled in the nearby
areas in order to fully assess the high potential of the
Mamba reservoir, investing euro 400 million. Further
world-class discoveries have been achieved in the Barents
Sea with the Skrugard and Havis oil and gas wells with
recoverable reserves estimated at approximately 500
million barrels in the PL532 license (Enis interest
30%). Both fields are planned to be put in production by
means of a fast-track synergic development. Following
these major successes, we believe we have cracked the
geological code in this part of the basin, and are
confident in a significant resource upside. In Venezuela
appraisal activities were completed at the large Perla
gas field in the Gulf of Venezuela. Results exceeded the
initial resource estimate to more than 16,000 billion
cubic feet. The target production of approximately 300
million cubic feet a day is expected in 2014. Our consistent performance confirms the effectiveness of
our exploration strategy, with its focus on proven basins
and a select number of high-potential frontier plays.
Building on this success, over the next four years we
will increase our exploration efforts to further
strengthen the basis of our long-term growth. In the next
four years, we are planning to step up expenditures
compared to our previous capital budget (an increase of
approximately euro 2 billion). |

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Eni in 2011 Business review / Exploration & Production

Estimated net proved hydrocarbons reserves	(mmboe)	2009	2010	2011
At
December 31
Consolidated subsidiaries
Italy		703	724	707
Rest of Europe		590	601	630
North
Africa		1,922	2,096	2,031
Sub-Saharan Africa		1,141	1,133	1,021
Kazakhstan		1,221	1,126	950
Rest of Asia		236	295	230
America		263	230	238
Australia and Oceania		133	127	133
		6,209	6,332	5,940
Equity-accounted entities		362	511	1,146
		6,571	6,843	7,086
Estimated net proved liquids reserves	(mmbbl)	2009	2010	2011
At
December 31
Consolidated subsidiaries
Italy		233	248	259
Rest of Europe		351	349	372
North
Africa		895	978	917
Sub-Saharan Africa		770	750	670
Kazakhstan		849	788	653
Rest of Asia		94	139	106
America		153	134	132
Australia and Oceania		32	29	25
		3,377	3,415	3,134
Equity-accounted entities		86	208	300
		3,463	3,623	3,434
Estimated net proved natural gas reserves	(bcf)	2009	2010	2011
At
December 31
Consolidated subsidiaries
Italy		2,704	2,644	2,491
Rest of Europe		1,380	1,401	1,425
North
Africa		5,894	6,207	6,190
Sub-Saharan Africa		2,127	2,127	1,949
Kazakhstan		2,139	1,874	1,648
Rest of Asia		814	871	685
America		629	530	590
Australia and Oceania		575	544	604
		16,262	16,198	15,582
Equity-accounted entities		1,588	1,684	4,700
		17,850	17,882	20,282

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Eni in 2011 Business review / Exploration & Production

Exploration projects will attract some euro 5.5 billion to appraise the latest discoveries made by the Company and to support continuing reserve replacement over the next four years. The most important amounts of exploration expenses will be incurred in Mozambique, the United States, Egypt, Nigeria, Angola, Norway and Indonesia; important resources will be dedicated to explore new areas in Sub-Saharan Africa (the Republic of Liberia, Ghana) and on unconventional plays. Over the next four years we aim to discover approximately 1 bboe of resources per year, at an average unit exploration cost of $2 per boe. We will continue to focus on assets with high materiality and fast time to market, concentrating on plays where we have experience and good knowledge of the geological model. We are also renewing our portfolio in new basins close to areas with high demand growth. As of December 31, 2011, Enis mineral right portfolio consisted of 1,106 exclusive or shared rights for exploration and development in 41 Countries on five continents for a total acreage of 254,421 square kilometers net to Eni of which developed acreage of 41,373 square kilometers and undeveloped acreage of 213,048 square kilometers. Acquisition of new leases in Angola, Australia, Ghana, Indonesia, Nigeria, and Norway and in Ukraine further enhanced our upstream portfolio. new projects. We plan to counteract those cost increases by leveraging on cost efficiencies associated with: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; and (iii) applying our technologies which we believe can reduce drilling and completion costs. A description of our main development projects is provided below. n Oil & gas major projects Block 405b Algeria (Eni 75%, Op.) Development activity progressed up the MLE and CAFC projects. The MLE project provides for 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 handle gas from the CAFC field. Production start-up is expected in 2012. The CAFC project provides the construction of an oil treatment plant and will also benefit from synergies with MLE production facilities. Gas and oil production start-up of CAFC field are expected in 2012 and 2014, respectively. The overall Block 405b will target a production plateau of approximately 33 kboe/d net to Eni by 2015. El Merk, Block 208 Algeria (Eni 12.25%) The scope of work provides for the construction of a gas treatment plant with a capacity of approximately 600 mmcf/d, two oil trains with a capacity of 65 kbbl/d and three export pipelines with linkage to the national system for a production of approximately 11 kbbl/d net to Eni. Start-up is expected in 2013. Kizomba satellites, Phase 1, Block 15 Angola (Eni 20%) The Kizomba satellites development targets the Clochas and Mavacola oil discoveries. The project provides for the drilling of 18 producing wells to be linked to an FPSO vessel already deployed in this area. Associated gas will be initially re-injected in the reservoirs in the Kizomba area, and later delivered to the A-LNG liquefaction plant. Start-up is expected by mid 2012 and production to peak at 100 kbbl/d (approximately 21 kbbl/d net to Eni) in 2013.

| Develop new projects to fuel future growth |
| --- |
| Eni
has a strong pipeline of development projects that will
fuel the medium and long-term growth of its oil and gas
production, with a break-even price of $45 per barrel. The pipeline of projects is geographically diversified,
with 20% of new production coming from developments in
OECD Countries, and 30% from Russia and the Caspian area.
However, while our production is geographically
diversified it is also focused on a number of key hubs
(Yamal Peninsula in Russia, Barents Sea in Norway,
Kazakhstan and Venezuela), with synergies in terms of
geological and local expertise, infrastructure and
relationships with local communities, and which will give
a material contribution to long-term production. We expect that costs to develop and operate fields
will increase in the next years due to sector-specific
inflation, and growing complexity of |

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Eni in 2011 Business review / Exploration & Production

Goliat, Prospecting License 229 Norway (Eni 65%, Op.) Goliat represents the first oil development in the Barents Sea. We have already obtained governmental approval. The project is progressing according to schedule. Development provides for the use of a cylindrical FPSO unit linked to an underwater production system. Gas produced will be injected in the field. Start-up is expected at the end of 2013 with production expected at 100 kbbl/d. Yamal Peninsula Russia (Eni 29.4%) We have 5 giant gas and condensates fields to develop in Russia. In 2011 we finalized our gas sales agreements and took the final investment decision on the Samburgskoye field. Start-up was achieved in April 2012 with an expected peak production of approximately 43 kboe/d (14 kboe/d, net to Eni). In addition, the Final Investment Decision of the onshore gas and condensate Urengoskoye field was sanctioned. Start-up is expected in 2014. Activities are progressing also on the Yaro-Yakhinskoye field. Oil production start-up is expected by the end of 2012, while first gas production in 2014. Lastly the Severo field will be in production by the end of 2015 and the definition of the field development plan is progressing. The Yamal hub will be provide over 120 kboe/d by 2015 and we confirm our expectation of long-term plateau of approximately 200 kboe/d. Junin 5 Venezuela (Eni 40%) We established a joint-venture with the Venezuelan National Oil Company PDVSA for the development of the giant Junin 5 oil field, located in the Orinoco Oil Belt with certified volumes of oil in place of 35 billion barrels. First oil is expected in 2012 at an initial rate of 75 kbbl/d, targeting a long-term production plateau of 240 kbbl/d by 2018. Perla Venezuela (Eni 50%) Perla is a giant gas field which was discovered by an Eni-participated joint venture in 2009 off the Venezuelan coast in the Gulf of Venezuela. The final investment decision for the first development phase was sanctioned in the year and a Gas Sale Agreement was signed. EPC contracts for the project are being awarded. The early production phase includes the utilization of the already successfully drilled wells and the installation of production platforms linked by pipelines to the onshore treatment plant. The target production of approximately 300 mmcf/d is expected in 2014. The investment plan for the first development phase is estimated at $1.4 billion. The development of Perla is currently planned to continue with two more phases by means of the drilling of additional wells and the upgrading of treatment facilities to reach a plateau production of 1,200 mmcf/d.

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2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 3.85 | 3.74 | 2.33 | |
| --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 9.48 | 8.24 | 8.38 | |
| Net sales from operations (a) | (euro million) | 30,447 | 29,576 | 34,731 | |
| Operating
profit | | 3,687 | 2,896 | 1,758 | |
| Adjusted operating profit | | 3,901 | 3,119 | 1,946 | |
| Marketing | | 1,721 | 733 | (550 | ) |
| Regulated businesses in Italy | | 1,796 | 2,043 | 2,112 | |
| International
transport | | 384 | 343 | 384 | |
| Adjusted net profit | | 2,916 | 2,558 | 1,541 | |
| EBITDA
pro-forma adjusted | | 4,403 | 3,853 | 2,565 | |
| Marketing | | 2,392 | 1,670 | 364 | |
| Regulated
businesses in Italy | | 1,345 | 1,486 | 1,535 | |
| International transport | | 666 | 697 | 666 | |
| Capital
expenditures | | 1,686 | 1,685 | 1,721 | |
| Adjusted capital employed, net at year end | | 25,024 | 27,270 | 27,660 | |
| Adjusted
ROACE | (%) | 12.3 | 9.8 | 5.6 | |
| Worldwide gas sales (b) | (bcm) | 103.72 | 97.06 | 96.76 | |
| LNG sales (c) | | 12.9 | 15.0 | 15.7 | |
| Customers in Italy | (million) | 6.88 | 6.88 | 7.10 | |
| Gas
volumes transported in Italy | (bcm) | 76.90 | 83.31 | 78.30 | |
| Electricity sold | (TWh) | 33.96 | 39.54 | 40.28 | |
| Employees
at year end | (units) | 11,404 | 11,245 | 10,907 | |
| Direct GHG emissions | (mmtonnes CO 2 eq) | 14.60 | 15.79 | 14.75 | |
| Customer
satisfaction index (PSC) | (%) | 83.7 | 87.4 | 91.0 | |
| Water consumption/withdrawals per kWheq produced
(EniPower) | (cm/kWheq) | 0.015 | 0.013 | 0.014 | |

i	i	i
(a)	i	Before
elimination of intragroup sales.
(b)	i	Include
volumes marketed by the Exploration & Production
Division of 2.86 bcm (6.17 and 5.65 bcm in 2009 and 2010,
respectively).
(c)	i	Refer to LNG
sales of the G&P Division (included in worldwide gas
sales) and the E&P Division.
i	i	i

2011 Highlights

Agreement with Gazprom In March 2012, as part of their strategic partnership, Eni and Gazprom signed agreements to revise gas supply contracts with retroactive effects from the beginning of 2011. The parties also agreed on a roadmap to commence construction of the South Stream gas pipeline with the Final Investment Decision (FID) expected by the end of 2012. Divestment of international pipelines In 2011, Eni divested its interests in the international pipelines importing natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) to Italy as part of the agreements made with the European Commission in 2010. Total consideration amounted to approximately euro 1.5 billion. Belgium In January 2012, Eni finalized the acquisition of Nuon Belgium NV and Nuon Power Generation Wallon NV for an outlay of euro 214 million. The acquired entities engage in marketing gas and electricity mainly to residential customers and small enterprises in Belgium. 2011 performance The G&P segment posted a 39.8% drop in adjusted net profit to euro 1,541 million, due to sharply lower results of the Marketing business. This was negatively impacted by weak demand and continuing competitive pressures fuelled by oversupply which pressured selling margins and reduced volumes opportunities. The performance was also affected by the disruption in Libyan gas. Furthermore, the results reflected only a part of the benefits associated with the renegotiations of gas supply contracts, certain of which have been finalized after 2011 year-end. These lower results were partly offset by the positive operating performance delivered by the International transport and Regulated businesses in Italy. Worldwide gas sales were basically stable at 96.76 bcm supported by commercial initiatives, despite lower consumption and competitive pressures. We grew in many European Countries and in international LNG

i - 14 -

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Eni in 2011 Business review / Gas & Power

sales, while off-takes from importers to Italy of Libyan gas fell sharply. Return On Average Capital Employed (ROACE) was 5.6% (9.8% in 2010). Capital expenditures amounted to euro 1,721 million for developing and upgrading transport and distribution networks in Italy, increasing storage capacity and improving efficiency standards in power generation. Electricity sales of 40.28 TWh increased by 0.74 TWh from 2010, up 1.9%. Gas volumes transported in Italy were 78.30 bcm, down by 6% from 2010 due to a steep decline in gas demand in Italy.

Strategies

Enis Gas & Power segment engages in all phases of the gas value chain: supply, trading and marketing of gas and electricity, gas infrastructures, and LNG supply and marketing. This segment also includes power generation activity, which is ancillary to the marketing of electricity. Enis leading position in the European gas market is underpinned by a set of competitive advantages, including our multi-Country approach, long-term gas availability, access to infrastructures, market knowledge, and a strong customer base. Furthermore, integration with our upstream operations provides valuable growth options whereby the Company targets to monetize its large gas reserves. The outlook in the European gas sector is challenging due to ongoing competitive pressures, while perspectives of a recovery in gas demand are muted due to macroeconomic uncertainties. Against this backdrop, we expect weak and volatile gas margins over the short and medium term. We have been implementing a number of initiatives to cope with this unfavorable environment targeting to gradually recover profitability of our marketing operations over the plan period. Firstly, we are committed to renegotiate better economic terms for the Companys gas purchase contracts, so as to restore the competitiveness of the Companys cost position. Secondly, we intend to strengthen our market position in the most valuable segments by upgrading our commercial efforts, improving service quality and retaining our large customer base particularly in retail. Finally, we will seek to boost margins by pursuing opportunities in the LNG market and deploying our trading capabilities aiming at capturing possible favorable trends in market prices and extracting value from our assets. Over the next four years, our strategy is to strengthen our leadership in the European gas markets, while managing through the downturn. We believe that this strategy will put us in a strong position to benefit once a market recovery begins. The strategic guidelines are: n To consolidate competitiveness of supply n To focus on key segments and markets n To recover profitability Our regulated businesses in gas transport, distribution and storage in Italy will continue focusing on network upgrading and efficient operations. However, we expect to exit these businesses due to a changed Italian regulatory environment in the near future. Finally our International transport business was downsized in 2011 following the divestment of our interests in the pipelines and carrier companies which transport gas from Northern Europe and Russia to core European consumer markets, including Italy. We expect that our residual activities in this business will continue to provide steady returns across the plan period. In the next four-year period, we plan to invest euro 7.2 billion in the business. Planned expenditures will be largely focused on regulated businesses with guaranteed returns, aiming at improving the systems flexibility and also at expanding gas storage capacity in Italy. In the Marketing business, we will invest about euro 1 billion, mainly in the power generation sector to increase flexibility and plant efficiency.

Gas market trends
In 2011, gas demand in Europe fell by 10% (down by 6% in
Italy) due to the economic downturn which reduced
industrial output and power requirements. Other factors
behind demand weakness were the growing adoption of
renewable sources, a shift to coal in power generation
due to cost advantages, as well as unusual weather
conditions. The profitability of the gas sector in 2011 was severely
hit by a combination of lower demand, oversupply and a
high rate of liquidity at continental hubs. Reduced sales
opportunities forced operators to aggressively compete on	pricing, particularly those operators which were exposed
to take-or-pay supply contracts. On their part, large
clients adopted opportunistic supply patterns, in order
to take advantage of the large availability of spot gas
on the marketplace. Those drivers led to a squeeze in
marketing margins due to decoupling trends between, on
one hand, the rising cost of gas supplies that are
indexed to the price of oil and its derivatives, as
provided by pricing formulas in long-term supply
contracts, and, on the other hand, weak selling prices at
continental hubs which have become the prevailing
benchmark

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Eni in 2011 Business review / Gas & Power

in selling contracts. Management forecasts that weak gas demand trends owing to decelerating economic growth, the persistence of oversupplies on the marketplace and strong competition will represent risk factors to the profitability outlook of the Company gas Marketing business over the next two to three years. However, we expect that things will start improving by 2014-2015. Demand will stage a medium term recovery driven by the secular growth trends of economic development and increasing use of gas in the production of electricity, also considering the ongoing commitment to reduce GHG emissions by EU Member States. Management expects EU demand to increase from around 500 bcm in 2011 to around 565 bcm by 2015, and to close to 600 bcm in 2020, corresponding to an average growth rate of approximately 2% across the period. Gas demand in Italy is expected to grow with an average rate of approximately 2% driven by power generation consumption which is expected to increase from approximately 28 bcm in 2011 to over 40 bcm in 2020. At the same time, we see European supplies tightening mainly due to: - increasing Far East demand, where we estimate that consumption will increase by 16%, or around 90 bcm within 2015, mainly driven by robust rates of economic development, as well as Japans shift to gas-fired electricity away from nuclear fuel. This will largely absorb the new LNG production coming on-stream in the region and attract some of the worldwide LNG supplies which are currently being delivered to Europe; - increasing domestic gas consumption in the Middle East and North Africa; - declining European domestic production; and - limited LNG capacity additions for the Atlantic basin. Domestic gas production in Europe will decline from the current level of 173 bcm by around 3% a year, to 156 bcm by 2015 and 130 bcm by 2020. LNG imports will level off after the peak in 2011, with capacity growth being absorbed by strong demand in the Far East and Latin America. In addition, incumbent European suppliers, in particular in Northern Africa, will struggle to increase exports because of strong domestic demand. In this context, our diversified long-term supply portfolio, our increased equity gas and our market leadership in key European countries will be significant competitive advantages, leading to growing profitability in our marketing business. generation customers and wholesalers by 13 bcm leveraging on our strong commercial platform in the largest consuming countries of traditional presence (Italy, France, Germany, UK, Spain, Belgium) and in our new, target markets (Netherlands, Austria and Hungary). Management also plans to increase Enis penetration in the European retail segment, growing our customer base by almost 30% in the next four years.

| Gas sales: 2001 and
outlook | Gas sales by market | 2009 | 2010 | 2011 |
| --- | --- | --- | --- | --- |
| | ITALY | 40.04 | 34.29 | 34.68 |
| In 2011, sales
of natural gas were 96.76 bcm, down 0.30 bcm, or 0.3%.
Despite a 6% decline in natural gas demand, sales volumes
on the Italian market were substantially stable, to 34.68
bcm (up 0.39 bcm, or 1.1%) due to effective market
initiatives that led to higher sales to industrial
customers, wholesalers and to the power generation
segment. Sales to shippers were down 5.20 bcm, or 61.6%, due to
the impact of force majeure on Libyan supplies. Sales on target markets in Europe of 49.74 bcm showed a
positive trend, increasing by 7.9%, except for Benelux
where competitive pressure reduced Enis sale
portfolio. The main increases were recorded in Turkey,
France also due to the consolidation of Altergaz,
UK/Northern Europe, Germany/Austria and the Iberian
Peninsula. The outlook for natural gas sales in 2012 is uncertain
due to macroeconomic headwinds, weak demand growth and
continuing oversupplies. Against this backdrop,
management expects to achieve stable natural gas sales
compared to 2011. Management intends to seek to increase
sales volumes and market share in Italy and particularly
to retain and develop its retail customer base; outside
Italy the main drivers of growth will be sales expansion
in the key markets of France, Germany/Austria and Benelux
and opportunities in the Far East. Those increases will
offset lower sales elsewhere. Over the plan period, we intend to increase our sales to
industrial, power | Wholesalers | 5.92 | 4.84 | 5.16 |
| | Gas release | 1.30 | 0.68 | |
| | Italian gas exchange and
spot markets | 2.37 | 4.65 | 5.24 |
| | Industries | 7.58 | 6.41 | 7.21 |
| | Medium-sized enterprises
and services | 1.08 | 1.09 | 0.88 |
| | Power generation | 9.68 | 4.04 | 4.31 |
| | Residential | 6.30 | 6.39 | 5.67 |
| | Own consumption | 5.81 | 6.19 | 6.21 |
| | INTERNATIONAL SALES | 63.68 | 62.77 | 62.08 |
| | Rest of Europe | 55.45 | 54.52 | 52.98 |
| | Importers in Italy | 10.48 | 8.44 | 3.24 |
| | European markets | 44.97 | 46.08 | 49.74 |
| | Iberian Peninsula | 6.81 | 7.11 | 7.48 |
| | Germany/Austria | 5.36 | 5.67 | 6.47 |
| | Belgium | 15.72 | 14.87 | 11.95 |
| | Hungary | 2.58 | 2.36 | 2.24 |
| | UK/Northern Europe | 4.31 | 5.22 | 6.10 |
| | Turkey | 4.79 | 3.95 | 6.86 |
| | France | 4.91 | 6,09 | 7.01 |
| | Other | 0.49 | 0.81 | 1.63 |
| | Extra European
markets | 2.06 | 2.60 | 6.24 |
| | E&P in
Europe and in the Gulf of Mexico | 6.17 | 5.65 | 2.86 |
| | WORLDWIDE GAS SALES | 103.72 | 97.06 | 96.76 |

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| Marketing strategy: planned actions |
| --- |
| In
spite of a challenging market environment and rising
competitive pressures, over the next four years we intend
to strengthen our leading position in the European gas
market targeting to gradually recover profitability by
leveraging on the following initiatives: n on the supply side, we intend to
improve the competitiveness of our supply portfolio which
is the key factor to cope with the ongoing market
downturn and regain profitability once the European
market tightens. We believe that our supply portfolio
has: - to be competitive with spot prices; - to be flexible on take or pay volumes; and - to give both suppliers and buyers the option to
renegotiate more frequently if required by market
conditions. We have already made good progress on this
front. In the last two years, we have closed contract
renegotiations with the Libyan NOC, Sonatrach and, in
recent weeks, with Gazprom, which between them account
for almost 70% of our supply portfolio. Looking forwards,
we will continue to work on the competitiveness and
market reflectivity of our portfolio. We plan to open
negotiations with other of our suppliers in the second
part of 2012; n on the commercial side of our
equation we intend: - to consolidate our leading European position in the
business gas market, where we have a well balanced
portfolio in terms of geographies, customer segments and
contract durations. Over the plan period, we will drive
sales and market share gains by leveraging on the
multiple presence in a number of markets, the development
of a pan-European commercial platform, |

| In Europe, most of the
expected growth will be achieved in: n Germany/Austria , where Eni is
present through its affiliate GVS (Gasversorgung
Süddeutschland GmbH - Eni 50%), and a direct marketing
structure. We plan to drive growth in direct sales
leveraging on the quality of our commercial offer; n Benelux (Belgium, the Netherlands
and Luxembourg), where we will seek to strengthen our
leading position granted by the integration with
operations of Distrigas and of the recently acquired
Nuon, as well as to extract value from our logistics
assets and our presence at the continental hubs; n France , where we plans to expand
sales by growing volumes supplied to the business
segments and increasing retail customers leveraging on
the Altergaz integration and our direct commercial
presence; and n Turkey , where Eni is supplying
gas in joint venture with Gazprom to the local company
Bota through the Blue Stream pipeline. Gas is carried
from Russia across the Black Sea. |
| --- |
| Supply |
| In order to secure long-term access to gas availability,
particularly with a view of supplying the Italian gas
market, Eni has signed a number of long- |

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| bcm of gas availability from
2010. Our contract portfolio has a residual life of
approximately 17 years and a pricing mechanism that
indexes the cost of gas to the price of crude oil and its
derivatives (gasoil, fuel oil, etc.). In 2011, Enis consolidated subsidiaries supplied
83.38 bcm of natural gas, representing an increase of
0.89 bcm, or 1.1% from 2010. | In addition, we
currently operate certain photovoltaic sites in Italy. We have an installed power capacity equal to 5.3
gigawatts 1 , and we plan a further capacity
expansion, targeting a fully operational capacity of 5.4
GW by 2016. Supplies of natural gas are expected to
amount to approximately 6 bcm/y from Enis
diversified supply portfolio. In the next four years we plan to complete the capacity
upgrading at the Ferrara, Bolgiano and Taranto sites and
to improve efficiency and flexibility of our facilities.
We are planning to retain an index of GHG emissions below
the target level of 415 gCO 2 /kWheq. We are
also planning to build a biomass power plant in Sardinia,
Italy, to complement the conversion of the Porto Torres
site into an innovative bio-based chemical complex. |
| --- | --- |
| LNG | |
| Eni is present
in all phases of the LNG business: liquefaction,
shipping, re-gasification and sale through operated
activities or interests in joint ventures and associates.
Enis presence in the business is tied to the
Companys plans to develop its large gas reserve
base in Africa and elsewhere in the world. The LNG
business has been deeply impacted by the economic
downturn and oversupply affecting the European gas
market, as well as by structural modifications in the US
market where large availability of gas from
unconventional sources has reduced the Countrys
dependence on gas imports via LNG. At present, we participate through our affiliates in a
number of facilities located in Spain (regasification)
and Egypt (liquefaction). The Company has also access to
LNG supplies in Algeria and Qatar. Our main ongoing
interest in the LNG business is the joint Pascagoula
project with our Exploration & Production business
which is targeting the US market. The Pascagoula project envisages construction of
an LNG plant in Angola designed to produce 5.2 mmtonnes
of LNG (approximately 7.3 bcm/y) destined to the North
American market in order to monetize part of the
Companys gas reserves. As part of the downstream
leg of the project, Eni signed a 20 year contract with
Gulf LNG to buy 5.8 bcm/y of the re-gasification capacity
at the Pascagoula plant in Mississippi. The start-up of
the re-gasification facility commenced in the fourth
quarter of 2011, while the upstream project in Angola
will start operations nextly. | Regulated businesses in Italy |
| | Eni,
through Snam SpA (Enis interest being 52.53%), a
company listed on the Italian Stock Exchange, operates
most of the Italian natural gas transport network, a
re-gasification terminal located in Panigaglia, an
extensive grid of local distribution networks and gas
underground storage deposits and related facilities. In the next four years, Snam plans to make capital
expenditures in the regulated businesses in the amount of
approximately euro 6.7 billion of which 1.4 billion will
be spent in 2012. These investments will be aimed at
improving the security and flexibility of the gas system,
by: (i) increasing gas transport capacity by adding
approximately 1,000 kilometers of new lines to the
existing 32,000 kilometer-long network as at end of 2011
and by increasing the installed power of the compression
stations by around 4% versus 2011; and (ii) improving the
overall flexibility and security of the storage system
through an increase in both the modulation and peak
capacity and providing storage services to the industrial
market. |

| Power generation |
| --- |
| Enis power generation sites are located in the
Italian spots of Ferrera Erbognone, Ravenna, Livorno,
Taranto, Mantova, Brindisi, Ferrara and Bolgiano where we
have implemented a plan of capacity upgrading by
installing new plants for the combined production of
steam and electricity. |

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

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| to the level required for
its flow; and (ii) four marine terminals linking
underwater pipelines with the on-land network at Mazara
del Vallo and Messina in Sicily and Favazzina and Palmi
in Calabria. In 2011, volumes of natural gas input in the
national grid (78.30 bcm) decreased by 5.01 bcm from 2010
due to declining domestic demand. Distribution Snam through Italgas and other subsidiaries operates
in the distribution activity in Italy, which involves the
delivery of natural gas to residential and commercial
customers in urban centers, serving 1,330 municipalities
through a low pressure network consisting of
approximately 50,300 kilometers of pipelines supplying
5.9 million customers and distributing 7.64 bcm in 2011. Storage Snam through Stogit, is the leading Italian operator
and one of the major operators in this sector in Europe.
Stogit provides storage and modulation services, pursuing
technical and economic efficiency, on the basis of the
concessions granted by the Italian Ministry of Economic
Development. Storage operations are provided through
depleted gas fields and proper infrastructures and
facilities such as treatment and compression plants, and
connections to the national transport network. Access to
the gas storage service enables suppliers to configure
their supplies in order to effectively manage seasonal
patterns in gas consumption. Stogit, with its eight
storage fields distributed throughout Italy can provide
the market with an integrated system that ensures the
flexibility requested by suppliers, in line with
available storage capacity. In 2011, 7.78 bcm (down 0.22
bcm from 2010) were input to the Companys storage
deposits, while 7.53 bcm of gas were off-taken (slightly
lower than one year ago). In 2011, storage capacity
amounted to 15 bcm, of which 5 were destined to strategic
storage. The share of storage capacity used by third
parties was 78% (71% in 2010). Snam is planning to update
the flexibility and security of the storage system
through an increase in both modulation and peak capacity
and providing storage services to the industrial market. |
| --- |
| International transport |
| n INTERNATIONAL TRANSPORT Eni owns capacity entitlements in an extensive
network of international high pressure pipelines enabling
the Company to import natural gas produced in Russia,
Algeria, the North Sea (including the Netherlands and
Norway), and |

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2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 3.18 | | 1.77 | | 2.02 | |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 4.35 | | 3.59 | | 3.21 | |
| Net sales from operations (a) | (euro million) | 31,769 | | 43,190 | | 51,219 | |
| Operating
profit | | (102 | ) | 149 | | (273 | ) |
| Adjusted operating profit | | (357 | ) | (171 | ) | (535 | ) |
| Adjusted
net profit | | (197 | ) | (49 | ) | (262 | ) |
| Capital expenditures | | 635 | | 711 | | 866 | |
| Adjusted
capital employed, net at year end | | 7,560 | | 7,859 | | 8,600 | |
| Adjusted ROACE | (%) | (2.6 | ) | (0.6 | ) | (3.1 | ) |
| Refinery
throughputs on own account | (mmtonnes) | 34.55 | | 34.80 | | 31.96 | |
| Conversion index | (%) | 60 | | 61 | | 61 | |
| Balanced
capacity of refineries | (kbbl/d) | 747 | | 757 | | 767 | |
| Retail sales of petroleum products in Europe | (mmtonnes) | 12.02 | | 11.73 | | 11.37 | |
| Service
stations in Europe at year end | (units) | 5,986 | | 6,167 | | 6,287 | |
| Average throughput per service station in Europe | (kliters) | 2,477 | | 2,353 | | 2,206 | |
| Retail
efficiency index | (%) | 1.61 | | 1.53 | | 1.50 | |
| Employees at year end | (units) | 8,166 | | 8,022 | | 7,591 | |
| Direct GHG
emissions | (mmtonnes CO 2 eq) | 7.29 | | 7.76 | | 7.23 | |
| SO x (sulphur oxide) emissions | (ktonnes SO 2 eq) | 21.98 | | 28.05 | | 23.07 | |
| NO x (nitrogen oxide) emissions | (ktonnes NO 2 eq) | 7.35 | | 7.96 | | 6.74 | |
| Water consumption rate/oil and intermediate
throughputs | (cm/tonnes) | 35.99 | | 28.36 | | 31.07 | |
| Customer
satisfaction index | (likert scale) | 7.93 | | 7.84 | | 7.74 | |

i	i	ii
(a)	i	Before
elimination of intragroup sales.
i	i	i

2011 Highlights

Financial and operating results In 2011, our Refining & Marketing Division reported sharply lower adjusted operating losses at minus euro 262 million. The performance was hit by unprofitable refining margins due to rising costs for oil-based feedstock and energy utilities that could not be transferred to prices at the pump pressured by weak demand and excess capacity in the Mediterranean basin. We continued upgrading our network of retail stations by rebranding, our outlets to the "eni" logo and improving quality standards and layout. Since the start of the program in 2010, 1,700 stations have been rebranded. Effective marketing actions helped us preserve our market share at 30.5% of the domestic consumption of fuels. Capital expenditure of euro 866 million related mainly to projects designed to improve the conversion capacity and flexibility of refineries, logistics, upgrade of the fuel distribution network in Italy and in the rest of Europe and initiatives in the field of health, safety and the environment. In spite of a weak outlook for refining margins, management plans to improve results of the Refining & Marketing Division by over euro 550 million by 2015 through efficiency improvements and plant optimizations.

Strategies

We refine and market fuels and other oil products primarily in Italy and Central-Eastern European countries. We are the largest refiner in Italy and the leading operator in the retail marketing of fuels with a market share of 30.5%. Our refining and marketing operations are fully integrated also through the support of a valuable set of logistic assets so as to maximize cost efficiencies. Supply of crude feedstock to our refineries and trading of product deficits/surpluses are ensured by our affiliate Eni Trading & Shipping. Our Refining & Marketing business has delivered poor results in recent years driven by a weak trading environment. High purchase costs for crude feedstock and oil-linked energy expenses have squeezed refining margins as product prices have lagged behind cost increases due to sluggish demand and excess capacity. At the same time our complex processes have been suffering from narrowing spreads between sour and sweet crudes. The outlook for the next four years remains challenging as we expect that refining margins will stage only

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| a modest recovery from currently depressed levels.
Against this backdrop, we intend to return to
profitability and positive free cash flow generation
targeting to improve our operating results by around euro
550 million by 2015 assuming a constant trading
environment. The levers to achieve this target are
continuing efficiency improvements, plant optimizations
and selective capital expenditures to expand margins in
our refining operations. In marketing we intend to
consolidate the profitability of our operations mainly
through network upgrading, expansion of our non-oil
activities and growing selectively outside Italy. Our strategic guidelines are: n Improve profitability of our refining
business leveraging on efficiency and optimization n Consolidate our leading position in
the Italian retail market n Selectively develop our presence
outside Italy n Pursue safe and reliable operations In the 2012-2015 period, we plan to make capital
expenditures amounting to euro 2.8 billion, in line with
the previous plan, carefully selecting capital projects.
Management plans to invest approximately euro 2 billion
to upgrade the Companys best refineries mainly by
completing and starting-up the EST (Eni Slurry
Technology) project at the Sannazzaro unit which will
upgrade the conversion capacity of the refinery, as well
as improving plant efficiency, flexibility and
reliability. Retail activities will attract some 25% of
the planned expenditure which will be mainly directed to
upgrade and modernize our service stations in Italy and
in selected European Countries, and to complete the
network rebranding. |
| --- |
| . n Industry trends In recent years, our refining activity has suffered
from an industry-wide downturn due to surging costs for
oil feedstock and energy utilities, poor demand for
refined products in the face of an economic slowdown and
excess capacity. Furthermore, the profitability of our
complex refineries was negatively impacted by narrowing
price differentials between sweet and sour crude
qualities. As a result of those trends, refining margins
have plunged to historical lows. Looking forward, we anticipate that a sector recovery
will not materialize until 2014 or 2015 as macroeconomic
uncertainties are expected to weigh on demand for fuels
and high costs for oil and energy utilities continue to
pressure refining margins. In the meantime, the industry
will undergo an unavoidable restructuring process to
eliminate marginal and obsolete refineries and rebalance
an ongoing surplus of gasoline with a shift vs. higher
yields of middle distillates. Over the long-term, we
expect that refining margins will stage a gradual
recovery across Europe and in the Mediterranean basin due
to the reopening of spreads between sweet and sour crudes
and a devaluation of fuel oil on the marketplace due to
increasingly strict environmental regulations,
particularly in the sector of power generation where fuel
oil is expected to be progressively replaced by gas as
well as in bunker consumption where new rules will
mandate the use of middle distillates. n Planned actions In the face of a weak market outlook and high and
volatile oil costs, we intend to implement all the
necessary actions and initiatives to restore the
profitability of our refining operations by: - pursuing integration of refinery cycles in order to
maximize the value of internally-produced semi-finished
products and other feedstock; - maximizing refinery flexibility and conversion to take
advantage of the availability of discounted crudes on the
marketplace. The start-up of our Eni Slurry Technology
conversion unit at the Sannazzaro refinery will
significantly upgrade our system and ability to process
heavy and extra-heavy crudes; - improving energy efficiency and plant safety and
reliability; - reducing fixed costs by rationalizing logistics and
pursuing other cost measures in maintenance, fixed
industrial expenses and labor; - strictly selecting capital expenditures; and - boosting margins leveraging on risk management
activities. |

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| n Our assets ITALY Enis refining system in Italy consists of five
wholly-owned refineries and a 50% interest in the Milazzo
refinery in Sicily. Each of Enis refineries in
Italy have operating and strategic features that aim at
maximizing the value associated to the asset structure,
the geographic positioning with respect to end markets
and the integration with Enis other activities. SANNAZZARO : the refinery has balanced
refining capacity of 190 kbbl/d and a conversion index of
59%. Management believes that this unit is among the most
efficient refineries in Europe. Located in the Po Valley,
it supplies markets in North-Western Italy and
Switzerland. The high degree of flexibility and
conversion capacity of this refinery enables to process a
wide range of feedstock. From a logistical standpoint
this refinery is located along the route of the Central
Europe Pipeline, which links the Genoa terminal with
French speaking Switzerland. This refinery contains two
primary distillation plants and relevant facilities,
including three desulphurization units. Conversion is
obtained through a fluid catalytic cracker (FCC), two
hydrocrackers (HdCK), which enable middle distillate
conversion and a visbreaking thermal conversion unit with
a gasification facility using the heavy residue from
visbreaking (tar) to produce syn-gas to feed the nearby
EniPower power plant at Ferrera Erbognone. Eni is
developing a conversion plant employing the Eni Slurry
Technology with a 23 kbbl/d capacity for the processing
of extra heavy crude with high sulphur content producing
high quality middle distillates, in particular gasoil,
and reducing the yield of fuel oil to zero. Start-up of
this facility is scheduled by the end of 2012. In
addition the Short Contact Time-Catalytic Partial
Oxidation project is underway for the production of
hydrogen. TARANTO : the refinery has balanced refining
capacity of 120 kbbl/d and a conversion index of 72%.
This refinery can process a wide range of crude and other
feedstock. It principally produces fuels for automotive
use and residential heating purposes for the Southern
Italian markets. Besides its primary distillation plants
and relevant facilities, including two units for the
desulphurization of middle distillates, this refinery
contains a two-stage thermal conversion plant
(visbreaking/thermal cracking) and an RHU conversion
plant for the conversion of high sulphur content residues
into valuable products and catalytic cracking feedstocks.
It processes most of the oil produced in Enis Val
dAgri fields carried to Taranto through the Monte
Alpi pipeline (in 2011, a total of 2.5 mmtonnes of this
oil were processed). GELA : the refinery has balanced refining capacity
of 100 kbbl/d and a conversion index of 142%. This
refinery is located on the Southern coast of Sicily and
is integrated with upstream operations as it processes
heavy crude produced from Enis nearby offshore and
onshore fields in Sicily. Its high conversion level is
ensured by an FCC unit with go-finer for feedstocks
upgrading and two coking plants enabling conversion of
heavy residues topping or vacuum residues. The power
plant of this refinery also contains residue and exhaust
fume treatment plants (so-called SNOx) which allow full
compliance with the tightest environmental standards,
removing almost all sulphur and nitrogen composites
coming from the coke burning-process. An upgrade of the
Gela refinery is underway by means of a refurbishment of
its power plant, substantially renewing pet-coke boilers,
aimed at increasing profitability maximizing synergies
deriving from the integration of refining and power
generation. OUTSIDE ITALY In Germany, Eni holds an 8.33% interest in the Schwedt refinery and a 20% interest in Bayernoil , an
integrated pole that includes the Vohburg and Neustadt
refineries. Enis refining capacity in Germany
amounts to approximately 60 kbbl/d mainly used to supply
Enis distribution network in Bavaria and Eastern
Germany. In the Czech Republic, Eni holds a 32.4%
interest in the Ceska Rafinerska pole, which includes two
refineries, Kralupy and Litvinov .
Enis share of refining capacity amounts
approximately to 53 kbbl/d. n Operational efficiency and
environmental performance Eni intends to continue pursuing high levels of
operational efficiency and environmental performance at
its refineries. Energy saving programs will be |
| --- |
| Logistics |
| Eni is a primary operator in storage and transport of
petroleum products in Italy with its logistical
integrated infrastructure consisting of 20 directly
managed storage sites and a network of petroleum product
pipelines for the sale and storage of refined products,
LPG and crude. Enis logistics model is organized in
a hub structure on five main areas. These hubs monitor
and centralize the handling of product flows aiming at
driving cost savings by efficiently collecting orders and
delivering goods. |
| Marketing |
| We are the leader in the retail marketing of refined
products in Italy with a 30.5% market share. We market a
wide range of refined petroleum products, through an
extensive network of operated service stations,
franchises and other distribution systems. We intend to consolidate our lead in the Italian retail
market by continuing investments in network upgrading and
modernization, as well as improving quality standards and
layout of our outlets. As part of this strategy, we plan
to complete our network rebranding and restyling, to
increase the automation of stations and to expand non-oil
activities under the "eni" brand. Outside Italy, we intend to continue growing our share in
the markets of interest to the Company while assessing a
possible divestment of marginal activities. n Retail - Italy In 2011, the re-branding of Enis service
stations continued. We plan that by the end of 2012 80%
of our proprietary service stations will have been
re-branded to the "eni brand". In the context
of weak domestic demand for fuels and rising competition,
management plans to preserve the market share achieved in
2011 (30.5%). This target factors in a planned reduction
of approximately 500 outlets. We expect that effective
marketing campaign, the development of the non-oil
offering and continuing network upgrading will underpin
our market share and client retention. We will continue
leveraging |

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on our successful promotional initiative "you&eni", a fidelity program which rewards the most loyal customers with prizes commensurated to their purchases of fuels and convenience items. The "you&eni" cards that made at least one transaction in the year were approximately 6.5 million at December 31, 2011, while the average number of active cards was approximately 2.6 million on a monthly basis. Volumes sold under the fidelity program represented approximately 39% of total throughputs. In 2011, retail sales in Italy of 8.36 mmtonnes decreased by approximately 270 ktonnes, down 3.1% driven by lower consumption of gasoil and gasoline, in particular in highway service station related to the decline in freight transportation. At December 31, 2011, Enis retail network in Italy consisted of 4,701 service stations, 159 more than at December 31, 2010 (4,542 service stations).

n Retail - outside Italy Enis strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany and Eastern Countries (e.g. Czech Republic) leveraging on the synergies ensured by the proximity of these markets to Enis production and logistic facilities. In 2011, retail sales of refined products marketed in the rest of Europe (3.01 mmtonnes) were down 2.9% (approximately 90 ktonnes) from 2010. Volume additions in Austria, reflecting the purchase of service stations, were offset by lower sales in Germany due to certain lease contract terminations, in France due to the rationalization of service stations with lower throughput and in Eastern Europe due to declining demand. At December 31, 2011, Enis retail network in the rest of Europe consisted of 1,586 units. n Non-oil Non-oil activities have become an integral part of our retail business. We have been upgrading our offering of non-oil products and services by carefully selecting our partners and improving quality and reach of the offering. Our most important service stations in Italy are equipped with franchised outlets, which market a wide range of food items, services and other merchandise. We have two main format: " enicafé ", a format which is present at 350 stations following upgrading of bars and stores; " enicafé&shop ", a format including corners for the sale of food and car-care products in 200 Eni outlets. In 2011 Eni also launched a new self-service option h24 of food, non-food and personal care products by installing Eni branded vending machines in 150 outlets with the aim of extending this service to over 1,000 outlets in the next two years. Non-oil activities in the rest of Europe are present in 1,101 service stations (Eni owned network), of which 321 are in Germany and 144 in France. n Wholesale and other businesses Fuels Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Along with traditional products provided with the high quality Eni standard, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and concessionaires. In 2011, sales volumes on wholesale markets in Italy (9.36 mmtonnes) were down by approximately 90 ktonnes from 2010, or 1%, mainly reflecting a decline in demand from transportations and industrial customers due to economic slowdown and strong competitive pressure which particularly affected bunkering and bitumen, but also LPG due to unusual weather conditions. Jet fuel and fuel oil sales increased, while gasoil sales dropped starkly in 2011. Enis wholesale market share for 2011 averaged 28.3%, down 0.9 percentage points from 2010 (29.2%). LPG In Italy, Eni is leader in LPG production, marketing and sale with 601 ktonnes sold for heating and automotive use equal to a 18.9% market share. An additional 214 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. Outside Italy, LPG sales in 2011 amounted to 485 ktonnes of which 384 ktonnes in Ecuador where LPG market share is around 37.5%. Lubricants Eni operates seven (owned and co-owned) blending plants, in Italy, Europe, North and South America and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state-of-the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). Oxygenates Eni, through its subsidiary Ecofuel (Enis interest 100%), sells approximately 1.7 mmtonnes/y of oxygenates mainly ethers (approximately 5.3% of world demand) and methanol (approximately 0.9% of world demand). About 80% of products are manufactured in Italy in Enis plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 20% is bought and resold. Eni also distributes bio-ETBE on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio-ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. Starting from March 1, 2010, Italian regulation on bio-fuels content has been changed from 3% to 3.5%. Through bio-ETBE and FAME blending into fossil fuels Eni covered the compliance within 96% in 2011. From January 1, 2012, the compulsory content of bio-fuels has increased to 4.5% from 2011 4%. Eni is addressing the new need through bio-ETBE, FAME and direct blending of ethanol in gasolines.

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2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 2.34 | | 1.54 | | 1.47 | |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 8.12 | | 5.94 | | 4.60 | |
| Net sales from operations (a) | (euro million) | 4,203 | | 6,141 | | 6,491 | |
| Basic
petrochemicals | | 1,832 | | 2,833 | | 2,987 | |
| Polymers | | 2,185 | | 3,126 | | 3,299 | |
| Other
sales | | 186 | | 182 | | 205 | |
| Operating profit | | (675 | ) | (86 | ) | (424 | ) |
| Adjusted
operating profit | | (426 | ) | (113 | ) | (276 | ) |
| Adjusted net profit | | (340 | ) | (85 | ) | (208 | ) |
| Capital
expenditures | | 145 | | 251 | | 216 | |
| Production | (ktonnes) | 6,521 | | 7,220 | | 6,245 | |
| Sales of
petrochemical products | | 4,265 | | 4,731 | | 4,040 | |
| Average plant utilization rate | (%) | 65.4 | | 72.9 | | 65.3 | |
| Employees
at year end | (units) | 6,068 | | 5,972 | | 5,804 | |
| Direct GHG emissions | (mmtonnes CO 2 eq) | 4.63 | | 4.69 | | 4.12 | |
| NMVOC
(Non-Methane Volatile Organic Compounds) emissions | (tonnes) | 3.83 | | 4.71 | | 4.18 | |
| SO x (sulphur oxide) emissions | (ktonnes of SO 2 eq) | 4.59 | | 3.30 | | 3.18 | |
| NO x (nitrogen oxide) emissions | (ktonnes of NO 2 eq) | 4.78 | | 4.87 | | 4.14 | |
| Recycled/reused water | (%) | 81.6 | | 82.7 | | 81.8 | |

i	i	ii
(a)	i	Before
elimination of intragroup sales.
i	i	ii

2011 Highlights

In 2011 injury rates of employees and contractors continued to follow the positive trends of previous years (down 4.5% and 22.6%, respectively). In 2011 emissions of greenhouse gases NMVOC, NO x and SO x decreased due to lower sale volumes and to energy saving interventions performed in the year. In 2011 the percentage of reused water was approximately 80%, barely unchanged from previous years. In 2011 the sector reported a significant increase in adjusted net loss (euro 208 million, up euro 123 million) from 2010, due to higher supply costs of oil-based feedstock which were not recovered in sale prices on end markets in a context of substantial decrease in demand. Sales of petrochemical products were 4,040 ktonnes, down 691 ktonnes, or 14.6%, from 2010 due to lower demand. Petrochemical production volumes were 6,245 ktonnes, decreasing by 975 ktonnes, or down 13.5%, due to a decline in demand for petrochemical products in all business, with the only exception of elastomers (up 1%). In 2011, the average plant utilization rate decreased from 72.9 to 65.3 due to reduced production in a phase of economic slowdown. In 2011 overall expenditure in R&D amounted to approximately euro 32 million in line with the previous year. A total of new 13 patent applications were filed. On April 5, 2012 Polimeri Europa changed its name in Versalis SpA.

Strategies

Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and Western Europe. The trading environment in which the Company operates is characterized by volatility of costs of oil-based feedstock, cyclicality in demand, strong competitive pressures from operators with lower cost structure especially in the Middle-East leveraging on stranded gases, taking into account the commoditized nature of many of Enis products. In fact, Enis profitability

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Eni in 2011 Business review / Petrochemicals

in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. In order to change this challenges in the future years the Company will pursue the following strategic pillars: n Effectively and efficiently manage operations in order to lower the break-even n Strengthen the production of higher value added products n Leverage on international expansion n Focus on green-chemistry To target those objectives, management plans to make capital expenditures amounting to approximately euro 1.7 billion over the next four years. The main investment regards the conversion of the Porto Torres unit in Sardinia, Italy, into an innovative bio-based chemical complex to produce bio-plastics and other bio-based chemical products for which significant growth is expected in the medium-long term. In addition, the Company plans to develop the product line in the elastomers and monomers businesses, revamp the efficiency of the Companys cracking units as well as complying with all applicable regulations on environment, health and safety issues. Management is planning to implement a strategy intended to refocusing the petrochemical business, strengthening the product mix of the Company by developing higher value added products, particularly in the businesses of elastomers, styrenics, resins, EVA and entering into bio-based chemical production. In the next years products demand in those higher value-added segments is planned to grow and margins to be resilient also with higher feedstock prices. Management expects sales of higher value added products to improve by 50% within 2015, with a contribution on total sales amounting to 40% and to deliver euro 400 million of additional operating profit by 2015 at the scenario experienced in 2011.

| Business areas |
| --- |
| n Basic petrochemicals Basic petrochemicals accounts for one of the pillars
of the petrochemical activities of Versalis, whose
products have a range of important industrial uses, such
as the production of polyethylene, polypropylene and
polystyrene. They are also used in the production of
petrochemical intermediates that converge, in turn, into
a range of other productive processes: plastics, rubbers,
fibers, solvents and lubricants. Basic petrochemicals revenues (euro 2,987 million)
increased by euro 154 million from 2010 (up 5.4%) in all
main business segments due to the steep increase in
average unit prices (olefins/aromatics up 20%,
intermediates up 16%) as a result of an improved
scenario, partly offset by lower volumes sold (down 18%
on average). In particular, a decline was reported in
sales volumes of olefins (ethylene down 22%; butadiene
down 57% due to the lack of raw material) and
intermediates (down 21% on average, in particular phenol
and acetone). |

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2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 0.40 | 0.45 | 0.44 |
| --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 0.57 | 0.33 | 0.21 |
| Fatality index | (No. of fatalities per
100 million hours worked) | 0.86 | 2.14 | 1.82 |
| Net sales
from operations (a) | (euro million) | 9,664 | 10,581 | 11,834 |
| Operating profit | | 881 | 1,302 | 1,422 |
| Adjusted
operating profit | | 1,120 | 1,326 | 1,443 |
| Adjusted net profit | | 892 | 994 | 1,098 |
| Capital
expenditures | | 1,630 | 1,552 | 1,090 |
| Adjusted ROACE | (%) | 15.4 | 14.0 | 13.9 |
| Orders
acquired | (euro million) | 9,917 | 12,935 | 12,505 |
| Order backlog | | 18,730 | 20,505 | 20,417 |
| Employees
at year end | (units) | 35,969 | 38,826 | 38,561 |
| Employees outside Italy rate | (%) | 85.6 | 87.3 | 86.5 |
| Local
managers rate | | 41.1 | 45.3 | 43.0 |
| Local procurement rate | | 47.0 | 61.3 | 56.4 |
| Healthcare
expenditures | (euro thousand) | 25,205 | 19,506 | 32,410 |
| Security expenditures | | 68,954 | 26,403 | 50,541 |
| Direct GHG
emissions | (mmtonnes CO 2 eq) | 1.28 | 1.11 | 1.32 |

i	i	ii
(a)	i	Before
elimination of intragroup sales.

2011 Highlights

The percentage of managerial positions covered by local personnel is constantly higher than 40% of total managerial positions, except for Italy and France, reflecting however fluctuations due to the opening of new yards and short-term projects. The overall amount of procurement was euro 8,740 million in 2011, of which euro 6,510 million related to operating projects, 56.4% of which was procured with local suppliers. In 2011 the injury frequency rate improved from 2010 (down 2% and down 36% for employees and contractors, respectively). Health and safety expenditures for individual protection equipment and medical assistance increased by 81% from 2010 (from euro 46 million to euro 83 million). In 2011 the Engineering & Construction sector achieved a positive performance with an adjusted net profit amounting to euro 1,098 million, up euro 104 million, or 10.5%, from a year ago, mainly due to a higher turnover and increasing project profitability. Return on average capital employed calculated on an adjusted basis was 13.9% in 2011 (14% in 2010). Orders acquired amounted to euro 12,505 million (euro 12,935 million in 2010), of these projects to be carried outside Italy represented 91%, while orders from Eni companies amounted to 7% of the total. Order backlog amounted to euro 20,417 million at December 31, 2011 (euro 20,505 million at December 31, 2010), of which euro 9,451 million to be carried out within 2012. Capital expenditures amounting to euro 1,090 million (euro 1,552 million in 2010) mainly regarded the upgrading of the drilling and construction fleet. In 2011 overall expenditure in R&D amounting approximately to euro 15 million in line with 2010. A total of 28 new patent applications were filed.

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Eni in 2011 Business review / Engineering & Construction

| ● |
| --- |
| Strategies |
| Eni engages in providing engineering, construction and
drilling to the oil&gas industry offshore and onshore
through Saipem, a subsidiary listed on the Italian Stock
Exchange (Enis interest is 42.91%), and
Saipems controlled entities. Saipem boasts a strong
competitive position in the segment of executing large,
complex EPC contracts for the construction of offshore
and onshore facilities and systems to develop
hydrocarbons reserves as well as LNG, refining and
petrochemicals plants, pipeline layering and offshore and
onshore drilling services. The Company owes its market
position to technological and operational skills which we
believe are acknowledged in the marketplace due to its
capabilities to operate in frontier areas and complex
ecosystems, efficient and effective project management
complemented by engineering competencies and availability
of technologically-advanced vessels and rigs. Management
expects to further strengthen Saipems competitive
position in the |

Business areas

n Engineering & Construction Offshore Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies ("NOCs"). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage and integrating the direct management of construction processes through the creation of a large construction yard in South-East Asia. Over the next years, Saipem will continue investing in the upgrading of its fleet by building a pipelayer and other supporting assets for offshore activity. In 2011 revenues amounted to euro 4,908 million, increasing by 10.4% from 2010, due to higher levels of activity in Northern Europe, Kazakhstan and Asia Pacific. Orders acquired amounted to euro 6,131 million (euro 4,600 million in 2010). The most significant orders awarded in 2011 in Engineering & Construction offshore were: n An EPIC contract on behalf of South Oil Co for the expansion of the Basra oil center and related infrastructures within of the Iraq Crude Oil Export Expansion - Phase 2 project; n An EPIC contract on behalf of Saudi Aramco for building the offshore infrastructures within the development of the offshore fields Arabiyah and Hasbah in the Arabian section of the Persian Gulf; and n An EPIC contract on behalf of Husky Oil China Ltd for the installation of two 79-kilometer long pipelines and umbilicals as well as the construction of a subsea production system for the development of Liwan 3-1 field in water depths of 1,500 meters in the South China Sea. n Engineering & Construction Onshore Saipem is one of the largest operators in the segment of turn-key onshore construction contracts for the Oil & Gas industry. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection)

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Eni in 2011 Business review / Engineering & Construction

and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transportation systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness leveraging its technological excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, exploiting upward trends in the oil service market, Saipem will be focused on capturing the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the execution of complex projects in the strategic areas of Middle-East, Caspian Sea, Northern and Western Africa and Russia. In 2011 revenues amounted to euro 5,369 million, increasing by 13.6% from 2010, due to higher levels of activity in the Middle East, Canada and Australia. Orders acquired amounted to euro 5,006 million (euro 7,744 million in 2010). The principal orders awarded in 2011 in Engineering & Construction Onshore were: n The construction of 39 kilometers high-speed/high-capacity railway along the Treviglio-Brescia railway in Northern Italy on behalf of Rete Ferroviaria SpA; n An EPC contract for the construction of a Secondary Upgrader with a capacity of 43 kbbl/d of Hydrotreated gas oil. The infrastructure will be part of the Horizon Oil Sands Project Hydrotreater Phase 2 in Alberta, in the Athabasca Region, Canada; and n The EPC contract for the realization of a gas pipeline, 42 inches in diameter and 435-kilometer long, which will connect the gas fields in the Bowen and Surat Basins to the Gladstone State Development Area (GSDA), near the city of Gladstone, in the Western Australian coast on behalf of Gladstone Operations Pty Ltd. n Offshore drilling Saipem is the only engineering and construction contractor that provides both offshore and onshore drilling services to oil companies. In the offshore drilling segment, Saipem mainly operates in West Africa, the North Sea, the Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum water depth of 9,200 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-the-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In particular, in the following years, Saipem intends to complete the building of the Scarabeo 8 and 9, new generation semi-submersible platforms, that have been already rented to Eni through multi-year contracts. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment). In 2011 revenues amounted to euro 833 million, increasing by 11.1% from 2010 mainly due to the entry in full activity of the Saipem 10000 and Saipem 12000 drilling vessels and of the Perro Negro 8 jack up. The most significant order awarded in 2011 in offshore drilling were: n A 24-month extension contract, from August 2012, for the lease of the drilling vessel Saipem 10000 on behalf of Eni; n A 24-month extension contract, from August 2015, for the lease of the drilling vessel Saipem 12000 on behalf of Total E&P Angola; and n A 36-month extension contract for the lease of the jack-up Perro Negro 7 on behalf of Saudi Aramco. n Onshore drilling Saipem operates in this area as a main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this area Saipem can leverage its knowledge of the market,

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Eni in 2011 Business review / Engineering & Construction

long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments. In 2011 revenues amounted to euro 724 million, increasing by 9.5% from 2010 mainly due to higher utilization of equipments in South America and entry in operation of new plants in Kazakhstan. Orders acquired amounted to euro 588 million (euro 265 million in 2010). The most significant order awarded in 2011 in Onshore drilling were: n A contract on behalf on Saudi Aramco in Saudi Arabia for the lease of nine rigs with a contract duration from one to three years; n Contracts on behalf of various clients in Peru, Colombia and Bolivia for the lease of fourteen rigs with a contract duration between 4 months and 2 years; n Two contracts on behalf of Ural Oil and Samek for the lease of 2 rigs with a contract duration of 4 and 12 months, respectively.

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| Technological
research and development ("R&D") and
continuous innovation represent key success factors in
implementing Enis business strategies as they
support our long-term competitive performance. The Company believes that the oil industry has to face a
number of challenges in the near future and that
technology will play a vital role in helping it to
effectively manage them. In particular: n continuing uncertainty about the future
evolution of prices and demand for oil and gas; n limited access to new hydrocarbon
resources, with the consequent problems for production
growth and reserve replacement; n a growing importance of renewable
sources in satisfying energy need, as well as the role of
unconventional resources; and n greater attention to operations safety
in the aftermath of recent accidents in the industry. Against this backdrop, management has identified key
technology priorities: continued technological innovation to increase the
recovery factor; to develop drilling technologies to be
applied in complex environments and deep/ultra-deep
offshore areas; to maximize asset value, especially for
gas and marginal fields and by reducing time-to-market; implementation of new technologies to minimize the
environmental footprint of Enis operations,
actively manage risks to employees and communities
health and safety; develop technologies to reduce Greenhouse gas
emissions in industrial operations with particular
reference to energy efficiency, gas flaring reduction and
CO 2 use; focusing on innovative fuels and bio-fuels
enhancing performance and environmental quality to
anticipate stricter regulation; commitment to develop a potentially breakthrough
technologies in the renewable energy (solar and
bio-mass). The relevant results achieved in certain
research projects, enable us to start up the application
phase; strengthening of strategic alliances and
scientific cooperation projects with international
academic institutions and research centers which we
believe are qualified in the marketplace. In 2011, Eni filed 79 patent applications (88 in 2010),
37 of these coming from Eni Divisions and Eni Corporate,
13 from Petrochemicals and 28 from the Engineering &
Construction activities of Saipem. In particular, 51% of
Eni Divisions and Eni Corporate patents concerned
exploration activities of unconventional resources,
maximizing the recovery factor, transportation and
products/processes in the downstream oil segment and 41%
were innovation on renewable energy sources. The efficacy
and efficiency of intellectual property management and of
know-how dissemination are monitored within the R&D
performance assessment system. In 2011, the review of
Enis portfolio was performed following two key
aspects: maximizing innovative solutions created by the
R&D |
| --- |
| Exploration &
Production |
| n Seismic
depth migration . Eni has developed a set of
proprietary technologies for more accurate image
reconstruction of highly complex subsurface structures,
e.g., subsalt environments, deep reservoirs below
carbonates, and fractured reservoirs. n Eni Common Reflection Surface Stack
(e-crs™) . This is a proprietary seismic
processing technology that enhances the signal/noise
ratio in challenging imaging areas. n Eni Deep water dual casing running
(e-dwdc™) . This proprietary technology for
simultaneously drilling and then installing the conductor
pipe and the first casing has been applied to drill wells
in Angola (Cinguvu-2 and Cabaça South East-3 appraisal
wells) and Mozambique (Mamba South 1 and Mamba North 1
discovery wells). Its use reduced the drilling time for
this phase, while assuring maximum hole verticality and
operational safety. n Eni Circulation Device (e-cd™) .
Proprietary technology has been used to drill wells in
Alaska, Angola, China, Egypt, Ghana, and Italy. Eni
Circulation Device technology provides enhanced hydraulic
control and has demonstrated excellent capacity also for
well bore cleaning, opening new application perspectives. n e-sight, thin layer reservoirs .
Proprietary while-drilling and log interpretation
technologies (e-sight™) recently industrialized
provide an industry-leading capability to identify,
quantify and develop thin layer reservoirs, which are
by-passed with conventional approaches. This has led to
the identification of important additional resources in
Italy and internationally, and increased production in
2011. |

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Eni in 2011 Research and development

Gas & Power	Eni Corporate
n Eni
Kassandra meteo forecast . Since 2009 Eni has been
developing a new climate weather forecast system in
collaboration with the Italian Weather Operations Centre
(MOPI) to gain know-how regarding the temperature trend
on a regional and seasonal scale. Eni developed "Eni
Kassandra meteo forecast", a proprietary system for
forecasting temperatures from meteorological and climate
data. The system has been validated in 2011 at the
European level and is going to be used in the management
and sale of energy resources obtaining competitive
advantages in both gas and power businesses. n Pipeline monitoring . With the aim
of guaranteeing excellent quality standards and efficient
transport services, as part of its activity of pipeline
monitoring, Eni developed theoretical models of
acoustic-elastic transmission in pipes used for gas and
oil transport as well as algorithms for remote
localization of impacts and fluid leaks along the pipe.
The prototypal system of this monitoring technology will
be applied on transport and production pipes in Eni
plants in Italy, Tunisia and Nigeria. In addition,
studies were also completed on new acoustic sensors with
Wi-Fi remote control for offshore pipes that cannot be
checked with PIG (Pipeline Inspection Gauges), and radar
technologies for remote monitoring of vibrations and pipe
displacement.	n Photoactive
materials . A Luminescent Solar Concentrator consists
of a slab of transparent material (polymeric or glassy)
doped with fluorescent molecules, patented by Eni, which
works as microscopic light emitters. The emitted
radiation is partially concentrated within the slab by
total internal reflections and is waveguided toward its
edges where PV cells are placed. LSCs allow for a
substantial decrease in standard PV module costs by
reducing the effective cell surface with respect to the
absorbing surface. The positive results obtained at lab
level allow the commencement of a demonstration phase. n Micro-organisms for bio-diesel .
Purpose of the project is the use of micro-organisms
(yeasts and bacteria) that accumulate lipids similar to
those deriving from oil-bearing vegetables, that can
easily be turned into bio-diesel. The raw material
employed by these micro-organisms derives from the
treatment of wood-cellulose bio-mass in order to not
compete with food products. The identified yeasts have
higher productivity than the traditional oil crops,
including palm oil. n Photoproduction of hydrogen . This
project has breakthrough content for water splitting into
O 2 and H 2 . New materials were
synthesized for innovative photoelectrodes and
demonstration cells were constructed. The new materials
(e.g. titanium oxide, tungsten, and iron), based on
original processes that use nanotechnology, have lead to
interesting efficiency levels in the conversion of solar
energy into chemical energy, up to the best levels
reached on a world basis.
Refining &
Marketing
	Results derived
from the Eni-MIT alliance
n Eni Slurry Technology (EST) . The
EST proprietary technology is an innovative process for
hydro-conversion 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 produce by-products and
completely converts feedstocks into distillates. n Total Conversion . Successful
results have been obtained from the continuous operation
of the Slurry Dual Catalyst pilot plant: this technology,
based on the combination of two nanocatalysts could lead
to a relevant breakthrough in the EST process, increasing
its productivity and improving product quality. n Short Contact Time-Catalytic Partial
Oxidation (SCT-CPO) . It is a reforming technology
that can convert gaseous and liquid hydrocarbons (also
derived from bio-mass) 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. n Zero
Waste project . For the treatment of industrial, oil
and biological waste generated by the oil industry a
thermal process has been studied that allows for the
gasification of sludge that is turned into an inert
residue. A patent application has been filed on this
project.
	n Oil
spills in marine environment . The project derives
from the discovery of an innovative material with great
selective capacity for the absorption of oil dispersed in
water. This could be a first step towards new systems for
treating oil spills in marine environments. n Ultraflexible solar cell. One of
the most important results obtained by the Solar Frontier
Center: these cells made of a thin photoactive material
covered by a layer of transparent plastic can be bent
without breaking or reducing performance and this allows
to cover irregular surfaces without using metal stilts. n Solar
cells on paper. In this case the photoactive device
is made on paper as a printed document. The innovative
technique is the same used for producing cells on plastic
and flexible substrata. A paper cell can be a low cost
solution for application where the key aspect is not
duration but fast installation and easy transport.

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Trading environment indicators 2009 2010 2011

| Average
price of Brent dated crude oil (a) | | 61.51 | 79.47 | 111.27 |
| --- | --- | --- | --- | --- |
| Average EUR/USD exchange rate (b) | | 1.393 | 1.327 | 1.392 |
| Average
price in euro of Brent dated crude oil | | 44.16 | 59.89 | 79.94 |
| Average European refining margin (c) | | 3.13 | 2.66 | 2.06 |
| Average
European refining margin Brent/Ural (c) | | 3.56 | 3.47 | 2.90 |
| Average European refining margin in euro | | 2.25 | 2.00 | 1.48 |
| NBP gas
price (d) | | 4.78 | 6.56 | 9.03 |
| Euribor - three-month rate | (%) | 1.2 | 0.8 | 1.4 |
| Libor -
three-month dollar rate | (%) | 0.7 | 0.3 | 0.3 |

| (a) | In USD per
barrel. Source: Platts Oilgram. |
| --- | --- |
| (b) | Source: ECB. |
| (c) | In USD per
barrel FOB Mediterranean Brent dated crude oil. Source:
Eni calculations based on Platts Oilgram data. |
| (d) | In USD per
million btu. Source: Platts Oilgram. |

Enis results of operations and the year to year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas and refined products prices, industry-wide movements in refining and petrochemical margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. In 2011, Enis results of operations were achieved on the back of stronger oil and gas realizations (up by 30% on average) driven by a 40% increase in the price of the Brent crude benchmark compared to 2010. Refining margins remained at unprofitable levels (the marker Brent margin was $2.06 per barrel; down 22.6% from 2010) due to high feedstock costs which were only partially transferred to prices at the pump. Enis margins at its high-conversion refineries were also hit by narrowing light-heavy crude differentials in the Mediterranean area. In Europe, gas spot prices which have become the benchmark in contractual selling formulas increased by 37.7% compared with the depressed levels registered in 2010. This positive trend was not reflected in Enis gas selling margins due to higher oil-linked supply costs and rising competitive pressure. Results were also affected by the appreciation of the euro vs. the US dollar (up 4.9%).

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Eni in 2011 Group results for the year

2011 Results

In 2011, net profit attributable to Enis shareholders was euro 6,860 million, an increase of euro 542 million from 2010, or 8.6%. This increase was driven by an improved operating performance (up euro 1,324 million, or 8.2%) reported by the Exploration & Production Division which was boosted by higher oil prices. The Groups results were also helped by lower extraordinary pre-tax charges which were down by approximately euro 1 billion year-on-year and a gain of euro 1,044 million recorded on the divestment of Enis interests in the international pipelines which transport gas from Northern Europe and Russia. These positives were partly offset by sharply lower results posted by the Groups downstream businesses, higher net finance charges (down euro 402 million) and higher income taxes (down euro 1,517 million). Adjusted net profit attributable to Enis shareholders amounted to euro 6,969 million, an increase of euro 100 million from 2010, or 1.5%. Adjusted net profit was calculated by excluding an inventory holding profit of euro 724 million and net special charges of euro 833 million, thus totaling to a positive adjustment of euro 109 million.

Results for the year (euro million) 2006 2007 2007

2009 — 4,367		Net profit attributable to Eni's shareholders	2010 — 6,318		2011 — 6,860
(191	)	Exclusion
of inventory holding (gain) losses	(610	)	(724	)
1,031		Exclusion of special items	1,161		833
		of
which:
250		- non recurring items	(246	)	69
781		- other
special items	1,407		764
5,207		Adjusted net profit attributable to
Enis shareholders	6,869		6,969	100	1.5

Special charges of the operating profit mainly related to: (i) impairment losses of euro 1,022 million, which were recorded to write down the book values of certain tangible and intangible assets to their lower value-in-use mainly in the refining and gas marketing businesses. These charges reflected our reduced profitability outlook in these businesses driven by a deteriorating macroeconomic environment, volatile commodity prices, and rising competitive pressures. Other impairment losses regarded a number of oil&gas properties in the Exploration & Production Division reflecting a changed pricing environment and downward reserve revisions; (ii) provisions for redundancy incentives (euro 209 million), including a liability which was taken in connection with the 2010-2011 personnel mobility program in Italy to reflect changed pension requirements as per Law Decree No. 201 of December 2011; (iii) environmental and other risk provisions amounting to euro 274 million. The breakdown of adjusted net profit by Division is shown in the table below:

Adjusted net profit by Division (euro million) 2006 2007 2007

2009 — 3,878		Exploration & Production	2010 — 5,600		2011 — 6,866		Change — 1,266		% Ch. — 22.6
2,916		Gas &
Power	2,558		1,541		(1,017	)	(39.8	)
(197	)	Refining & Marketing	(49	)	(262	)	(213	)	..
(340	)	Petrochemicals	(85	)	(208	)	(123	)	..
892		Engineering & Construction	994		1,098		104		10.5
(245	)	Other
activities	(216	)	(225	)	(9	)	(4.2	)
(744	)	Corporate and financial companies	(699	)	(787	)	(88	)	(12.6	)
(3	)	Impact of
unrealized intragroup profit elimination (a)	(169	)	(111	)	58
6,157		Adjusted net profit	7,934		7,912		(22	)	(0.3	)
		of
which attributable to:
950		- Non-controlling interest	1,065		943		(122	)	(11.5	)
5,207		- Eni's
shareholders	6,869		6,969		100		1.5

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

The increase in the Group adjusted net profit reflected a higher adjusted net profit mainly reported by: - the Exploration & Production Division (up euro 1,266 million, or 22.6%) driven by a better operating performance (up euro 2,193 million, or 15.8%), reflecting higher oil and gas realizations in dollar terms (up 40.3% and 7.7%, respectively). This trend was strong enough to fully absorb a reduced operating profit from the Libyan activities. Full year results were impacted by the negative effect of the appreciation of the euro against the dollar (up 4.9%, for an overall impact of approximately euro 490 million); - the Engineering & Construction business (up euro 104 million , or 10.5%) reported an improved operating performance (up euro 117 million , or 8.8%) driven by revenue growth and higher profitability of works executed. These increases were partly offset by a declining adjusted net profit reported by: - the Gas & Power Division reported sharply lower results due to a decline of euro 1,173 million in adjusted operating profit, down by 37.6%. The decrease was mainly caused by the Marketing business which was negatively impacted by weak demand and mounting competitive pressure fuelled by oversupply which squeezed selling margins and reduced volumes opportunities;

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Eni in 2011 Group results for the year

the Refining & Marketing Division reported sharply lower adjusted operating losses (from minus euro 49 million in 2010 to minus euro 262 million in 2011). This decrease reflected negative trends in the refining trading environment featured by depressed margins and poor demand for fuels due to weak underlying fundamentals; - the Petrochemical Division was also deeply in the red with reported operating losses down to minus euro 208 million in 2011, much worse than in 2010. The performance was negatively impacted by falling product margins, with the cracker margin severely hit by higher supply costs of oil-based feedstock which were not recovered in sales prices on end markets, and a substantial decrease in demand. n Capital expenditures In 2011, capital expenditures amounting to euro 13,438 million related mainly to: - development activities (euro 7,357 million) deployed mainly outside Italy, primarily in Norway, Kazakhstan, Algeria, the Unites States, Congo and Egypt. In addition we acquired certain blocks and paid entry bonuses following interest license awards amounting to euro 754 million, mainly in Nigeria; - exploratory activities (euro 1,210 million) of which 97% was spent outside Italy, were conducted primarily in Australia, Angola, Mozambique, Indonesia, Ghana, Egypt, Nigeria and Norway; - upgrading of the fleet used in the Engineering & Construction Division (euro 1,090 million); - development and upgrading of Enis natural gas transport network in Italy (euro 898 million) and distribution network (euro 337 million), the development and the increase of storage capacity (euro 294 million), as well as and the ongoing development of power generation plants (euro 87 million); - projects aimed at improving the conversion capacity and flexibility of refineries (euro 629 million), as well as building and upgrading service stations in Italy and outside Italy (euro 228 million).

Capital expenditures by Division (euro million) 2006 2007 2007

2009 — 9,486	Exploration & Production	2010 — 9,690		2011 — 9,435		Change — (255	)	% Ch. — (2.6	)
1,686	Gas &
Power	1,685		1,721		36		2.1
635	Refining & Marketing	711		866		155		21.8
145	Petrochemicals	251		216		(35	)	(13.9	)
1,630	Engineering & Construction	1,552		1,090		(462	)	(29.8	)
44	Other
activities	22		10		(12	)	(54.5	)
57	Corporate and financial companies	109		128		19		17.4
12	Impact of
unrealized intragroup profit elimination	(150	)	(28	)	122
13,695	Capital expenditures	13,870		13,438		(432	)	(3.1	)

n Sources and uses of cash The Companys cash requirements for capital expenditures, dividends to shareholders, and working capital were financed by a combination of funds generated from operations, borrowings and divestments of non-strategic assets. In 2011, main inflows were associated with net cash provided by operating activities, which amounted to euro 14,382 million and proceeds from asset disposals (euro 1,912 million). These inflows were balanced by outflows for capital expenditures totaling euro 13,438 million, expenditures in joint venture projects (euro 360 million) and dividend payments amounting to euro 4,247 million to Eni shareholders (euro 3,695 million, of which euro 1,884 million relating to the 2011 interim dividend) and to non-controlling interest of Snam Rete Gas, Saipem and other consolidated subsidiaries (euro 552 million). As a result of these cash flows, net borrowings as of December 31, 2011 increased by euro 1,913 million compared to December 31, 2010. n Capital structure and ratios The Group continually monitors the balance between cash flow from operating activities, net expenditures, internally generated funds and dividend requirements targeting a sound and well-balanced financing structure. Enis net financial debt of euro 28 billion as of end of 2011 was associated with low risk activities as around euro 11 billion were attributable to Regulated businesses in Italy which ensure stable and solid cash flows that cover their investment needs and contribute to lower the risk profile of Enis portfolio. In addition, euro 3 billion of consolidated debt are attributable to Saipem, whose major ongoing investment program, relating to Offshore drilling and construction, will be completed by the end of the year. Finally, euro 14 billion of consolidated debt are attributable to Enis core operations and mainly linked to development projects under PSAs that have a safe and quick pay back period. In the foreseeable future, management is strongly focused on preserving a solid balance sheet and an adequate level of liquidity taking into account macroeconomic uncertainties and tight financial markets. For planning purposes, management projected the Companys expected cash flows assuming a scenario of Brent prices at 90-85 $/bbl for the years 2012-2015 to assess the financial compatibility of its capital expenditures programs and dividend policy with internal targets of leverage (the ratio of net borrowings to total equity). As of December 31, 2011, the Group leverage was 0.46, compared to the level of 0.47 as of December 31, 2010.

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In 2012, leverage is projected to be roughly in line with the level achieved at the end of 2011 assuming a Brent price of $90 a barrel. Looking forward, management will seek to progressively reduce this ratio to below 40% by the end of the plan period leveraging on the projected future cash flow from operations which are estimated to generate enough resources to fund both capital expenditures and dividends to Enis shareholders. Return On Average Capital Employed (ROACE) calculated on an adjusted basis was 9.9% (10.7% in 2010).

Adjusted ROACE (euro million) 2006 2007 2007

2011	E&P	G&P	R&M		Group
Adjusted net profit	6,866	1,541	(262	)	7,912
Exclusion
of after-tax finance expenses/interest income					454
Adjusted net profit unlevered	6,866	1,541	(262	)	8,366
Adjusted
capital employed, net:
- at the beginning
of period	37,646	27,346	8,321		81,847
-
at the end of period	42,024	27,660	8,600		87,701
Adjusted average capital employed, net	39,835	27,503	8,461		84,774
Adjusted
ROACE (%)	17.2	5.6	(3.1	)	9.9

| n Dividends In the next four-year period management intends to
maintain its progressive dividend policy. Enis dividend policy in future periods, and the
sustainability of the current amount of dividends over
the next four-year period, will depend upon a number of
factors including future levels of profitability and cash
flow provided by operating activities, a sound balance
sheet structure, capital expenditures and development
plans. The parent Companys net profit and,
therefore, the amounts of earnings available for the
payment of dividends will also depend on the level of
dividends received from Enis subsidiaries. However,
subject to such factors, under the Companys
scenario for Brent prices at 90-85 $/bbl over the next
four years, management plans to grow the dividend in line
with OECD inflation from 2011 onwards. If management
assumptions on oil prices were to change, management may
revise the dividend and reset the basis for progressive
dividend increases. Management plans to pay a dividend of euro 1.04 a share
for 2011 subject to approval from the Annual General
Shareholders Meeting scheduled on May 8, 2012. Of
this, euro 0.52 per share was paid in September 2011 as
an interim dividend with the balance of euro 0.52 per
share expected to be paid late in May 2012. | are anticipated to remain at
unprofitable levels due to high costs of oil supplies,
sluggish demand and excess capacity. For investment planning purposes and short-term financial
projections, Eni assumes a full-year average price of $90
a barrel for the Brent crude benchmark. For the full year 2012, management expects a capital
budget almost in line with 2011 (in 2011 capital
expenditures amounted to euro 13.44 billion, while
expenditures incurred in joint venture initiatives and
other investments amounted to euro 0.36 billion). Management plans to continue spending on exploration to
appraise the mineral potential of recent discoveries
(Mozambique, Norway, Ghana and Indonesia) and investing
large amounts on developing growing areas and maintain
field plateaus in mature basins. Other investment
initiatives will target the upgrading of the gas
transport and distribution networks, the completion of
the EST project in the refining business, and
strengthening selected petrochemical plants. |
| --- | --- |
| | Risk factors |
| In future years, management
expects to continue paying interim dividends for each
fiscal year, with the balance for the full-year dividend
paid in the following year. | n Market
risk and sensitivity to market environment Market risk is the possibility that the exposure to
fluctuations in currency |

| Outlook for 2012 |
| --- |
| Management expects the 2012 outlook to be challenging due
to signs of a continuing economic slowdown, particularly
in the Euro-zone, and volatile market conditions.
Management expects international oil prices to be
supported by robust demand growth from China and other
emerging economies, as well as ongoing geopolitical risks
and uncertainties, partly offset by a recovery in the
Libyan output. Recovery perspectives look poor in the gas
sector. Gas demand is expected to be soft due to slow
economic activity and increasing competition from
renewable sources; in the meantime the marketplace
appears well supplied. Against this backdrop, management
expects ongoing margin pressures to continue in 2012, and
reduced sales opportunities due to rising competition.
Management foresees the persistence of a depressed
trading environment in the European refining business.
Refining margins |

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Eni in 2011 Group results for the year

margin. The Groups risk management objectives are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. Also, as part of its risk management activities from 2011 the Group has commenced trading activities in order to seek to profit from short-term market opportunities. The Groups risk management has evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, gas volatile margins and development of liquid gas spot markets. To achieve these targets, Eni enters into commodity derivatives transactions in both commodity and financial markets: (i) to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. As tight correlation exists between such commodity derivatives transactions and underlying physical contracts, those derivatives are treated in accordance with hedging accounting in compliance with IAS 39, where possible; and (ii) to pursue speculative purposes such as altering the risk profile associated with a portfolio of contracts (purchase contracts, transport entitlements, storage capacity) or leveraging any pricing differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of trends in future prices. The Company also intends to implement strategies of dynamic forward trading in order to maximize the economic value of the flexibilities associated with its assets. Price risks related to asset backed trading activities are mitigated by the natural hedge granted by the assets availability. These contracts may lead to gains as well as losses, which, in each case, may be significant. These derivatives are accounted for through profit and loss, resulting in higher volatility in Enis operating profit, particularly in the gas marketing business. Eni Trading & Shipping is the Groups entity in charge of managing derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. The objective of this activity is to both hedge part of the Group exposure to the commodity risk and optimize commercial margins by entering speculative derivative transactions. Eni Trading & Shipping SpA and its subsidiaries also provide Group companies with crude oil and products supply, trading and shipping services. The results of this entity are reported within the Gas & Power segment with regard to the results recorded on trading gas and electricity derivatives; while the portion of results which pertains to oil and products trading derivatives and supply and shipping services are reported within the Refining & Marketing segment. As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in foreign exchange rates and interest rates. These instruments are principally interest rate and currency swaps. n Liquidity and counterparty risks Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively impact the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements. At December 31, 2011, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 11,897 million, of which euro 2,551 million were committed, and long-term committed unused borrowing facilities of euro 3,201 million. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial. Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 10.5 billion were drawn as of December 31, 2011. The Group has credit ratings of A and A-1 respectively for long and short-term debt assigned by Standard & Poors and A2 and P-1 assigned by Moodys; the outlook is negative in both ratings. Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Enis corporate financial units and Eni Adfin are responsible for managing credit risk arising in the normal course of the business. The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Enis corporate units define directions and methods for quantifying and controlling customers reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterpartys financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Companys Board of Directors taking into accounts the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Enis subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and Division, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterparty on a daily basis. Exceptional market conditions have forced the Group to adopt contingency plans and under certain circumstances to suspend eligibility to be a Group financial counterparty. Actions implemented also have been intended to limit concentrations of credit risk by maximizing counterparty diversification and turnover. Counterparties have also been selected on more stringent criteria particularly in transactions on derivatives instruments and with maturity longer than a three-month period. As of December 31, 2011, Eni had no significant concentration of credit risk.

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Eni prepares its consolidated financial statements in accordance with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Union. Differences in certain respects between IFRS as endorsed by the EU and IFRS as issued by IASB are on matters that do not relate to Eni. On this basis, Enis financial statements are fully in compliance with IFRS as issued by IASB. The consolidated financial statements of Eni include accounts of the parent company Eni SpA and of all Italian and foreign significant subsidiaries in which Eni directly or indirectly holds the majority of voting rights or is otherwise able to exercise control as in the case of "de facto" controlled entities. Control comprises the power to govern the financial and operating policies of the investee so as to obtain benefit from its activities. Immaterial subsidiaries, jointly controlled entities, and other entities in which the group is in a position to exercise a significant influence through participation in the financial and operating policy decisions of the investee are generally accounted for under the equity method. Revenues from sales of crude oil, natural gas, petroleum and petrochemical products are recognized when the products are delivered and title passes to the customer. Revenue recognition in the Engineering & Construction Division is based on the stage of completion of contracts as measured on the cost-to-cost basis applied to contractual revenues. Eni enters into various derivative financial transactions to manage exposures to certain market risks, including foreign currency exchange rate risks, interest rate risks and commodity risks. Such derivative financial instruments are assets and liabilities recognized at fair value starting on the date on which a derivative contract is entered into and are subsequently re-measured at fair value. Derivatives are designated as hedges when the hedging relationship between the hedged item or transaction and the hedging instrument is highly effective and formally documented. Changes in the fair value of hedging derivatives are recognized: (i) for fair value hedges, hedging the exposure to changes in the fair value of a recognized asset or liability, in the profit and loss account; (ii) for cash flow hedges, hedging exposure to variability in cash flows, the effective portion is recognized directly in equity, while the ineffective portion is recognized in profit or loss; subsequently amounts taken to equity are transferred to the profit and loss account when the hedged transaction affects profit or loss. Changes in fair value of derivatives held for trading purposes, including derivatives for which the hedging relationship is not formally documented or is ineffective, are recognized in profit or loss. Inventories of crude oil, natural gas and oil products are stated at the lower of purchase or production cost and net realizable value. Cost is determined by applying the weighted-average cost method. Contract work in progress is recorded on the basis of contractual considerations by reference to the stage of completion of a contract measured on a cost-to-cost basis. Property, plant and equipment is stated at cost less any accumulated depreciation, depletion and amortization charges and impairment losses. Depreciation, depletion and amortization of oil and gas properties (capitalized costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas) is calculated based on the Unit-Of-Production (UOP) method on proved reserves or proved developed reserves. Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. Exploration costs (costs associated with exploratory activities for oil and gas including geological and geophysical exploration costs and exploratory drilling well expenditures) are capitalized and fully amortized as incurred. Intangible assets are initially stated at cost. Intangible assets having a defined useful life are amortized systematically, based on the straight-line method. Goodwill and intangibles lacking a defined useful life are not amortized but are reviewed periodically for impairment. Impairment of tangible and intangible assets Eni assesses its property, plant and equipment and intangible assets, including goodwill, for impairment whenever events or changes in circumstances indicate that the carrying values of the assets may not be recoverable. Indications of impairment include changes in the Groups business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. The recoverability of an asset or group of assets is assessed by comparing the carrying value with the recoverable amount represented by the higher of fair value less costs to sell and value in use. In assessing value in use, the Group makes an estimate of the future cash flows expected to be derived from the use of the asset on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years of the estimate and managements long-term planning

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Eni in 2011 Financial information

| assumptions thereafter.
Future cash flows are discounted at a rate that reflects
current market valuation of the time value of money and
those specific risks of the asset that are not reflected
in the estimation of future cash flows. The Group uses a
discount rate that is calculates as the weighted average
cost of capital to the Group (WACC), adjusted to reflect
specific country risks of each asset. Asset
retirement obligations , that may be incurred for the
dismantling and removal of assets and the reclamation of
sites, are evaluated estimating the costs to be incurred
when the asset is retired. Future estimated costs are
discounted if the effect of the time value of money is
material. The initial estimate is reviewed periodically
to reflect changes in circumstances and other factors
surrounding the estimate, including the discount rates.
The Company recognizes material provisions for asset
retirement in the upstream business. No significant asset
retirement obligations associated with any legal
obligations to retire refining, marketing and
transportation (downstream) and chemical long-lived
assets are generally recognized, as indeterminate
settlement dates for the asset retirement prevent
estimation of the fair value of the associated asset
retirement obligation. Provisions , including environmental
liabilities, are recognized when the group has a current
obligation (legal or constructive) as a result of a past
event, when it is probable that an outflow of resources
embodying economic benefit will be required to settle the
obligation, and when the obligation can be reliably
estimated. The initial estimate to settle the obligation
is discounted when the effect of the time value of money
is material. The estimate is reviewed periodically to
take account of changes in costs expected to be incurred
to settle the obligation and other factors, including
changes in the discount rates. | | Eni is a party to a number
of legal proceedings arising in the ordinary
course of business. Based on information available to
date, and taking into account the existing risk
provisions, Enis management believes that ongoing
litigations will not have a material adverse effect on
Enis financial position and results of operations.
However, there can be no assurance that in the future Eni
will not incur material charges in connection with
pending litigations as new information becomes available
and new developments may occur. For further information
about pending litigations, see Note 34 - Legal proceedings - to the consolidated financial
statements of 2011 Enis Annual Report on Form 20-F
filed with the US SEC. The preparation of consolidated
financial statements requires the use of estimates and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimates made are
based on complex or subjective judgments, past
experience, other assumptions deemed reasonable in
consideration of the information available at the time.
The accounting policies and areas that require the most
significant judgments and estimates to be used in the
preparation of consolidated financial statements are in
relation to the accounting for oil and natural gas
activities, specifically in the determination of proved
and proved developed reserves, impairment of fixed
assets, intangible assets and goodwill, asset retirement
obligations, business combinations, pensions and other
postretirement benefits, recognition of environmental
liabilities and recognition of revenues in the oilfield
services construction and engineering businesses.
Although the Company uses its best estimates and
judgments, actual results could differ from the estimates
and assumptions used. For further information regarding accounting policies
and practices, see Note 3 - Summary of significant accounting policies - and Note 5 - Use of accounting estimates - to the consolidated financial statements of 2011
Enis Annual Report. |
| --- | --- | --- |
| i | i | i |

Profit and loss account (euro million) 2009 2010 2011

Revenues — Net sales from operations	83,227		98,523		109,589
Other
income and revenues	1,118		956		933
	84,345		99,479		110,522
Operating
expenses
Purchases, services and other	(58,351	)	(69,135	)	(79,191	)
-
of which non-recurring charge (income)	250		(246	)	69
Payroll and related costs	(4,181	)	(4,785	)	(4,749	)
	(62,532	)	(73,920	)	(83,940	)
Other operating income (expense)	55		131		171
Depreciation,
depletion, amortization and impairments	(9,813	)	(9,579	)	(9,318	)
OPERATING PROFIT	12,055		16,111		17,435
Finance
income (expense)
Finance income	5,950		6,117		6,379
Finance
expense	(6,497	)	(6,713	)	(7,396	)
Derivative financial instruments	(4	)	(131	)	(112	)
	(551	)	(727	)	(1,129	)
Income (expense) from investments
Share of
profit (loss) of equity-accounted investments	393		537		544
Other gain (loss) from investments	176		619		1,627
	569		1,156		2,171
PROFIT BEFORE INCOME TAXES	12,073		16,540		18,477
Income
taxes	(6,756	)	(9,157	)	(10,674	)
NET PROFIT	5,317		7,383		7,803
Attributable
to:
- Eni's
shareholders	4,367		6,318		6,860
-
Non-controlling interest	950		1,065		943

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Eni in 2011 Financial information

Balance sheet (euro million) Dec. 31, 2010 Dec. 31, 2011

ASSETS
Current assets
Cash and
cash equivalents	1,549		1,500
Other financial assets held for trading or
available for sale	382		262
Trade and
other receivables	23,636		24,595
Inventories	6,589		7,575
Current
tax assets	467		549
Other current tax assets	938		1,388
Other
current assets	1,350		2,326
Total current assets	34,911		38,195
Non-current
assets
Property, plant and equipment	67,404		73,578
Inventory
- compulsory stock	2,024		2,433
Intangible assets	11,172		10,950
Equity-accounted
investments	5,668		5,843
Other investments	422		399
Other
financial assets	1,523		1,578
Deferred tax assets	4,864		5,514
Other
non-current receivables	3,355		4,225
Total non-current assets	96,432		104,520
Assets
held for sale	517		230
TOTAL ASSETS	131,860		142,945
LIABILITIES
AND SHAREHOLDERS EQUITY
Current liabilities
Short-term
debt	6,515		4,459
Current portion of long-term debt	963		2,036
Trade and
other payables	22,575		22,912
Income taxes payables	1,515		2,092
Other
taxes payables	1,659		1,896
Other current liabilities	1,620		2,237
Total
current liabilities	34,847		35,632
Non-current liabilities
Long-term
debt	20,305		23,102
Provisions for contingencies	11,792		12,735
Provisions
for employee benefits	1,032		1,039
Deferred tax liabilities	5,924		7,120
Other
non-current liabilities	2,194		2,900
Total non-current liabilities	41,247		46,896
Liabilities
directly associated with assets held for sale	38		24
TOTAL LIABILITIES	76,132		82,552
SHAREHOLDERS
EQUITY
Non-controlling interest	4,522		4,921
Eni
shareholders equity
Share capital: 4,005,358,876 fully paid shares
nominal value euro 1 each (same amount as of December 31,
2010)	4,005		4,005
Reserves	49,624		53,195
Reserve related to cash flow hedging derivatives
net of tax effect	(174	)	49
Treasury
shares	(6,756	)	(6,753	)
Interim dividend	(1,811	)	(1,884	)
Net profit	6,318		6,860
Total Eni shareholders equity	51,206		55,472
TOTAL
SHAREHOLDERS EQUITY	55,728		60,393
TOTAL LIABILITIES AND SHAREHOLDERS
EQUITY	131,860		142,945

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Eni in 2011 Financial information

Statements of cash flow (euro million) 2009 2010 2011

| Net profit
of the year | 5,317 | | 7,383 | | 7,803 | |
| --- | --- | --- | --- | --- | --- | --- |
| Adjustments to reconcile net profit to net
cash provided by operating activities | | | | | | |
| Depreciation,
depletion and amortization | 8,762 | | 8,881 | | 8,297 | |
| Impairments of tangible and intangible assets,
net | 1,051 | | 698 | | 1,021 | |
| Share of
profit (loss) of equity-accounted investments | (393 | ) | (537 | ) | (544 | ) |
| Gain on disposal of assets, net | (226 | ) | (552 | ) | (1,170 | ) |
| Dividend
income | (164 | ) | (264 | ) | (659 | ) |
| Interest income | (352 | ) | (96 | ) | (101 | ) |
| Interest
expense | 603 | | 571 | | 737 | |
| Income taxes | 6,756 | | 9,157 | | 10,674 | |
| Other
changes | (319 | ) | (39 | ) | 331 | |
| Changes in working capital: | | | | | | |
| -
inventories | 52 | | (1,150 | ) | (1,422 | ) |
| - trade receivables | 1,431 | | (1,918 | ) | (369 | ) |
| - trade
payables | (2,559 | ) | 2,770 | | 161 | |
| - provisions for contingencies | 517 | | 588 | | 122 | |
| - other
assets and liabilities | (636 | ) | (2,010 | ) | (668 | ) |
| Cash flow from changes in working capital | (1,195 | ) | (1,720 | ) | (2,176 | ) |
| Net change
in the provisions for employee benefits | 16 | | 21 | | (10 | ) |
| Dividends received | 576 | | 799 | | 997 | |
| Interest
received | 594 | | 126 | | 100 | |
| Interest paid | (583 | ) | (600 | ) | (893 | ) |
| Income
taxes paid, net of tax receivables received | (9,307 | ) | (9,134 | ) | (10,025 | ) |
| Net cash provided by operating activities | 11,136 | | 14,694 | | 14,382 | |
| Investing
activities: | | | | | | |
| - tangible assets | (12,032 | ) | (12,308 | ) | (11,658 | ) |
| -
intangible assets | (1,663 | ) | (1,562 | ) | (1,780 | ) |
| - consolidated subsidiaries and businesses | (25 | ) | (143 | ) | (115 | ) |
| -
investments | (230 | ) | (267 | ) | (245 | ) |
| - securities | (2 | ) | (50 | ) | (62 | ) |
| -
financing receivables | (972 | ) | (866 | ) | (715 | ) |
| - change in payables and receivables in relation
to investing activities and capitalized depreciation | (97 | ) | 261 | | 379 | |
| Cash
flow from investing activities | (15,021 | ) | (14,935 | ) | (14,196 | ) |
| Disposals: | | | | | | |
| - tangible
assets | 111 | | 272 | | 154 | |
| - intangible assets | 265 | | 57 | | 41 | |
| -
consolidated subsidiaries and businesses | | | 215 | | 1,006 | |
| - investments | 3,219 | | 569 | | 711 | |
| -
securities | 164 | | 14 | | 128 | |
| - financing receivables | 861 | | 841 | | 695 | |
| - change
in payables and receivables in relation to disposals | 147 | | 2 | | 243 | |
| Cash flow from disposals | 4,767 | | 1,970 | | 2,978 | |
| Net
cash used in investing activities | (10,254 | ) | (12,965 | ) | (11,218 | ) |
| Proceeds from long-term debt | 8,774 | | 2,953 | | 4,474 | |
| Repayments
of long-term debt | (2,044 | ) | (3,327 | ) | (889 | ) |
| Increase (decrease) in short-term debt | (2,889 | ) | 2,646 | | (2,481 | ) |
| | 3,841 | | 2,272 | | 1,104 | |
| Net capital contributions/payments by/to
non-controlling interest | 1,551 | | | | 26 | |
| Net sale
of treasury shares by consolidated subsidiaries | 9 | | 37 | | 17 | |
| Acquisition of additional interests in
consolidated subsidiaries | (2,068 | ) | | | (126 | ) |
| Dividends
paid to Enis shareholders | (4,166 | ) | (3,622 | ) | (3,695 | ) |
| Dividends paid to non-controlling interest | (350 | ) | (514 | ) | (552 | ) |
| Sale of
treasury shares | | | | | 3 | |
| Net cash used in financing activities | (1,183 | ) | (1,827 | ) | (3,223 | ) |
| Effect
of change in consolidation (inclusion/exclusion of
significant/insignificant subsidiaries) | | | | | (7 | ) |
| Effect of exchange rate changes on cash and
cash equivalents and other changes | (30 | ) | 39 | | 17 | |
| Net
cash flow of the year | (331 | ) | (59 | ) | (49 | ) |
| Cash and cash equivalents - beginning of the
year | 1,939 | | 1,608 | | 1,549 | |
| Cash
and cash equivalents - end of the year | 1,608 | | 1,549 | | 1,500 | |

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Eni in 2011 Financial information

Non-GAAP measures

n Reconciliation of reported operating profit and reported net profit to results on an adjusted basis Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses and special items. Furthermore, finance charges on finance debt, interest income, gains or losses deriving from the evaluation of certain derivative financial instruments at fair value through profit or loss (as they do not meet the formal criteria to be assessed as hedges under IFRS, excluding commodity derivatives), and exchange rate differences are all excluded when determining adjusted net profit of each business segment. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (38% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Enis trading performance on the basis of their forecasting models. In addition, management uses segmental adjusted net profit when calculating Return On Average Capital Employed (ROACE) by each business segment. The following is a description of items that are excluded from the calculation of adjusted results. Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting. Special items include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; or (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (Consob), non recurring material income or charges are to be clearly reported in the managements discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives, including the ineffective portion of cash flow hedges and certain derivatives financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production Division. Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. In addition, gains or losses on the fair value evaluation of the aforementioned derivative financial instruments, excluding commodity derivatives and exchange rate differences are excluded from the adjusted net profit of business segments. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment-operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production Division). Finance charges or interest income and related taxation effects excluded from the adjusted net profit of the business segments are allocated on the aggregate Corporate and financial companies. For a reconciliation of adjusted operating profit and adjusted net profit to reported operating profit and reported net profit see tables below.

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Eni in 2011 Financial information

2011 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	15,887		1,758		(273	)	(424	)	1,422		(427	)	(319	)	(189	)	17,435
Exclusion
of inventory holding (gains) losses			(166	)	(907	)	(40	)									(1,113	)
Exclusion of special items
of
which:
Non-recurring (income) charges							10				59						69
Other special (income) charges:	190		354		645		178		21		142		53				1,583
- environmental charges			10		34		1				141						186
- asset impairments	190		145		488		160		35		4						1,022
- gains on disposal of assets	(63	)	(4	)	10				4		(7	)	(1	)			(61	)
- risk provisions			77		8						9		(6	)			88
- provision for redundancy incentives	44		40		81		17		10		8		9				209
- re-measurement gains/losses on commodity
derivatives	1		45		(3	)			(28	)							15
- other	18		41		27						(13	)	51				124
Special
items of operating profit	190		354		645		188		21		201		53				1,652
Adjusted operating profit	16,077		1,946		(535	)	(276	)	1,443		(226	)	(266	)	(189	)	17,974
Net
finance (expense) income (a)	(231	)	33								5		(932	)			(1,125	)
Net income (expense) from investments (a)	624		407		99				95		(3	)	1				1,223
Income
taxes (a)	(9,604	)	(845	)	174		68		(440	)	(1	)	410		78		(10,160	)
Tax rate (%)	58.3		35.4		..				28.6								56.2
Adjusted
net profit	6,866		1,541		(262	)	(208	)	1,098		(225	)	(787	)	(111	)	7,912
of which:
- Adjusted
net profit of non-controlling interest																	943
- Adjusted net profit attributable to
Enis shareholders																	6,969
Reported
net profit attributable to Enis shareholders																	6,860
Exclusion of inventory holding (gains) losses																	(724	)
Exclusion
of special items:																	833
- non-recurring charges																	69
- other
special (income) charges																	764
Adjusted net profit attributable to
Enis shareholders																	6,969

(a) Excluding special items.

2010 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	13,866		2,896		149		(86	)	1,302		)	(361	)	(271	)	16,111
Exclusion
of inventory holding (gains) losses			(117	)	(659	)	(105	)								(881	)
Exclusion of special items
of
which:
Non-recurring (income) charges			(270	)					24							(246	)
Other special (income) charges:	18		610		339		78			1,179		96				2,320
- environmental charges	30		25		169					1,145						1,369
- asset impairments	127		436		76		52		3	8						702
- gains on disposal of assets	(241	)	4		(16	)			5							(248	)
- risk provisions			78		2					7		8				95
- provision for redundancy incentives	97		75		113		26		14	10		88				423
- re-measurement gains/losses on commodity
derivatives			30		(10	)			(22	)						(2	)
- other	5		(38	)	5					9						(19	)
Special
items of operating profit	18		340		339		78		24	1,179		96				2,074
Adjusted operating profit	13,884		3,119		(171	)	(113	)	1,326	(205	)	(265	)	(271	)	17,304
Net
finance (expense) income (a)	(205	)	19						33	(9	)	(530	)			(692	)
Net income (expense) from investments (a)	274		406		92		1		10	(2	)					781
Income
taxes (a)	(8,353	)	(986	)	30		27		(375	)		96		102		(9,459	)
Tax rate (%)	59.9		27.8		..				27.4							54.4
Adjusted
net profit	5,600		2,558		(49	)	(85	)	994	(216	)	(699	)	(169	)	7,934
of which:
- Adjusted
net profit of non-controlling interest																1,065
- Adjusted net profit attributable to
Enis shareholders																6,869
Reported
net profit attributable to Enis shareholders																6,318
Exclusion of inventory holding (gains) losses																(610	)
Exclusion
of special items:																1,161
- non-recurring charges																(246	)
- other
special (income) charges																1,407
Adjusted net profit attributable to
Enis shareholders																6,869

(a)
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Eni in 2011 Financial information

2009 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	9,120		3,687		(102	)	(675	)	881		(436	)	(420	)			12,055
Exclusion
of inventory holding (gains) losses			326		(792	)	121										(345	)
Exclusion of special items
of
which:
Non-recurring (income) charges									250								250
Other special (income) charges:	364		(112	)	537		128		(11	)	178		78				1,162
- environmental charges			19		72						207						298
- asset impairments	618		27		389		121		2		5						1,162
- gains on disposals of assets	(270	)	(6	)	(2	)			3		(2	)					(277	)
- risk provisions			115		17						(4	)					128
- provision for redundancy incentives	31		25		22		10				8		38				134
- re-measurement gains/losses on commodity
derivatives	(15	)	(292	)	39		(3	)	(16	)							(287	)
- other											(36	)	40				4
Special
items of operating profit	364		(112	)	537		128		239		178		78				1,412
Adjusted operating profit	9,484		3,901		(357	)	(426	)	1,120		(258	)	(342	)			13,122
Net
finance (expense) income (a)	(23	)	(15	)							12		(525	)			(551	)
Net income (expense) from investments (a)	243		332		75				49		1						700
Income
taxes (a)	(5,826	)	(1,302	)	85		86		(277	)			123		(3	)	(7,114	)
Tax rate (%)	60.0		30.9		..				23.7								53.6
Adjusted
net profit	3,878		2,916		(197	)	(340	)	892		(245	)	(744	)	(3	)	6,157
of which:
- Adjusted
net profit of non-controlling interest																	950
- Adjusted net profit attributable to
Enis shareholders																	5,207
Reported
net profit attributable to Enis shareholders																	4,367
Exclusion of inventory holding (gains) losses																	(191	)
Exclusion
of special items:																	1,031
- non-recurring charges																	250
- other
special (income) charges																	781
Adjusted net profit attributable to
Enis shareholders																	5,207

| (a) | | Excluding
special items. |
| --- | --- | --- |
| i | i | i |

Breakdown of special items (euro million) 2009 2010 2011

| Non-recurring
charges (income) | 250 | | (246 | ) | 69 | |
| --- | --- | --- | --- | --- | --- | --- |
| of which: | | | | | | |
| -
expected settlement of TSKJ proceeding | 250 | | | | | |
| - settlement/payments on antitrust and other
Authorities proceedings | | | (246 | ) | 69 | |
| Other
special charges (income): | 1,162 | | 2,320 | | 1,583 | |
| environmental charges | 298 | | 1,369 | | 186 | |
| asset
impairments | 1,162 | | 702 | | 1,022 | |
| gains on disposal of assets | (277 | ) | (248 | ) | (61 | ) |
| risk
provisions | 128 | | 95 | | 88 | |
| provisions for redundancy incentives | 134 | | 423 | | 209 | |
| re-measurement
gains/losses on commodity derivatives | (287 | ) | (2 | ) | 15 | |
| other | 4 | | (19 | ) | 124 | |
| Special
items of operating profit | 1,412 | | 2,074 | | 1,652 | |
| Net finance (income) expense | | | 35 | | 4 | |
| Net
(income) expense from investments | 179 | | (324 | ) | (883 | ) |
| of which: | | | | | | |
| - gains
from disposal of assets | | | (332 | ) | (1,122 | ) |
| - impairments | | | 28 | | 191 | |
| Income
taxes | (560 | ) | (624 | ) | 60 | |
| of which: | | | | | | |
| impairment
of deferred tax assets E&P | 72 | | 29 | | | |
| deferred tax adjustment in a Production
Sharing Agreement | | | | | 552 | |
| re-allocation
of tax impact on Eni SpA dividends and other special
items | (219 | ) | 29 | | 29 | |
| taxes on special items of operating profit | (413 | ) | (653 | ) | (521 | ) |
| Total
special items of net profit | 1,031 | | 1,161 | | 833 | |

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n Summarized Group Balance Sheet The Summarized Group Balance Sheet aggregates the amount of assets and liabilities derived from the statutory balance sheet in accordance with functional criteria which consider the enterprise conventionally divided into the three fundamental areas focusing on resource investments, operations and financing. Management believes that this Summarized Group Balance Sheet is useful information in assisting investors to assess Enis capital structure and to analyze its sources of funds and investments in fixed assets and working capital. Management uses the Summarized Group Balance Sheet to calculate key ratios such as Return On Capital Employed (ROACE) and the proportion of net borrowings to shareholders equity (leverage) intended to evaluate whether Enis financing structure is sound and well-balanced.

Summarized Group Balance Sheet (euro million) Dec. 31, 2010 Dec. 31, 2011

| Fixed
assets — Property, plant and equipment | 67,404 | | 73,578 | |
| --- | --- | --- | --- | --- |
| Inventories
- compulsory stock | 2,024 | | 2,433 | |
| Intangible assets | 11,172 | | 10,950 | |
| Equity-accounted
investments and other investments | 6,090 | | 6,242 | |
| Receivables and securities held for operating
purposes | 1,743 | | 1,740 | |
| Net
payables related to capital expenditures | (970 | ) | (1,576 | ) |
| | 87,463 | | 93,367 | |
| Net
working capital | | | | |
| Inventories | 6,589 | | 7,575 | |
| Trade
receivables | 17,221 | | 17,709 | |
| Trade payables | (13,111 | ) | (13,436 | ) |
| Tax
payables and provisions for net deferred tax liabilities | (2,684 | ) | (3,503 | ) |
| Provisions | (11,792 | ) | (12,735 | ) |
| Other
current assets and liabilities | (1,286 | ) | 281 | |
| | (5,063 | ) | (4,109 | ) |
| Provisions
for employee post-retirement benefits | (1,032 | ) | (1,039 | ) |
| Net assets held for sale including related
net borrowings | 479 | | 206 | |
| CAPITAL
EMPLOYED, NET | 81,847 | | 88,425 | |
| Shareholders equity: | | | | |
| - Eni
shareholders' equity | 51,206 | | 55,472 | |
| - Non-controlling interest | 4,522 | | 4,921 | |
| | 55,728 | | 60,393 | |
| Net borrowings | 26,119 | | 28,032 | |
| TOTAL
LIABILITIES AND SHAREHOLDERS EQUITY | 81,847 | | 88,425 | |

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Eni in 2011 Financial information

n Net borrowings and leverage Eni evaluates its financial condition by reference to net borrowings , which is calculated as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Enis financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities. Leverage is a measure used by management to assess the Companys level of indebtedness. It is calculated as a ratio of net borrowings which is calculated by excluding cash and cash equivalents and certain very liquid assets from financial debt to shareholders equity, including non-controlling interest. Management periodically reviews leverage in order to assess the soundness and efficiency of the Group balance sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards.

Net borrowings and leverage (euro million) Dec. 31, 2010 Dec. 31, 2011

| Total debt — - Short-term
debt | 27,783 — 7,478 | | 29,597 — 6,495 | |
| --- | --- | --- | --- | --- |
| -
Long-term debt | 20,305 | | 23,102 | |
| Cash and cash equivalents | (1,549 | ) | (1,500 | ) |
| Securities
held for non-operating purposes | (109 | ) | (37 | ) |
| Financing receivables for non-operating purposes | (6 | ) | (28 | ) |
| Net
borrowings | 26,119 | | 28,032 | |
| Shareholders equity including
non-controlling interest | 55,728 | | 60,393 | |
| Leverage | 0.47 | | 0.46 | |

n Summarized Group Cash Flow Statement and Change in net borrowings Enis summarized Group cash flow statement derives from the statutory statement of cash flows. It enables investors to understand the link existing between changes in cash and cash equivalents (deriving from the statutory cash flow statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. The measure enabling such a link is represented by the free cash flow which is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/ deducting cash flows relating to financing debts/receivables (issuance/repayment of debt and receivables related to financing activities), shareholders equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; and (ii) change in net borrowings for the period by adding/deducting cash flows relating to shareholders equity and the effect of changes in consolidation and of exchange rate differences. The free cash flow is a non-GAAP measure of financial performance.

Summarized Group Cash Flow Statement (euro million) 2009 2010 2011

| Net
profit | 5,317 | | 7,383 | | 7,803 | |
| --- | --- | --- | --- | --- | --- | --- |
| Adjustments to reconcile net profit to net
cash provided by operating activities: | | | | | | |
| -
depreciation, depletion and amortization and other non
monetary items | 9,117 | | 9,024 | | 9,095 | |
| - net gains on disposal of assets | (226 | ) | (552 | ) | (1,170 | ) |
| -
dividends, interest, taxes and other changes | 6,843 | | 9,368 | | 10,651 | |
| Changes in working capital related to operations | (1,195 | ) | (1,720 | ) | (2,176 | ) |
| Dividends
received, taxes paid, interest (paid) received during the
period | (8,720 | ) | (8,809 | ) | (9,821 | ) |
| Net cash provided by operating activities | 11,136 | | 14,694 | | 14,382 | |
| Capital
expenditures | (13,695 | ) | (13,870 | ) | (13,438 | ) |
| Investments and purchase of consolidated
subsidiaries and businesses | (2,323 | ) | (410 | ) | (360 | ) |
| Disposals | 3,595 | | 1,113 | | 1,912 | |
| Other cash flow related to capital expenditures,
investments and disposals | (295 | ) | 228 | | 627 | |
| Free
cash flow | (1,582 | ) | 1,755 | | 3,123 | |
| Cash flows of financial instruments not related
to operations | 396 | | (26 | ) | 41 | |
| Changes in
short and long-term finance debt | 3,841 | | 2,272 | | 1,104 | |
| Dividends paid and changes in non-controlling
interests and reserves | (2,956 | ) | (4,099 | ) | (4,327 | ) |
| Effect of
changes in consolidation area and exchange differences | (30 | ) | 39 | | 10 | |
| NET CASH FLOW FOR THE PERIOD | (331 | ) | (59 | ) | (49 | ) |

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Change in net borrowings (euro million) 2009 2010 2011

| Free
cash flow | (1,582 | ) | 1,755 | | 3,123 | |
| --- | --- | --- | --- | --- | --- | --- |
| Net borrowings of acquired companies | | | (33 | ) | | |
| Net
borrowings of divested companies | | | | | (192 | ) |
| Exchange differences on net borrowings and other
changes | (141 | ) | (687 | ) | (517 | ) |
| Dividends
paid and changes in non-controlling interest and reserves | (2,956 | ) | (4,099 | ) | (4,327 | ) |
| CHANGE IN NET BORROWINGS | (4,679 | ) | (3,064 | ) | (1,913 | ) |

i i i

n ROACE Return On Average Capital Employed for the Group, on an adjusted basis is the return on the Group average capital invested, calculated as ratio of net adjusted profit before non-controlling interests, plus net finance charges on net borrowings net of the related tax effect, to net average capital employed. The tax rate applied on finance charges is the Italian statutory tax rate of 34%. The capital invested, as of the period end, used for the calculation of net average capital invested is obtained by deducting inventory gains or losses in the period, net of the related tax effect. ROACE by Division is determined as ratio of adjusted net profit to net average capital invested pertaining to each Division and rectifying the net capital invested as of period-end, from net inventory gains or losses (after applying the business specific tax rate).

i i i

ROACE - Return On Average Capital Employed (euro million) 2009 2010 2011

| Adjusted
net profit | 6,157 | 7,934 | 7,912 |
| --- | --- | --- | --- |
| Exclusion of after-tax finance expenses/interest
income | 283 | 337 | 454 |
| Adjusted
net profit unlevered | 6,440 | 8,271 | 8,366 |
| Adjusted capital employed, net: | | | |
| -
at the beginning of period | 66,886 | 73,106 | 81,847 |
| - at the end of
period | 72,915 | 81,237 | 87,701 |
| Adjusted
average capital employed, net | 69,901 | 77,172 | 84,774 |
| Adjusted ROACE (%) | 9.2 | 10.7 | 9.9 |

i i i

n Pro-forma adjusted EBITDA EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization charges) on an adjusted basis is calculated by adding amortization and depreciation charges to adjusted operating profit, which is also modified to take into account the impact associated with certain derivatives instruments as detailed below. This performance indicator includes the adjusted EBITDA of Enis wholly owned subsidiaries and Enis share of adjusted EBITDA generated by certain associates which are accounted for under the equity method for IFRS purposes. The EBITDA reported by Regulated businesses in Italy is included according to Enis share of equity in the parent company Snam SpA (55.53% as of December 31, 2011, which takes into account the amount of own shares held in treasury by the subsidiary itself) due to its listed company status. In order to calculate the EBITDA pro-forma adjusted, the adjusted operating profit of the Marketing business has been modified to take into account the impact of the settlement of certain commodity and exchange rate derivatives that do not meet the formal criteria to be classified as hedges under the IFRS. These are entered into by the Company in view of certain amounts of gas and electricity that the Company expects to supply at fixed prices during future periods. The impact of those derivatives has been allocated to the EBITDA pro-forma adjusted relating to the reporting periods during which those supplies at fixed prices are recognized. Management believes that the EBITDA pro-forma adjusted is an important alternative measure to assess the performance of Enis Gas & Power Division, taking into account evidence that this Division is comparable to European utilities in the gas and power generation sector. This measure is provided in order to assist investors and financial analysts in assessing the divisional performance of Eni Gas & Power, as compared to its European peers, as EBITDA is widely used as the main performance indicator for utilities. The EBITDA pro-forma adjusted is a non-GAAP measure under IFRS. n Production Sharing Agreements (PSAs) Contract in use in non OECD Countries, regulating relationships between States and oil companies with regard to the exploration and production of hydrocarbons. The mining concession is assigned to the national oil company jointly with the foreign oil company who has exclusive right to perform exploration, development and production activities and can enter agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractors equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "Cost Oil" is used to recover costs borne by the contractor, "Profit Oil" is divided between contractor and national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions may vary from one Country to the other. n Possible reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. n Probable reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. n Proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which

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Eni in 2011 Financial information

contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. n Recoverable reserves Amounts of hydrocarbons included in different categories of reserves (proved, probable and possible), without considering their different degree of uncertainty. n Reserves Quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods. n Reserve replacement ratio Measure of the reserves produced replaced by proved reserves. Indicates the Companys ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the value of reserves in PSAs due to changes in international oil prices. Management also calculates this ratio by excluding the effect of the purchase of proved property in order to better assess the underlying performance of the Companys operations. n Average reserve life index Ratio between the amount of reserves at the end of the year and total production for the year. n Resource base Oil and gas volumes contained in a reservoir as ascertained based on available engineering and geological data (sum of proved, probable and possible reserves) plus volumes not yet discovered but that are expected to be eventually recovered from the reservoir net of a risk factor (risked exploration resources). n Take-or-pay Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years. n Conversion Refinery process allowing the transformation of heavy fractions into lighter fractions. Conversion processes are cracking, visbreaking, coking, the gasification of refinery residues, etc. The ratio of overall treatment capacity of these plants and that of primary crude fractioning plants is the conversion rate of a refinery. Flexible refineries have higher rates and higher profitability.

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Giuseppe Recchi Chairman He has been Chairman of the Board of Eni since May 2011. He is Vice Chairman of GE Capital SpA; member of the Board of Directors and the compensation and audit committees of Exor SpA (listed at Milan Stock Exchange); member of the European Advisory Board of Blackstone and member of the Massachussetts Institute of Technology E.I. External Advisory Board. He is also member of the executive committees of Confindustria (the Confederation of Italian Industries, where he is Chairman of the Foreign Investment Committee), Assonime (Association of Italian Joint Stock Companies), and Aspen Institute Italia; member of the Trilateral Commission; member of the Board of Directors of FEEM - Eni Enrico Mattei Foundation and of the Italian Institute of Technology. He graduated in Engineering at Polytechnic of Turin. In 1989 he started his career as an entrepreneur at Recchi SpA. From 1994 he has served as Executive Chairman of Recchi America Inc, the US branch of the Group and as Managing Director for the overseas activities of Ferrocemento - Recchi Group (now Condotte SpA). In 1999 he joined General Electric, where he held several managerial positions in Europe and in the USA. He served as Director of GE Capital Structure Finance Group; Managing director for Industrial M&A and Business Development for GE EMEA and as President & CEO of GE Italy. Until May 2011 he was President & CEO of GE South Europe. Paolo Scaroni Chief Executive Officer and General Manager He has been Chief Executive Officer of Eni since June 2005. He is currently Director of Assicurazioni Generali, Non-Executive Deputy Chairman of the London Stock Exchange Group, Director of Veolia Environnement. He is also member of the Board of Overseers of Columbia Business School, in New York, and Director of Fondazione Teatro alla Scala. After graduating in Economics and Business at the Luigi Bocconi University, in Milan, in 1969, he worked for three years at Chevron, and obtained an MBA from Columbia University, in New York, and continued his career at McKinsey. In 1973, he joined Saint Gobain, where he held a series of managerial positions in Italy and abroad, until his appointment as Head of the Glass Division in Paris in 1984. From 1985 to 1996 he was Deputy Chairman and Chief Executive Officer of Techint. In 1996, he moved to the UK and was Chief Executive Officer of Pilkington until May 2002. From May 2002 to May 2005 he was Chief Executive Officer and Chief Operating Officer of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro. In November 2007 he was decorated as Officer of the Légion dhonneur. Carlo Cesare Gatto He has been a Director of Eni since May 2011. He graduated in Economics and Business at the Università degli Studi of Turin. He is a registered public auditor. He is currently Chairman of the Board of Statutory Auditors of RAI SpA, Natuzzi SpA and Difesa Servizi SpA, Chairman of the Board of Directors of DeaPrinting Officine Grafiche Novara 1901 SpA, and Chairman of Flenco Fluid System Srl and Director of Arcese Trasporti SpA. He was teacher of Finance, Administration and Control at the Isvor Fiat SpA training institute. In 1968 he was hired by Impresit as Chief Accountant, and managed, in Jordan, the finance department of the local branch. He joined the Fiat Group in 1969 where over the years he held a series of positions of increasing responsibility in the area of finance, administration and control. In 1993 he was the Italian Representative at the European Commission for the fiscal harmonization of member States. In 1992 he was decorated as Cavaliere Ordine al Merito della Repubblica Italiana and, in 1995, as Ufficiale Ordine al Merito della Repubblica Italiana. Alessandro Lorenzi He has been a Director of Eni since May 2011. He graduated in Political Science at the Università degli Studi of Turin. He is currently a founding partner of Tokos Srl, a consulting firm for securities investment, and Chairman of Società Metropolitana Acque Torino SpA. He began his career at SAIAG SpA. In 1975 he joined Fiat Iveco SpA where he held a series of positions. In 1983 he joined GFT Group where he was: Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA In 1998 he was appointed Central Manager, and subsequently Director of Ersel SIM SpA. In 2000 he became Central Manager of Planning and Control at the Ferrero Group and General Manager of Soremartec. In May 2003 he was appointed CFO of Coin Group. In 2006 he became Central Corporate Manager at Lavazza SpA, becoming member of the Board of Directors from 2008 to June 2011. Until this date, he was also Director of LCS Srl as well as Chairman of COFINCAF SpA until May 2011. Paolo Marchioni He has been a Director of Eni since June 2008. He is a qualified lawyer specializing in penal and administrative law, counselor in Supreme Court and superior jurisdictions. He is currently Director of the Provincial Board of the Province of Verbano-Cusio-Ossola. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010. He acts as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola waste water consortium, and the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of the Stresa city council. From October 2001 to April 2004 he was Director of CIM SpA of Novara (merchandise interport center) and from December 2002 to December 2005 Director and member of the executive committee of Finpiemonte SpA. From June 2005 to June 2008 he was Director of Consip. He was Provincial Councillor in charge of balance sheet, property, legal affairs and production activities and Vice President of the Province of Verbano-Cusio-Ossola from June 2009 to October 2011. Roberto Petri He has been a Director of Eni since May 2011. Born in 1949. He has a degree in Law from the Università degli Studi Gabriele DAnnunzio, of Chieti and Pescara. Since 2007, he has been part of the Board of Directors of the Ravenna Festival and since 2011, Chairman of the Board of Directors for the company Italimmobili Srl. In 1976, he was hired by Banca Nazionale del Lavoro (BNL) and filled a number of roles therein. In 1990 he was appointed Commercial Manager of Banca Popolare and in 1994 moved to the Cassa di

(*) Appointed by the Ordinary Shareholders Meeting held on May 5, 2011, for a three-year period. The Board of Directors appointed Paolo Scaroni Chief Executive Officer. The Board mandate will expire with the shareholders meeting approving the financial statements for the year ending December 31, 2013.

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Risparmio di Ravenna Group (Carisp Ravenna and Banca di Imola), where he held the same role. From 2001 and 2006, he was Chief Secretary to the Under-Secretary of Defense, where he was mainly involved with the Departments contacts with the defense industry and international relations. From 2008 to 2011, he was Chief Secretary at the Ministry of Defence. From 2003 to 2006, he was Director of Fintecna SpA and from 2005 to 2008 Director of Finmeccanica SpA. Alessandro Profumo He has been a Director of Eni since May 2011. He graduated in Business Administration at the Università Luigi Bocconi of Milan. He is currently Chairman of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also a member of the Board of Directors of Bocconi University in Milan and of the Fondazione Arnaldo Pomodoro. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development projects at Bain, Cuneo e Associati (now Bain & Company). In 1991 he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà. In 1994 he joined Credito Italiano. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On an international level he was Chairman of the European Banking Federation and Chairman of the IMC Washington. In May 2004 he was decorated as Cavaliere del Lavoro. Mario Resca He has been a Director of Eni since May 2002. He graduated in Economics and Business at the Università Luigi Bocconi of Milan. He is currently General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities. He is also Chairman of Confimprese, Chairman of Convention Bureau Italia SpA, Deputy Chairman of Sesto Immobiliare SpA and Director of Mondadori SpA. After graduating he joined Chase Manhattan Bank. In 1974 he was appointed manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner of Egon Zehnder. In this period he was appointed Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonalds Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners and Chairman of the American Chamber of Commerce. He was decorated as a Cavaliere del Lavoro in June 2002. Francesco Taranto He has been Director of Eni since June 2008. He is currently Director of Cassa di Risparmio di Firenze SpA and ERSEL S.I.M. He started working in 1959, in a stock brokerage in Milan; from 1965 to 1982, he worked at Banco di Napoli as deputy manager of the stock market and securities department. He held a series of managerial positions in the asset management field. Notably he was manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime Group (1987 to 2000), he was Chief Executive Officer of the parent company for a long period. He was also a member of the steering council of Assogestioni and of the Corporate Governance Committee for listed companies formed by Borsa Italiana. He was Director of Enel from October 2000 to June 2008. B OARD C OMMITTEES Internal Control Committee : Alessandro Lorenzi - Chairman , Carlo Cesare Gatto, Paolo Marchioni and Francesco Taranto Compensation Committee : Mario Resca - Chairman , Carlo Cesare Gatto, Roberto Petri and Alessandro Profumo Nominations Committee: Giuseppe Recchi - Chairman , Alessandro Lorenzi, Alessandro Profumo and Mario Resca Oil - Gas Energy Committee: Alessandro Profumo - Chairman , Alessandro Lorenzi, Paolo Marchioni, Roberto Petri, Mario Resca and Francesco Taranto B OARD OF S TATUTORY A UDITORS Ugo Marinelli - Chairman, Roberto Ferranti, Paolo Fumagalli, Renato Righetti, Giorgio Silva, Francesco Bilotti and Maurizio Lauri E XTERNAL A UDITORS Reconta Ernst & Young SpA G ROUP O FFICERS Paolo Scaroni Chief Executive Officer and General Manager Claudio Descalzi Exploration & Production Chief Operating Officer Umberto Vergine Gas & Power Chief Operating Officer Angelo Fanelli Refining & Marketing Chief Operating Officer Alessandro Bernini Chief Financial Officer Salvatore Sardo Chief Corporate Operations Officer Stefano Lucchini Senior Executive Vice President for Public Affairs and Communication Massimo Mantovani Senior Executive Vice President for General Counsel Legal Affairs Salvatore Meli Executive Vice President for Research and Technological Innovation Marco Petracchini Senior Executive Vice President for Internal Audit Roberto Ulissi Senior Executive Vice President for Corporate Affairs and Governance Raffaella Leone Executive Assistant to the Chief Executive Officer

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Eni in 2011 Directors and officers

n Remuneration (a) The Eni Remuneration System is defined consistently with the recommendations of the Borsa Italianas Code as transposed in the Eni Code. Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the table below reports individual remuneration earned in 2011 by each Member of the Board of Directors and Chief Operating Officers. The overall amount earned by Statutory Auditors and other Managers with strategic responsibilities is reported too.

i i i

Remuneration earned by Directors, Statutory Auditors, Chief Operating Officers, and other Managers with strategic responsibilities

(euro thousand) Variable non-equity remuneration

Name Office Term of office Office expiry () Fixed remuneration Committee membership remuneration Bonuses and other incentives Profit sharing Non-monetary benefits Other remuneration Total Fair Value of equity remuneration (*) Severance indemnity for end of office or termination of employment

| Board of Directors — Roberto
Poli | Chairman | 01.01 - 05.05 | 05.2011 | 262 | | 375 | | | 637 | | 1,000 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Giuseppe Recchi | Chairman | 05.06 - 12.31 | 04.2014 | 500 | | | | | 500 | | |
| Paolo
Scaroni | CEO and General Manager | 01.01 - 12.31 | 04.2014 | 1,430 | | 3,439 | 15 | | 4,884 | 175 | 1,000 |
| Alberto Clô | Director | 01.01 - 05.05 | 05.2011 | 40 | 16 | | | | 56 | | |
| Paolo
Andrea Colombo | Director | 01.01 - 05.05 | 05.2011 | 40 | 13 | | | | 53 | | |
| Carlo Cesare Gatto | Director | 05.06 - 12.31 | 04.2014 | 75 | 32 | | | | 107 | | |
| Alessandro
Lorenzi | Director | 05.06 - 12.31 | 04.2014 | 75 | 38 | | | | 113 | | |
| Paolo Marchioni | Director | 01.01 - 12.31 | 04.2014 | 115 | 39 | | | | 154 | | |
| Roberto
Petri | Director | 05.06 - 12.31 | 04.2014 | 75 | 24 | | | | 99 | | |
| Alessandro Profumo | Director | 05.06 - 12.31 | 04.2014 | 75 | 29 | | | | 104 | | |
| Marco
Reboa | Director | 01.01 - 05.05 | 05.2011 | 40 | 16 | | | | 56 | | |
| Mario Resca | Director | 01.01 - 12.31 | 04.2014 | 115 | 45 | | | | 160 | | |
| Pierluigi
Scibetta | Director | 01.01 - 05.05 | 05.2011 | 40 | 13 | | | | 53 | | |
| Francesco Taranto | Director | 01.01 - 12.31 | 04.2014 | 115 | 45 | | | | 160 | | |
| Board
of Statutory Auditors | | | | 435 | | | | 85 | 520 | | |
| Chief Operating Officers | | | | | | | | | | | |
| Claudio
Descalzi | E&P Division | 01.01 - 12.31 | | 754 | | 1,167 | 15 | 595 | 2,531 | 24 | |
| Domenico Dispenza | G&P Division | 01.01 - 12.31 | | 740 | | 1,339 | 13 | | 2,092 | 41 | 2,844 |
| Angelo
Fanelli | R&M Division | 01.01 - 12.31 | | 541 | | 504 | 14 | | 1,059 | 14 | |
| Other Managers with strategic
responsibilities (***) | | | | 3,910 | | 4,988 | 96 | 120 | 9,114 | 166 | |
| | | | | 9,377 | 310 | 11,812 | 153 | 800 | 22,452 | 420 | 4,844 |

i	i	i
(*)	i	For directors
appointed by the Shareholders Meeting of May 5,
2011, the term of office expires with the
Shareholders Meeting approving the financial
statements for the year ending December 31, 2013.
(**)	i	This refers
to the 2011 pro-rata value (from January 1 to July 30) of
the granting of the 2008 stock option plan in accordance
with the breakdown provided for by the accounting
standards.
(***)	i	Managers who,
during the course of the year and with the Chief
Executive Officer and Chief Operating Officers of
Enis divisions were permanent members of the
management committee and those who report directly to the
Chief Executive Officer (ten managers).

i i i

In particular: - the column "Fixed remuneration" reports, following the criteria of competence, fixed remuneration and fixed salary from employment due for the year, gross of social security and tax expenses to be paid by the employee; it excludes lump-sum expense reimbursements and attendance fees, as they are not envisaged. Details on compensation are provided in the notes, as well as separate indication of any indemnities or payments referred to the employment relationship; - the column "Committees membership remuneration" reports, following the criteria of competence, the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately; - the column "Variable non-equity remuneration - Bonuses and other incentives" reports the incentives paid during the year due to the vesting of the relative rights following the assessment and approval of the relative performance results by the relevant company bodies, in accordance with that specified, in greater detail, in the Table "Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities"; the column "Profit sharing", does not include any figures, as no form of profit-sharing is envisaged; - the column "Non-monetary benefits" reports, in accordance with competence and taxability criteria, the value of fringe benefits awarded; - the column "Other remuneration" reports, in accordance with the criteria of competence, any other remuneration deriving from other services provided; - the column "Total" reports the sum of the amounts of all the previous items;

(a) For detailed information on Enis remuneration policy and compensation see the "Remuneration Report 2012" available on Enis website under the sections Governance and Investor relations.

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the column "Fair value of equity remuneration" reports the fair value of competence of the year related to the existing stock option plans, estimated in accordance with international accounting standards which assign the relevant cost in the vesting period; - the column "Severance indemnities for end of office or termination of employment" reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of financial year considered or in relation to the end of the office and/or employment. The structure of Enis management remuneration system is made up of: (i) fixed remuneration; (ii) short-term variable incentives tied to a target incentive level (performance=100) and a maximum level (performance=130), set at 110% and 155% respectively of the total fixed remuneration, based on the economic/ financial performance and operational results achieved by Eni in the previous year; (iii) long-term variable component consisting of two distinct plans: - Deferred Monetary Incentive Plan (DMI) with three annual awards, starting in 2012, in relation to the performance of the Company measured in terms of EBITDA. The said Plan maintains the same performance conditions and characteristics as described above for the Plan of the Chief Executive Officer and General Manager. For Chief Operating Officers and other Managers with Strategic Responsibilities the base incentive to be assigned at target level is differentiated by the grade of the role up to a maximum equal to 40% of the fixed remuneration. The incentive to be paid at the end of the three-year period in question is determined as a percentage between zero and 170% of the value awarded, in relation to the results achieved; - Long-Term Monetary Incentive Plan (LTMI), envisaged for critical managerial staff. This Plan maintains the same performance conditions and characteristics as envisaged in the Plan of the Chief Executive Officer and General Manager. For Chief Operating Officers and other Managers with Strategic Responsibilities the base incentive to be awarded at target level is differentiated by the grade of the role up to a maximum equal to 50% of the fixed remuneration. The incentive to be paid at the end of the three-year period in question is determined as a percentage between zero and 130% of the value awarded, in relation to the results achieved. Studies regarding possible changes to the current Performance conditions of the Plan are in course, in order to take into account the specific structure of the Eni business portfolio with respect to that of the peer group in question; (iv) benefits : For the Chief Executive Officer and General Manager, unchanged from the previous mandate and the policy enacted in 2011, insurance-related benefits are envisaged and, in particular, in respect of that envisaged in the national collective labor agreement and the additional company agreements for Eni senior managers, enrolment in the complementary retirement plan (FOPDIRE) as well as in the additional health plan (FISDE) are envisaged, together with the use of a company car.

The following table sets out long term variable components.

Bonuses of the year Bonuses of previous years Other bonuses

Name Office (euro thousand) paid/ payable deferred no longer payable paid/ payable (a) still deferred

| Roberto
Poli — Paolo Scaroni | Chairman — CEO and General Manager | 375 — 2,110 | 3,234 | | 1,329 | 6,791 | |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Claudio
Descalzi | Chief
Operating Officer E&P Division | 537 | 672 | | 280 | 962 | 350 |
| Domenico Dispenza (b) | Chief Operating Officer G&P Division | 453 | | 246 | 886 | | |
| Angelo
Fanelli | Chief
Operating Officer R&M Division | 345 | 487 | | 159 | 564 | |
| Other Managers with strategic responsibilities (c) | | 2,587 | 2,829 | | 1,751 | 3,977 | 650 |
| | | 6,407 | 7,222 | 246 | 4,405 | 12,294 | 1,000 |

i	i	i
(a)	i	Payment
relating to deferred monetary incentive granted in 2008
related to EBITDA performance in the three-year period
2008-2010.
(b)	i	In charge
until December 31, 2011. As of January 1, 2012, Umberto
Vergine has been appointed as Gas & Power Chief
Operating Officer.
(c)	i	Managers who,
during the course of the year and with the Chief
Executive Officer and Division Chief Operating Officers,
were permanent members of the Company Management
Committee and the ones who report directly to the Chief
Executive Officer (ten managers).
i	i	i

| n Overall remuneration of key
management personnel Remuneration of persons
responsible of key positions in planning, direction and
control functions of Eni Group companies, including
executive and non-executive Directors, Chief Operating
Officers and other managers with strategic
responsibilities in charge at December 31, 2011, amounted
to euro 34 million, as described in the following table: | 2010 | 2011 |
| --- | --- | --- |
| Fees and
salaries | 20 | 21 |
| Post employment benefits | 1 | 1 |
| Other
long-term benefits | 10 | 10 |
| Indemnity upon termination of the office | 2 | 2 |
| | 33 | 34 |

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n Eni share performance in 2011 As of December 31, 2011, the Companys 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 average number of shares outstanding in the period, considering the treasury shares in Enis portfolio, was 3,622,616,182 (3,622,454,738 in 2010). In the last session of 2011, the Eni share price, quoted on the Italian Stock Exchange, was euro 16.01, down 2.1 percentage points from the price quoted at the end of 2010 (euro 16.34). 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 25.2 percentage points. At the end of 2011, the Eni ADR listed on the NYSE was $41.27, down 5.6% compared to the price registered in the last session of 2010 ($43.74). One ADR is equal to two Eni ordinary shares. In the same period the S&P 500 index increased by 5.5% percentage points. Eni market capitalization at the end of 2011 was euro 58 billion (euro 59.2 billion at the end of 2010), 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 5.9 billion, with an average number of shares traded daily of 22.9 million (20.7 million in 2010). The total trade value of Eni share amounted to approximately euro 92 billion (euro 86 billion in 2010), equal to a daily average of euro 355 million.

i i i

Share information 2009 2010 2011

| Market
quotations for common stock on the Mercato Telematico
Azionario (MTA) — High | (euro) | 18.35 | 18.56 | 18.42 |
| --- | --- | --- | --- | --- |
| Low | (euro) | 12.30 | 14.61 | 12.17 |
| Average daily close | (euro) | 16.59 | 16.39 | 15.95 |
| Year-end
close | (euro) | 17.80 | 16.34 | 16.01 |
| Market quotations for ADR on the New York
Stock Exchange | | | | |
| High | (US$) | 54.45 | 53.89 | 53.74 |
| Low | (US$) | 31.07 | 35.37 | 32.98 |
| Average
daily close | (US$) | 46.36 | 43.56 | 44.41 |
| Year-end close | (US$) | 50.61 | 43.74 | 41.27 |
| Average
daily traded volumes | (million
of shares) | 27.9 | 20.7 | 22.8 |
| Value of traded volumes | (euro million) | 461.7 | 336.0 | 355.0 |

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Share data 2009 2010 2011

| Net profit
pertaining to Eni: — - per share (a) | (euro) | 1.21 | 1.74 | | 1.89 |
| --- | --- | --- | --- | --- | --- |
| - per ADR (a) (b) | (US$) | 3.36 | 4.62 | | 5.27 |
| Adjusted net profit pertaining to Eni: | | | | | |
| - per
share (a) | (euro) | 1.44 | 1.90 | | 1.92 |
| - per ADR (a) (b) | (US$) | 4.01 | 5.04 | | 5.36 |
| Dividend: | | | | | |
| - per share (c) | (euro) | 1.00 | 1.00 | | 1.04 |
| - per ADR (b) | (US$) | 2.79 | 2.65 | | 2.90 |
| Pay-out | (%) | 83 | 57 | | 55 |
| Dividend
yield (d) | (%) | 5.8 | 6.1 | | 6.6 |
| Total shareholder return (TSR) | (%) | 13.7 | (2.2 | ) | 5.1 |
| Number of
shares outstanding: | | | | | |
| - at year end (e) | (million) | 3,622.4 | 3,622.5 | | 3,622.7 |
| - average
(fully diluted) (f) | (million) | 3,622.4 | 3,622.5 | | 3,622.5 |
| Market capitalization (g) | (euro billion) | 64.5 | 59.2 | | 58.0 |

| (a) | Ratio of net
profit and average number of shares outstanding in the
year, assuming dilution. Dollar amounts are converted on
the basis of the average EUR/USD exchange rate quoted by
the ECB for the periods presented. |
| --- | --- |
| (b) | One ADR
(American Depositary Receipt) is equal to two Eni
ordinary shares. |
| (c) | Dividend per
share pertaining to the year. This dividend is paid in
two tranches. An interim dividend is paid in the same
year, as approved by the Board; the balance to the full
year dividend is paid in the following calendar year
(after approval by the Annual Shareholders
Meeting). |
| (d) | Ratio of
dividend for the period to the average price of the Eni
shares recorded on the Italian Stock Exchange in
December. |
| (e) | Excluding
treasury shares. |
| (f) | Calculated by
excluding own shares in portfolio. |
| (g) | Number of
outstanding shares by references price at year end. |

Dividends

Eni announces dividends on its ordinary shares in terms of euros. For the fiscal year 2011, the Annual Shareholders Meeting convened on May 8, 2012, is due to approve a dividend proposal made by the Board of Directors to pay a euro 1.04 a share dividend for 2011. Eni paid an interim dividend for fiscal year 2011 amounting to euro 0.52 per share to shares on the register at the ex-dividend date (September 19, 2011). Following shareholders approval, the balance of euro 0.52 to the 2011 dividend is scheduled for payment on May 24, 2012 (being the ex-dividend date May 21, 2012). Holders of ADRs will receive euro 1.04 per ADR, payable late in May 2012 being May 23, 2012 the ex-dividend date. Eni intends to continue paying interim dividends in the future. Holders of ADRs receive their dividends in US dollars. The rate of exchange used to determine the amount in dollars is equal to the official rate recorded on the date of dividend payment in Italy (May 24, 2012). On ADR payment date, Bank of New York Mellon (until January 17, 2012 the depositary bank was JPMorgan Chase Bank, NA) pays the dividend less the amount of any withholding tax under Italian law (currently 27%) to all Depository Trust Company Participants, representing payment of Eni SpAs gross dividend. By submitting to Bank of New York Mellon certain required documents with respect to each dividend payment, US holders of ADRs will enable the Italian Depositary bank and JPMorgan as ADR Depositary to pay the dividend at the reduced withholding tax rate of 15%. US shareholders can obtain relevant documents as well as a complete instruction packet to benefit from this tax relief by contacting Bank of New York Mellon at 1.201.680.6825.

55 -

Contents

Eni in 2011 Investor information

Publications

| 1 | Annual Report
2011 a comprehensive report on Enis activities
and financial and sustainability results for the year. | 5 |
| --- | --- | --- |
| 2 | Annual Report
on Form 20-F 2011 a comprehensive report on
Enis activities and results to comply with the
reporting requirements of the US Securities Exchange Act
of 1934 and filed with the US Securities and Exchange
Commission. | These
and other Eni publications are available on Enis
internet site eni.com , in the section
"Publications"
(eni.com/sites/ENI_en_IT/documentation/documentation.page?type=bilrap&lef
tbox=documentazione&doc_from=hpeni_left).
Shareholders may receive a hard copy of Enis
publications, free of charge, by filling in the request
form found in the section "Publications" or
through an email request addressed to
[email protected] or to
[email protected]. Any other information
relevant to shareholders and investors can be found at
Enis website under the "Investor
Relations" section. |
| 3 | Fact Book
2011 a report on Enis businesses, strategies,
objectives and development projects, including a full set
of operating and financial statistics. | |
| 4 | Remuneration
Report 2012 a report on Enis compensation and
remuneration policies pursuant to rule 123-ter of
Legislative Decree No. 58/1998. | |

Financial calendar
The dates of the Board of
Directors meetings to be held during 2012 in order
to approve/review the Companys quarterly and
semi-annual, and annual preliminary results are the
following:
n Results for the first quarter of 2012	April 26, 2012	n Results for the third quarter of 2012	October 29, 2012
n Results for the second quarter and first half of 2012 and proposal of interim dividend for the financial year 2012	July 31, 2012	n Preliminary full-year results for the
year ending December 31, 2012 and dividend proposal for
the financial year 2012	February 2013

56 -

Contents

Table of Contents Contents

Table of Contents

Fact Book 2011

| Contents — 4 5 11 15 43 56 66 70 | Eni in 2011 Enis strategy How we operate Exploration
& Production Gas & Power Refining &
Marketing Petrochemicals Engineering
& Construction | Tables — 76 89 90 110 | Financial data Employees Supplemental
oil and gas information Quarterly
information |
| --- | --- | --- | --- |

| Enis
Fact Book is a supplement to Enis 2011 Annual
Report and is designed to provide supplemental financial
and operating information. It contains certain forward-looking statements in
particular under the section "Outlook"
regarding capital expenditure, development and management
of oil and gas resources, dividends, allocation of future
cash flow from operations, future operating performance,
gearing, targets of production and sale growth, new
markets, and the progress and timing of projects. By
their nature, forward-looking statements involve risks
and uncertainties because they relate to events and
depend on circumstances that will or may occur in the
future. Actual |
| --- |
| Periodical updates
will be available on the web site: www.factbook.eni.com |

Contents

Eni Fact Book Eni

Eni is an integrated company engaged in the energy chain. Enis strong presence in the gas market and in the liquefaction of natural gas, our skills in the power generation and refinery activities, strengthened by world class skills in engineering and project management, allow us to catch opportunities in the market and to realize integrated projects. In 2011, adjusted net profit was euro 6.97 billion, up 1.5% from a year ago driven by an excellent performance reported by an excellent performance reported by the Exploration & Production Division on the back of a recovery in crude oil prices. This positive helped the Company withstand the impact of the production shut down in Libya and the sharp contraction in results of the Companys downstream businesses dragged down by the economic downturn. Return on Average Capital Employed (ROACE) calculated on an adjusted basis was 9.9%. Net cash generated by operating activities amounted to euro 14.38 billion. Proceeds from divestments amounted to euro 1.9 billion. These inflows enabled the Company to fund the major part of the financing requirements associated with capital expenditure and other investments of euro 13.8 billion and shareholders remuneration. The ratio of net borrowings to total equity was 0.46 at year end (0.47 at December 31, 2010). The Board of Directors suggested to the Shareholders Meeting the distribution of a dividend of euro 1.04 per share for 2011 full year. In 2011, the injury frequency rate decreased by 22% and 15.9% relating to employees and contractors respectively, compared to the previous year. This positive trend progressed for the sixth consecutive year. In 2011, Eni continued its commitment in incident prevention also by means of training programs on safety and emergency prevention. In 2011, the Exploration & Production Division reported adjusted net profit amounting to euro 6.87 billion (up 22.6% from 2010). Liquids and gas production was 1,581 kboe/d, down by 12.9% from 2010, mainly due to a lowered output in Libya. Estimated net proved reserves at December 31, 2011, were 7.09 bboe. All sources reserves replacement ratio was 142%. Excluding price effect, the replacement ratio would be 159%. The reserves life index is 12.3 years (10.3 years in 2010). In 2011, the Gas & Power Division reported adjusted net profit of euro 1.54 billion, down 39.8% from 2010 due to a sharply lower operating performance of the Marketing business (adjusted operating profit was down euro 1.28 billion) negatively impacted by weak domestic demand (down 6%), and mounting competitive pressures fuelled by oversupply which squeezed selling margins and reduced volumes opportunities. The performance was also impacted by the disruption in Libyan gas availability which negatively impacted the supply mix and reduced sales to importers. Sales in Italy were basically stable (up 1.1%) despite declining demand. Sales in target European markets increased by approximately 8%. In 2011, the Refining & Marketing segment reported adjusted operating loss of euro 262 million worsening by euro 213 million from 2010, reflecting unprofitable refining margins due to rising costs for oil-based feedstock and for energy utilities linked to the former that could not be transferred to prices at the pump, also due to weak demand and excess capacity in the Mediterranean basin. Marketing results were positive but shrinking due to the decline in retail and wholesale demand for products and high competitive pressure. Despite a decline in retail sales in Italy (down 3%) Enis average retail market share for 2011 was 30.5%, up from 2010 due to commercial initiatives and a strong brand name. In 2011, the Engineering & Construction sector achieved an adjusted net profit amounting to euro 1.1 billion and a flow of new orders that allowed to keep its order backlog to a record of over euro 20 billion. In 2011, the sector reported a significant increase in adjusted net loss (euro 208 million, down euro 123 million) from 2010, due to lower cracker margins and lower sales volumes, in particular of commodity production. Niche business segments of elastomers and styrenes improved their profitability due to their higher technological content.

Contents

Eni Fact Book Eni

The oil&gas industry is coping with a complex scenario featured by the global economic slowdown, particularly in the Euro-zone, and volatile market conditions for energy commodities. In the medium to long-term the main challenges will be driven by rising competitive pressures in accessing reserves by new players, stricter regulation addressing environmental preservation and mitigation of the climate risk, a growing importance of renewable sources as well as the role of unconventional resources in satisfying energy need. Against this backdrop, Eni confirms its growth strategy and the adoption of a sustainable business model founded on the pillars of innovation, excellence, inclusiveness, integration, responsibility and cooperation in a framework of straightforward rules of corporate governance. Eni believes that a sustainable business conduct contributes to both the achievement of industrial performance, and the mitigation of political, financial and operational risks. This strengthens Enis role as a trustworthy and reliable partner, who is ready to capture new opportunities in the marketplace and able to manage the complexities of the environment. Eni believes that those drivers will help the Company to create value to its shareholders and stakeholders. Eni has designed its industrial plan for the four-year period 2012-2015 along the following strategic guidelines: growing profitable oil and gas production in the upstream, strengthening market leadership in the European gas market, improving downstream oil efficiency, refocusing petrochemical operations and retaining top spots among the best-in-class engineering and construction players in the most technologically advanced segments. In the medium-term, Eni intends to preserve a solid capital structure while continuing to invest to fuel profitable growth and reward investors. Management is targeting a net debt to equity ratio of less than 0.4 by the end of the plan period which takes into account a capital expenditure plan of euro 59.6 billion, of which 75% dedicated to upstream activities. Enis ability to generate strong operating cash flows, investment selection and capital efficiency will underpin the Companys financial structure. In the Exploration & Production Division, Eni intends to deliver organic production growth with increasing returns and reserve replacement. The Companys value proposition in its upstream operations will leverage on strengthening our leadership in core areas, increasing the volume of operated production and retaining a strong portfolio of long-term plateau fields. Eni will pursue further growth options by developing unconventional plays, gas-to-LNG projects and integrated gas projects. Enis growth trajectory will be supported by its ongoing commitment in establishing and consolidating its partnerships with key host Countries, leveraging the Eni co-operation model. Management expects that continuing technological innovation and competence build-up will drive production growth and increasing rates of reserve recovery, developing drilling techniques to be applied in complex environment, marginal fields and deep/ultra deep offshore areas. Management is targeting to increase hydrocarbon production to 2.03 mmboe/d by 2015 at an average rate of more than 3% over the next four years. Growth will be fuelled by increasing flows from Enis core areas (in Sub-Saharan Africa in particular in Mozambique, Venezuela, Barents Sea, Yamal Peninsula in Russia, Kazakhstan, Iraq and Indonesia) leveraging Enis vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. Enis exploration activity will play a vital role in securing access to new resources and the long-term business sustainability and we are planning to step-up expenditures over the next four-year plan compared to our previous capital budget (an increase of approximately euro 2 billion). Management plans to achieve a sound balance between exploration projects in legacy areas vs. high risk/high reward basins. Eni intends to drive higher returns and manage the operational risk in its upstream operations by reducing the time-to-market of its portfolio of resources, increasing total volumes of operated production, as operatorship is seen to be the safest way to control risks, as well as selectively picking partners in non-operated joint-projects. Eni plans to monetize its reserves of associated gas in particular in Algeria, Angola, Congo, Iraq, Italy, Libya,

Contents

Eni Fact Book Eni

Nigeria, Norway and Turkmenistan, targeting to cut the level of gas flaring by 80% from 2007 levels over the next four-years plan. Management is ready to invest approximately euro 4 billion to achieve that target. In the Gas & Power Division, Eni plans to strengthen its leadership in the European gas markets in spite of increasing competitive pressures, oversupply and weak gas spot prices. Management intends to leverage on: (i) the renegotiation of the economic conditions of Enis key supply contracts in order to improve the competitiveness of Enis gas portfolio; (ii) extracting value from Enis logistics assets and its presence at the continental hubs; (iii) developing an international commercial platform and a multi-Country approach; (iv) boosting LNG sales; (v) enhancing of Enis gas and power commercial offer, continuing service improvement and customer care through the adoption of systems and processes which best suit customers needs, mainly in retail markets. We target to recover a fair level of profitability in the G&P Marketing business. Regulated businesses in Italy are committed to develop additional transport and storage capacity, focusing on improving infrastructure reliability and flexibility as well as efficient operations. In particular, EniPower is planning to upgrade the energy efficiency at proprietary plants in order to retain an index of CO 2 emissions below the target level of 415 g CO 2 /kWheq. Eni will continue pursuing the OHSAS 18001 certification for its health and safety management systems at all its plants. In the Refining & Marketing Division, Eni will strive to regain profitability against the backdrop of a depressed trading environment. Eni will boost its refining operations by means of optimizations and integration of refinery cycles and cost and energy efficiencies. Eni will pursue strict capital discipline by focusing on projects intended to upgrade the complexity and reliability of our refineries, and to improve the environmental performance. In marketing operations, considering a weak demand outlook for fuels, management plans to strengthen Enis leadership in the Italian retail market leveraging on commercial initiatives to best suit customers needs, a differentiated offer, process automation, enhancing non-oil activities, retaining customers and strengthening our brand. Abroad, Eni will grow selectively in target European markets and divest marginal assets. Management plans to improve results of the Refining & Marketing Division by over euro 500 million within 2015, excluding any change in market context, through efficiency improvements. Eni expects to grow middle distillate yield s to 50% (vs. 47% in 2011) and, in marketing, we are targeting a market share up to 30% in the Italian retail sector. Energy saving programs will be strengthened by implementing the Energy Management System at refinery plants in accordance with the ISO 50001 international standard. Eni will also invest euro 25.6 million to reduce SO x and NO x emissions by 2013 on a comparable production basis. To cope with the structural challenges of Petrochemical business, management is implementing a strategic shift targeting to restore the economic equilibrium of the business over the medium-term. This new strategy features a gradual reduction of the exposure to the unprofitable, commoditized businesses in favor of growing the

Contents

Eni Fact Book Eni

Companys presence in niche productions, particularly elastomers and specialties which have shown good profitability. Eni will pursue this goal by reconverting and restructuring loss-making plants, improving plant integration and flexibility, as well as optimization projects. Eni intends to growth its presence in green chemistry leveraging its joint venture project at Porto Torres in Sardinia which targets the restructuring of an obsolete plant into a modern and advanced facility for the production of environmentally-friendly chemicals. The licensing of Enis proprietary technologies will support the establishment of strategic alliances with international partners. Over the next four years, Eni will make capital expenditure amounting to euro 1.7 billion, targeting plant upgrading and enhancement in the best positioned businesses, mainly in elastomers. In the medium term Eni plans to break-even business results. made to boost local assets and logistic centers in key areas (in particular in Brazil) will support the competitive advantages. Management believes that the achievement of Enis projected targets and expected returns will be underpinned by Enis operational excellence, synergies from integration and the development of integrated risk management capabilities intended to extract value from Enis assets. Operational excellence thanks to Enis know-how and distinctive competences endorses a preventive business conduct when managing the environmental footprint of Enis operations and risks to employees and communities health and safety. Continuing improvement in efficiency through innovation of business processes will enable the Company to reduce the energy intensity of its productions, optimize plants activities and achieve economies of scale in centralized services.

Engineering & Construction segment will consolidate its leading position in the Offshore and Onshore businesses leveraging the EPIC-oriented business model and outstanding relationships with the Majors and NOCs. Saipem will continue focusing on the execution of technologically-advanced mega-projects mainly located in frontier areas and complex environments, carefully selecting business opportunities. The upgrading of a world-class drilling and construction offshore fleet, the availability of an important construction yard in Indonesian targeting offshore projects, as well as the expenditures Integration will enable Eni to capture joint opportunities in the marketplace, reaping the benefits of synergies and maximizing asset returns. Particularly, the new business unit Eni trading will develop integrated risk management activities with a view of better coping with the increasingly volatile commodity markets.

Contents

Eni Fact Book Eni

Main data

Key financial data Italian GAAP IFRS

(euro million) 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

| Net sales from operation — Operating
profit | 8,502 | | 51,487 — 9,517 | | 57,498 — 12,399 | | 73,692 — 16,664 | | 86,071 — 19,336 | | 87,204 — 18,739 | | 108,082 — 18,517 | | 83,227 — 12,055 | | 98,523 — 16,111 | | 109,589 — 17,435 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Special items | | | | | (448 | ) | (1,210 | ) | 88 | | (620 | ) | 936 | | (345 | ) | (881 | ) | (1,113 | ) |
| Profit
(loss) on stock | | | | | 631 | | 1,942 | | 1,059 | | 885 | | 2,155 | | 1,412 | | 2,074 | | 1,652 | |
| Adjusted operating profit | 8,959 | | 9,958 | | 12,582 | | 17,396 | | 20,483 | | 19,004 | | 21,608 | | 13,122 | | 17,304 | | 17,974 | |
| Exploration
& Production | 5,428 | | 5,973 | | 8,202 | | 12,649 | | 15,521 | | 13,770 | | 17,222 | | 9,484 | | 13,884 | | 16,077 | |
| Gas & Power | 3,373 | | 3,661 | | 3,448 | | 3,783 | | 4,117 | | 4,414 | | 3,564 | | 3,901 | | 3,119 | | 1,946 | |
| Refining
& Marketing | 312 | | 584 | | 923 | | 1,210 | | 794 | | 292 | | 580 | | (357 | ) | (171 | ) | (535 | ) |
| Petrochemicals | (48 | ) | (54 | ) | 263 | | 261 | | 219 | | 116 | | (398 | ) | (426 | ) | (113 | ) | (276 | ) |
| Engineering
& Construction | 298 | | 311 | | 215 | | 314 | | 508 | | 840 | | 1,041 | | 1,120 | | 1,326 | | 1,443 | |
| Other
activities | (208 | ) | (236 | ) | (223 | ) | (296 | ) | (299 | ) | (207 | ) | (244 | ) | (258 | ) | (205 | ) | (226 | ) |
| Corporate
and financial companies | (196 | ) | (281 | ) | (187 | ) | (384 | ) | (244 | ) | (195 | ) | (282 | ) | (342 | ) | (265 | ) | (266 | ) |
| Impact of
unrealized intragroup profit elimination | | | | | (59 | ) | (141 | ) | (133 | ) | (26 | ) | 125 | | | | (271 | ) | (189 | ) |
| Net profit | 4,593 | | 5,585 | | 7,059 | | 8,788 | | 9,217 | | 10,011 | | 8,825 | | 4,367 | | 6,318 | | 6,860 | |
| Adjusted net profit | 4,923 | | 5,096 | | 6,645 | | 9,251 | | 10,401 | | 9,569 | | 10,164 | | 5,207 | | 6,869 | | 6,969 | |
| Net cash
provided by operating activities | 10,578 | | 10,827 | | 12,500 | | 14,936 | | 17,001 | | 15,517 | | 21,801 | | 11,136 | | 14,694 | | 14,382 | |
| Capital expenditures and investments | 9,414 | | 13,057 | | 7,815 | | 7,560 | | 7,928 | | 20,502 | | 18,867 | | 16,018 | | 14,280 | | 13,798 | |
| Capital
expenditures | 8,048 | | 8,802 | | 7,499 | | 7,414 | | 7,833 | | 10,593 | | 14,562 | | 13,695 | | 13,870 | | 13,438 | |
| Investments | 1,366 | | 4,255 | | 316 | | 146 | | 95 | | 9,909 | | 4,305 | | 2,323 | | 410 | | 360 | |
| Shareholders
equity including non-controlling interest | 28,351 | | 28,318 | | 35,540 | | 39,217 | | 41,199 | | 42,867 | | 48,510 | | 50,051 | | 55,728 | | 60,393 | |
| Net borrowings | 11,141 | | 13,543 | | 10,443 | | 10,475 | | 6,767 | | 16,327 | | 18,376 | | 23,055 | | 26,119 | | 28,032 | |
| Net
capital employed | 39,492 | | 41,861 | | 45,983 | | 49,692 | | 47,966 | | 59,194 | | 66,886 | | 73,106 | | 81,847 | | 88,425 | |
| Exploration
& Production | 17,318 | | 17,340 | | 16,770 | | 19,109 | | 17,783 | | 23,826 | | 31,302 | | 32,455 | | 37,646 | | 42,024 | |
| Gas
& Power | 12,488 | | 15,617 | | 19,554 | | 20,075 | | 19,713 | | 21,333 | | 21,614 | | 24,754 | | 27,346 | | 27,760 | |
| Refining &
Marketing | 5,093 | | 5,089 | | 5,081 | | 5,993 | | 5,631 | | 7,675 | | 7,379 | | 8,105 | | 8,321 | | 9,188 | |
| Petrochemicals | 2,130 | | 1,821 | | 2,076 | | 2,018 | | 1,953 | | 2,228 | | 1,915 | | 1,774 | | 1,978 | | 2,252 | |
| Engineering
& Construction | 2,335 | | 2,119 | | 2,403 | | 2,844 | | 3,399 | | 4,313 | | 5,022 | | 6,566 | | 7,610 | | 8,217 | |
| Corporate
financial companies and other activities | 128 | | (125 | ) | 277 | | 2 | | (95 | ) | 294 | | 24 | | (192 | ) | (527 | ) | (393 | ) |
| Impact of
unrealized intragroup profit elimination | | | | | (178 | ) | (349 | ) | (418 | ) | (475 | ) | (370 | ) | (356 | ) | (527 | ) | (623 | ) |
| Return On
Average Capital Employed (ROACE) | (%) | | | | | | | | | | | | | | | | | | | |
| Reported | 13.7 | | 15.6 | | 16.6 | | 19.5 | | 20.2 | | 20.5 | | 15.7 | | 8.0 | | 10.0 | | 9.7 | |
| Adjusted | | | | | 15.9 | | 20.5 | | 22.6 | | 19.4 | | 17.6 | | 9.2 | | 10.7 | | 9.9 | |
| Leverage | 0.39 | | 0.48 | | 0.29 | | 0.27 | | 0.16 | | 0.38 | | 0.38 | | 0.46 | | 0.47 | | 0.46 | |

Key market indicators 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Average price of Brent dated crude oil (a)		24.98	28.84	38.22	54.38	65.14	72.52	96.99	61.51	79.47	111.27
Average
EUR/USD exchange rate (b)		0.946	1.131	1.244	1.244	1.256	1.371	1.471	1.393	1.327	1.392
Average price in euro of Brent dated crude oil		26.41	25.50	30.72	43.71	51.86	52.90	65.93	44.16	59.89	79.94
Average
European refining margin (c)		0.80	2.65	4.35	5.78	3.79	4.52	6.49	3.13	2.66	2.06
Average European refining margin Brent/Ural (c)		1.40	3.40	7.03	8.33	6.50	6.45	8.85	3.56	3.47	2.90
Euribor -
three-month euro rate	(%)	3.3	2.3	2.1	2.2	3.1	4.3	4.6	1.2	0.8	1.4

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

Contents

Eni Fact Book Eni

Selected operating data 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

| Corporate — Employees
at period end | (number) | 80,540 | 76,529 | 71,572 | 71,773 | 72,850 | 75,125 | 78,094 | 77,718 | 79,941 | 78,686 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: | | | | | | | | | | | |
| - women | | 10,274 | 11,155 | 10,326 | 10,620 | 10,841 | 10,977 | 12,221 | 12,564 | 12,754 | 13,185 |
| - outside Italy | | 39,329 | 36,678 | 32,691 | 34,036 | 35,818 | 38,634 | 41,971 | 42,633 | 45,967 | 45,516 |
| Female
managers | (%) | 10.9 | 10.9 | 12.5 | 12.4 | 13.5 | 14.1 | 16.0 | 17.0 | 17.7 | 18.2 |
| Employee injury frequency rate | (number of
injuries/million of worked hours) | 4.74 | 3.79 | 3.99 | 2.74 | 2.45 | 1.93 | 1.45 | 1.00 | 0.91 | 0.71 |
| Contractor
injury frequency rate | | 4.71 | 4.12 | 7.84 | 2.59 | 1.54 | 1.45 | 1.40 | 1.18 | 0.88 | 0.74 |
| Oil spills | (barrels) | 2,198 | 857 | 7,813 | 6,908 | 6,151 | 6,731 | 4,749 | 6,259 | 4,269 | 7,295 |
| Oil spills
due to sabotage and terrorism | | n.a. | n.a. | n.a. | 1,810 | 7,014 | 2,608 | 2,286 | 15,288 | 18,695 | 6,127 |
| GHG emission | (mmtonnes CO 2 eq) | 52.84 | 52.27 | 58.34 | 61.85 | 60.72 | 67.25 | 62.01 | 57.69 | 60.64 | 51.10 |
| R&D
expenditures (a) | (euro million) | 175 | 238 | 257 | 204 | 222 | 208 | 217 | 207 | 221 | 191 |
| Exploration & Production | | | | | | | | | | | |
| Proved
reserves of hydrocarbons at period end | (mmboe) | 7,030 | 7,272 | 7,218 | 6,837 | 6,436 | 6,370 | 6,600 | 6,571 | 6,843 | 7,086 |
| Reserve life index | (years) | 13.2 | 12.7 | 12.1 | 10.8 | 10.0 | 10.0 | 10.0 | 10.2 | 10.3 | 12.3 |
| Hydrocarbons
production | (kboe/d) | 1,472 | 1,562 | 1,624 | 1,737 | 1,770 | 1,736 | 1,797 | 1,769 | 1,815 | 1,581 |
| Gas & Power | | | | | | | | | | | |
| Sales of
consolidated companies (including own consumption) | (bcm) | 66.14 | 71.39 | 76.49 | 82.62 | 85.76 | 84.83 | 89.32 | 89.60 | 82.00 | 84.37 |
| Sales of Enis affiliates (Enis
share) | (bcm) | 2.40 | 6.94 | 5.84 | 7.08 | 7.65 | 8.74 | 8.91 | 7.95 | 9.41 | 9.53 |
| Total
sales and own consumption (G&P) | (bcm) | 68.54 | 78.33 | 82.33 | 89.70 | 93.41 | 93.57 | 98.23 | 97.55 | 91.41 | 93.90 |
| E&P gas sales (b) | (bcm) | | | 4.70 | 4.51 | 4.69 | 5.39 | 6.00 | 6.17 | 5.65 | 2.86 |
| Worldwide
gas sales | (bcm) | 68.54 | 78.33 | 87.03 | 94.21 | 98.10 | 98.96 | 104.23 | 103.72 | 97.06 | 96.76 |
| Electricity sold | (TWh) | 6.74 | 8.65 | 16.95 | 27.56 | 31.03 | 33.19 | 29.93 | 33.96 | 39.54 | 40.28 |
| Refining & Marketing | | | | | | | | | | | |
| Throughputs on own account | (mmtonnes) | 37.73 | 35.43 | 37.69 | 38.79 | 38.04 | 37.15 | 35.84 | 34.55 | 34.80 | 31.96 |
| Balanced
capacity of wholly-owned refineries at period end | (kbbl/d) | 504 | 504 | 504 | 524 | 534 | 544 | 737 | 747 | 757 | 767 |
| Sales of refined products (c) | (mmtonnes) | 52.24 | 50.43 | 53.54 | 51.63 | 51.13 | 50.15 | 49.16 | 45.59 | 46.80 | 45.02 |
| Retail
sales in Europe (c) | (mmtonnes) | 13.71 | 14.01 | 14.40 | 12.42 | 12.48 | 12.65 | 12.03 | 12.02 | 11.73 | 11.37 |
| Service stations at year end (c) | (units) | 10,762 | 10,647 | 9,140 | 6,282 | 6,294 | 6,440 | 5,956 | 5,986 | 6,167 | 6,287 |
| Average
throughput per service station | (kliters/y) | 1,674 | 1,771 | 1,970 | 2,479 | 2,470 | 2,486 | 2,502 | 2,477 | 2,353 | 2,206 |
| Petrochemicals | | | | | | | | | | | |
| Production | (ktonnes) | 7,116 | 6,907 | 7,118 | 7,282 | 7,072 | 8,795 | 7,372 | 6,521 | 7,220 | 6,245 |
| of which: | | | | | | | | | | | |
| - Basic
petrochemicals | | 4,304 | 4,014 | 4,236 | 4,450 | 4,275 | 5,688 | 5,110 | 4,350 | 4,860 | 4,101 |
| - Polymers | | 2,812 | 2,893 | 2,882 | 2,832 | 2,797 | 3,107 | 2,262 | 2,171 | 2,360 | 2,144 |
| Average
plant utilization rate | (%) | 74.3 | 71.3 | 75.2 | 78.4 | 76.4 | 80.6 | 68.6 | 65.4 | 72.9 | 65.3 |
| Engineering &
Construction | | | | | | | | | | | |
| Orders
acquired | (euro million) | 7,852 | 5,876 | 5,784 | 8,395 | 11,172 | 11,845 | 13,860 | 9,917 | 12,935 | 12,505 |
| Order backlog at year end | (euro million) | 10,065 | 9,405 | 8,521 | 10,122 | 13,191 | 15,390 | 19,105 | 18,370 | 20,505 | 20,417 |

i	i	i
(a)	i	Net of
general and administrative costs.
(b)	i	Includes
E&P gas sales in Europe (4.70, 4.51, 4.07, 3.59,
3.36, 2.57, 2.33 and 2.29 bcm in 2004, 2005, 2006, 2007,
2008, 2009, 2010 and 2011, respectively) and in the Gulf
of Mexico (0.62, 1.80, 2.64, 3.60, 3.32 and 0.57 in 2006,
2007, 2008, 2009, 2010 and 2011, respectively).
(c)	i	2008-2009
data do not include downstream activities in the Iberian
Peninsula divested to Galp in October 2008.

i i i

Share data Italian GAAP IFRS

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Net profit (a)	(euro)	1.20	1.48	1.87	2.34	2.49	2.73	2.43		1.21	1.74		1.89
Dividend	(euro)	0.75	0.75	0.90	1.10	1.25	1.30	1.30		1.00	1.00		1.04
Dividend pertaining to the year (b)	(euro million)	2,833	2,828	3,384	4,086	4,594	4,750	4,714		3,622	3,622		3,695
Cash flow	(euro)	2.76	2.87	3.31	3.97	4.59	4.23	5.99		3.07	4.06		3.97
Dividend yield (c)	(%)	5.2	5.1	4.9	4.7	5.0	5.3	7.6		5.8	6.1		6.6
Net profit
per ADR (d)	(US$)	2.52	3.72	4.66	5.81	6.26	7.49	7.15		3.36	4.62		5.27
Dividend per ADR (d)	(US$)	1.71	1.83	2.17	2.74	3.14	3.56	3.82		2.79	2.65		2.90
Cash flow
per ADR (d)	(US$)	5.79	7.22	8.96	9.40	11.53	11.60	17.63		8.56	10.77		11.05
Dividend yield per ADR (c)	(%)	5.8	5.0	5.0	4.7	5.0	5.3	7.6		5.8	6.1		6.6
Pay-out	(%)	62	51	48	46	50	47	53		83	57		55
Number of shares at period-end representing
share capital	(million shares)	4,001.8	4,002.9	4,004.4	4,005.4	4,005.4	4,005.4	4,005.4		4,005.4	4,005.4		4,005.4
Average
number of share outstanding in the year (e) (fully diluted)	(million shares)	3,826.9	3,778.4	3,771.7	3,763.4	3,701.3	3,669.2	3,638.9		3,622.4	3,622.5		3,622.7
TSR	(%)	13.1	4.3	28.5	35.3	14.8	3.2	(29.1	)	13.7	(2.2	)	5.1

i	i	i
(a)	i	Calculated on
the average number of Eni shares outstanding during the
year.
(b)	i	Amounts due
on the payment of the balance of 2011 dividend are
estimated.
(c)	i	Ratio between
dividend of the year and average share price in December.
(d)	i	One ADR
represents 2 shares. Net profit, dividends and cash flow
data were converted using average exchange rates.
Dividends data were converted at the Noon Buying Rate of
the pay-out date.
(e)	i	Calculated by
excluding own shares in portfolio.

i - 9 -

Contents

Eni Fact Book Eni

Share information 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

| Share price - Milan Stock
Exchange — High | (euro) | 17.15 | 15.75 | 18.75 | 24.96 | 25.73 | 28.33 | 26.93 | 18.35 | 18.56 | 18.42 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Low | (euro) | 12.94 | 11.88 | 14.72 | 17.93 | 21.82 | 22.76 | 13.80 | 12.30 | 14.61 | 12.17 |
| Average | (euro) | 15.29 | 13.64 | 16.94 | 21.60 | 23.83 | 25.10 | 21.43 | 16.59 | 16.39 | 15.95 |
| End of the period | (euro) | 15.15 | 14.96 | 18.42 | 23.43 | 25.48 | 25.05 | 16.74 | 17.80 | 16.34 | 16.01 |
| ADR price (a) - New
York Stock Exchange | | | | | | | | | | | |
| High | (US$) | 82.11 | 94.98 | 126.45 | 151.35 | 67.69 | 78.29 | 84.14 | 54.45 | 53.89 | 53.74 |
| Low | (US$) | 60.90 | 66.15 | 92.35 | 118.50 | 54.65 | 60.22 | 37.22 | 31.07 | 35.37 | 32.98 |
| Average | (US$) | 72.20 | 77.44 | 105.60 | 134.02 | 59.97 | 68.80 | 63.38 | 46.36 | 43.56 | 44,41 |
| End of the
period | (US$) | 78.49 | 94.98 | 125.84 | 139.46 | 67.28 | 72.43 | 47.82 | 50.61 | 43.74 | 41.27 |
| Average daily exchanged shares | (million shares) | 19.4 | 22.0 | 20.0 | 28.5 | 26.2 | 30.5 | 28.7 | 27.9 | 20.7 | 22.9 |
| Value | (euro million) | 295.4 | 298.5 | 338.7 | 620.7 | 619.1 | 773.1 | 610.4 | 461.7 | 336.0 | 355.0 |
| Number of shares outstanding at period end (b) | (million shares) | 3,795.1 | 3,772.3 | 3,770.0 | 3,727.3 | 3,680.4 | 3,656.8 | 3,622.4 | 3,622.4 | 3,622.5 | 3,622.5 |
| Market
capitalization (c) | | | | | | | | | | | |
| EUR | (billion) | 57.5 | 56.4 | 69.4 | 87.3 | 93.8 | 91.6 | 60.6 | 64.5 | 59.2 | 58.0 |
| USD | (billion) | 60.4 | 71.1 | 94.9 | 104.0 | 123.8 | 132.4 | 86.6 | 91.7 | 79.2 | 75.0 |

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

i i i

Data on Eni share placement 1995 1996 1997 1998 2001

| Offer
price | (euro/share) | 5.42 | 7.40 | 9.90 | 11.80 | 13.60 |
| --- | --- | --- | --- | --- | --- | --- |
| Number of share placed | (million shares) | 601.9 | 647.5 | 728.4 | 608.1 | 200.1 |
| of
which through bonus shares | (million shares) | | 1.9 | 15.0 | 24.4 | 39.6 |
| Percentage of share capital (a) | (%) | 15.0 | 16.2 | 18.2 | 15.2 | 5.0 |
| Proceeds | (euro million) | 3,254 | 4,596 | 6,869 | 6,714 | 2,721 |

i	i	i
(a)	i	Refers to
share capital at December 31, 2011.

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Eni Fact Book How we operate

In the deployment of its activities, Eni built important relations with the external world in order to maintain a constructive confrontation aimed at the diffusion and development of best practices. This has enabled Eni to be seen as a reliable and competitive partner. This approach is based on the respect of universal principles such as the protection of human rights, the adoption of the highest standards of work, the respect of the environment and communities, and the fight against corruption. In addition to this, Eni is oriented at seizing business opportunities while taking account the development of the socio-economic contexts in which it operates. The respect for universal principles incorporated in Enis business model is expressed mainly in responsibility towards applicable laws and the adoption of best standards, the inclusion of all its people through fair and non discriminating policies, excellence in operations with the adoption of quality systems and advanced technologies. Integration , innovation and cooperation are the competitive drivers allowing Eni to stand out in the oil&gas industry, to consolidate its presence in Countries that are not always characterized by political stability and at the same time to contribute to the development goals of the United Nations. Cooperation in the development of the territories where we work, expresses the ability to understand local needs and the willingness to contribute to their fulfillment. Eni is committed to provide concrete response to problems and requirements of the Countries where it operates, in synergy with the development strategies of these Countries and with reference to the Millennium Goals. The cooperation model with producing Countries, or rather the will to invest with a long-term prospective and the flexibility of offering solutions to the requirements of the Countries, has been an integral part of corporate strategy from the very beginning. This is now transforming into ever greater integration among the Company development projects and the development of growth opportunities in the territories where Eni is hosted. Integration of all activities along the energy supply chain is a source of crucial synergies for facing market challenges and ensuring competitive advantages. The integrated approach enables greater flexibility in managing relation with producing Countries, to whom Eni proposes solutions that each and every time are adapted to the specific requirements for technology, infrastructure and economic growth of the local society.

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Eni Fact Book How we operate

Innovation is a key element for accessing new energy resources, improving recovery from the subsoil and the efficiency of its use, ensuring respect for and responsible use of natural resources. Enis commitment to technological research is aimed at reducing the time-to-market for new scientific discoveries in the traditional oil&gas sectors, at enhancing renewable energy, and at developing innovative methods of environmental conservation. Excellence in running the operations hinges on making use of best practices, quality systems, advanced technologies and safety systems to ensure full respect for the community and the environment. Environmental responsibility is a basic pillar of sustainable operations, in particular as concerns the environmental impact on health and well-being of communities living in the affected areas. Among the projects carried out by Eni are the reduction of polluting emissions and of greenhouse gases (by means of increased efficiency and flare down projects), the reduction in fresh water consumption, the provision of assessments on ecosystem and biodiversity protection. Inclusion of all Eni people, with their broadly expressed diversity combines with health and safety protection in the workplace, as well as their personal development and involvement in the Companys goals. Thanks to the skills of its employees and to their diversity, which Eni enhances inside its corporate structure, to its ability to integrate with different local contexts, Eni ensures a distinctive offering with significant advantages in terms of competitiveness. Responsibility in terms of commitment to transparency in the business management, in the fight against corruption, and in the respect for human rights in every sphere of our work is a requisite for effective contribution toward the development of Countries and societies. As concerns human rights, Eni promotes their respect in all its operations and extends this to all its supply chain and to all its stakeholders. The respect of international standards is essential especially in Countries where rules and values for the protection and safeguard of human rights are not implemented. Eni is also engaged in the fight against corruption. Anti-corruption regulations are applied to all corporate levels through an articulated and homogenous system of rules based on the principles of integrity and transparency that have been extended along the entire value chain to promote a sustainable business and full respect of stakeholders.

Safety 2007 2008 2009 2010 2011

| Injury frequency rate | (number of
injuries/million of worked hours) | 1.62 | 1.42 | 1.11 | 0.89 | 0.73 |
| --- | --- | --- | --- | --- | --- | --- |
| -
employees | | 1.93 | 1.45 | 1.00 | 0.91 | 0.71 |
| - contractors | | 1.45 | 1.40 | 1.18 | 0.88 | 0.74 |
| Fatality
index | (fatal injuries/one hundred million of worked
hours) | 2.97 | 2.68 | 1.33 | 4.64 | 1.89 |
| - employees | | 1.00 | 2.43 | 0.85 | 6.40 | 1.15 |
| -
contractors | | 4.04 | 2.81 | 1.65 | 3.48 | 2.34 |
| Safety expenditures and investments | (euro thousand) | 446,597 | 425,593 | 514,773 | 283,501 | 349,229 |
| Professional
illnesses reported | (number) | 109 | 83 | 127 | 184 | 135 |
| Health and hygiene expenditure and investments | (euro thousand) | 53,762 | 68,561 | 80,896 | 57,756 | 81,192 |

Spending for the territory (euro million) 2007 2008 2009 2010 2011

| Total spending for the
territory: | 85.9 | 86.5 | 98.6 | 108.0 | 101.8 |
| --- | --- | --- | --- | --- | --- |
| - project
investments | 58.1 | 69.4 | 70.4 | 75.4 | 69.3 |
| - short-term investments and donations | 2.7 | 0.5 | 1.2 | 4.5 | 1.1 |
| -
association memberships fees | 0.9 | 1.5 | 1.5 | 1.7 | 1.6 |
| - contributions to the Eni Foundation | 8.0 | 0.0 | 5.0 | 5.0 | 3.0 |
| -
sponsorships for the territory | 12.9 | 11.8 | 16.6 | 17.6 | 22.9 |
| - contributions to the Eni Enrico Mattei
Foundation | 3.3 | 3.3 | 3.9 | 3.9 | 3.9 |

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Eni Fact Book How we operate

Employment 2007 2008 2009 2010 2011

Employees as of December 31	(number)	75,125	78,094	77,718	79,941	78,686
- men		64,148	65,873	65,154	67,187	65,501
- women		10,977	12,221	12,564	12,754	13,185
Employees
abroad by type		38,634	41,971	42,633	45,967	45,516
- locals		31,279	33,233	33,483	35,835	34,801
-
Italian expatriates		2,386	2,769	2,771	3,123	3,208
- International expatriates (including TCN)		4,969	5,969	6,379	7,009	7,507
Senior
Managers employed		1,532	1,594	1,562	1,574	1,586
- of which women		108	134	149	155	160
Managers/Supervisors
employed		11,700	12,527	12,893	13,350	13,298
- of which women		1,761	2,124	2,310	2,479	2,545
Employees		36,231	36,895	37,295	37,885	39,296
- of which women		8,804	9,619	9,720	9,567	9,961
Workers
employed		25,662	27,078	25,968	27,132	24,506
- of which women		304	344	385	553	519
Local
employees abroad by professional category		31,279	33,233	33,483	35,835	34,801
- senior managers		230	245	224	228	228
-
managers/supervisors		2,668	2,900	3,138	3,461	3,476
- employees		14,407	14,864	15,533	16,269	17,529
-
workers		13,974	15,224	14,588	15,877	13,568
Training hours	(thousand hours)	2,797	2,960	3,097	3,114	3,327

Procurement by geographical area 2011 Africa Americas Asia Italy Rest of Europe Oceania

Number of suppliers used	(number)	6,356	4,111	4,649	14,067	7,407	276
Total procurement:	(euro million)	8,351	2,283	6,125	13,682	3,456	379
- in goods	(%)	14.7	36.3	10.3	26.1	24.5	19.0
- in works		29.5	8.7	36.2	15.1	7.7	1.5
- in services		39.3	50.8	45.0	51.7	60.7	79.1
-
unidentifiable		16.5	4.2	8.4	7.1	7.1	0.4

Local procurement 2011 by Country

% procurement on local market	Countries
0 - 25%	Portugal,
Peru, Pakistan, Malaysia, Luxembourg, Germany, Libya,
Venezuela, Austria, Czech Republic, Slovenia, China,
Spain, Poland, Russian Federation.
25 - 50%	Kazakhstan, Republic of Congo, Angola, France,
United Kingdom, Algeria, Tunisia, Switzerland, Gabon,
Hungary.
50 - 75%	Italy,
Nigeria, Iraq, Saudi Arabia, Australia, Indonesia, Iran,
India, Ghana, Croatia, Romania.
75 - 100%	United States, Egypt, Norway, Canada, Brazil,
Mexico, Ecuador, Singapore, Belgium, Netherlands,
Argentina.

Relations with suppliers 2007 2008 2009 2010 2011

Procurement by macro-class	(euro million)	23,208	30,026	35,205	32,626	34,275
Supplier
concentration top 20	(%)	18	24	25	18	20
Suppliers used	(number)	26,270	29,416	35,113	33,961	34,064
Qualification
cycles carried out during the year		19,058	15,936	22,108	33,700	29,362
Suppliers subjected to qualification procedures
including screening on human rights		5,784	6,174	8,388	10,643	12,300
%
procurement from suppliers subjected to qualification
procedures including screening on human rights	(%)	83	89	87	89	91

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Eni Fact Book How we operate

Relations with customers 2007 2008 2009 2010 2011

| R&M Customer satisfaction — Customer
satisfaction index | (likert scale) | 8.22 | 8.14 | 7.93 | 7.84 | 7.74 |
| --- | --- | --- | --- | --- | --- | --- |
| Clients involved in the survey | (number) | 33,692 | 22,609 | 10,711 | 30,618 | 30,524 |
| G&P Customer satisfaction | | | | | | |
| Customer
satisfaction index | (%) | n.a. | 75.3 | 83.7 | 87.4 | 91.0 |
| Average Panel (G&P) (a) | | n.a. | 84.9 | 87.0 | 87.4 | 89.8 |

(a) Referred to companies representing more than 50% of the gas market and totaling over 50,000 customers.

Technological innovation 2007 2008 2009 2010 2011

R&D expenditures	(euro million)	205	329	279	268	237
- R&D
expenditures net of general and administrative costs		208	217	207	221	191
Tangible value generated by R&D activities (a)		n.a.	n.a.	362	540	492 (b)
Personnel
employed in R&D activities (full time equivalent)	(number)	1,001	1,123	1,019	1,019	925
Existing patents		8,122	8,049	7,760	7,998	8,784

| (a) | Figures refer
to E&P, R&M and Polimeri Europa activities and
had been measured since 2009, when the measurement
process started. |
| --- | --- |
| (b) | The figure is
net of benefits related to the increase of reserves. |

Operating efficiency 2007 2008 2009 2010 2011

Direct GHG emissions:	(tons CO 2 eq)	67,246,179	62,013,146	57,694,175	60,642,340	51,099,412
- of which
CO 2 from combustion and process	(tonnes)	39,252,511	37,389,394	36,587,311	39,006,120	36,014,381
- of which CO 2 equivalents from
flaring	(tons CO 2 eq)	20,070,000	16,535,835	13,839,353	13,834,988	9,553,894
- of which
CO 2 equivalents from CH 4 (methane)		5,733,668	5,697,220	5,085,309	5,461,211	4,498,120
- of which CO 2 equivalents from
venting		2,190,000	2,390,697	2,182,202	2,340,021	1,033,017
CO 2 eq
emissions/100% net operated hydrocarbon production	(tons CO 2 eq/toe)	0.292	0.265	0.245	0.245	0.206
CO 2 eq emissions/kWheq (EniPower)	(kg CO 2 eq/kWheq)	0.400	0.402	0.410	0.407	0.410
CO 2 eq
emissions/gas distributed (Italgas)	(tons CO 2 eq/mmcm)	96.29	93.04	87.68	92.86	87.00
CO 2 eq emissions/uEDC (R&M)	(tons CO 2 eq/kbbl/SD)	n.a.	1,297	1,240	1,284	1,230
NO x (nitrogen oxide) emissions	(tons NO 2 eq)	111,824	113,952	112,263	107,724	98,117
SO x (sulphur oxide) emissions	(tons SO 2 eq)	62,980	47,163	45,988	50,085	37,940
NMVOC
(Non-Methane Volatile Organic Compounds) emissions	(tonnes)	87,889	80,923	75,392	68,490	46,228
TSP (Total Suspended Particulate) emissions		4,567	4,230	3,973	3,783	3,297
Energy
used/net 100% operated hydrocarbon production	(GJ/toe)	1.387	1.481	1.746	1.934	1.958
Total water withdrawals	(mmcm)	3,370.77	3,028.06	2,844.75	2,791.47	2,583.87
Total
production and/or process water extracted	(mmcm)	48.34	52.93	59.67	61.15	58.16
- of which re-injected		14.73	14.88	23.32	27.11	25.18
Total
recycled and/or reused water	(mmcm)	n.a.	460.93	490.22	544.63	521.39
Total number of oil spills (a)	(number)	367	382	308	330	418
Total
volume of oil spills (a) (b) :	(barrels)	9,337	7,024	21,547	22,964	13,422
- of which from sabotage and terrorism		2,608	2,286	15,288	18,695	6,127
- of which
from accidents		6,729	4,738	6,259	4,269	7,295
Waste from production activities	(tonnes)	1,543,619	1,253,750	1,158,645	1,452,717	1,324,808
Hazardous
waste from production activities		393,028	487,607	440,244	497,092	477,558
Non-hazardous waste from production activities		1,150,591	766,143	718,401	955,625	847,250
Waste from
reclamation activities to be disposed of or
recovered/recycled	(tonnes)	6,862,915	9,209,054	10,180,216	10,490,267	10,863,767
Environmental expenditures and investments	(euro thousand)	1,062,850	1,080,707	1,324,066	1,006,777	1,006,711

| (a) | For the
E&P sector only oil spills of more than one barrel
are considered. |
| --- | --- |
| (b) | For 2009 the
total volume of spills does not include the Engineering
& Construction sector. |

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Eni Fact Book Exploration & Production

		2007	2008	2009	2010	2011
Employees injury frequency rate	(No. of accidents per
million hours worked)	0.57	0.84	0.49	0.72	0.41
Contractors
injury frequency rate		0.92	0.93	0.59	0.48	0.41
Fatality index	(No. of fatalities per
100 million hours worked)	2.34	3.54	1.77	7.90	1.83
Net sales
from operations (a)	(euro million)	26,920	33,042	23,801	29,497	29,121
Operating profit		13,433	16,239	9,120	13,866	15,887
Adjusted
operating profit		13,770	17,222	9,484	13,884	16,077
Adjusted net profit		6,328	7,900	3,878	5,600	6,866
Capital
expenditure		6,480	9,281	9,486	9,690	9,435
Adjusted capital employed, net at year end		23,826	30,362	32,455	37,646	42,024
Adjusted
ROACE	(%)	30.4	29.2	12.3	16.0	17.2
Profit per boe (b)	($/boe)	14.19	16.00	8.14	11.91	16.98
Opex per
boe (b)		4.99	5.45	5.77	6.14	7.28
Cash Flow per boe		25.79	32.25	23.70	25.52	31.65
Finding
& Development cost (c)		43.44	28.79	28.90	19.32	18.82
Average hydrocarbons realizations (d)		53.17	68.13	46.90	55.60	72.26
Production
of hydrocarbons (d)	(kboe/d)	1,736	1,797	1,769	1,815	1,581
Estimated net proved reserves of hydrocarbons (d)	(mmboe)	6,370	6,600	6,571	6,843	7,086
Reserves
life index (d)	(years)	10.0	10.0	10.2	10.3	12.3
All sources reserves replacement ratio (d)	(%)	90	135	96	125	142
Employees
at year end	(units)	8,376	10,236	10,271	10,276	10,425
of which: outside Italy		4,446	6,182	6,388	6,370	6,628
Oil spills	(bbl)	6,729	4,738	6,259	3,820	2,930
Oil spills from sabotage and terrorism		2,608	2,286	15,288	18,695	6,127
Produced
water re-injected	(%)	30	28	39	44	43
Direct GHG emissions	(mmtonnes CO 2 eq)	36.31	33.21	29.73	31.20	23.59
of which: from
flaring		20.07	16.54	13.84	13.83	9.55
Community investment	(euro million)	59	65	67	72	62

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

Performance of the year I In 2011, employee and contractor injury frequency rate declined by 43.1% and 14.6% from 2010, respectively. - Greenhouse gas emissions (total and from flared) reported a steep decline reflecting the completion of certain gas recovery projects in Nigeria and the reduction associated gas to feed the ramp-up of two turbo-generators in a power plant in Congo. Performance for the year was also impacted by lowered Libyan activities. - In 2011, the E&P Division reported an excellent performance amounting to euro 6,866 million of adjusted net profit (up 22.6% from 2010), reflecting higher oil prices and the rapid recovery of Libyan output. - Return on average capital employed calculated on an adjusted basis was 17.2% in 2011 (16% in 2010). Giant discovery in Mozambique I The volume of natural gas discovered beyond expectation in Mozambique will lead to a new significant development opportunities in Far East Countries with an energy demand growth at fast pace. The Mamba South, Mamba North and Mamba North East exploration wells were drilled in Area 4 of the offshore Rovuma basin showing the mineral potential of gas in place up to 40 tcf. This is the largest operated discovery in the Companys exploration history. Agreement with Rosneft I On April 25, 2012, Eni and Rosneft signed a strategic cooperation agreement to jointly develop exploration licenses in the Russian offshore of the Barents Sea and the Black Sea. Under the agreement, joint ventures (Eni 33.33%) will explore for and develop

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the Fedynsky and Tsentralno-Barentsvesky licenses offshore the Barents Sea and the Zapadno-Cernomorsky license offshore the Black Sea. These licenses are estimated to hold recoverable resources of 36 billion boe. Technology exchange is a key element of the strategic partnership. Restarted Libyan operations I The rapid restart of Enis Libyan operations reduced the impact of the Revolution on 2011 results. Production at Enis Libyan sites is currently flowing at approximately 240 kboe/d and management is targeting to achieve the pre-crisis production plateau of 280 kboe/d and full ramp-up by the second half of 2012. Start-up of Perla project in Venezuela I Signed a Gas Sales Agreement for developing the giant Perla gas discovery, containing over 17 tcf of gas in place with the Venezuelan national oil company PDVSA. The development plan provides for three phases, targeting production of approximately 9 tcf until 2036 or 1.2 mmcf/d at peak. The gas produced will be used locally and exported. The investment plan for the first development phase is estimated at $1.4 billion at 100%. Portfolio I In spite of the year 2011 was marked by the Libyan crisis, the management continued to pursue our long-term growth strategy. Leveraging its established co-operation model, focusing on core areas and capturing opportunities in high risk/high reward basins, Eni laid foundations for a new development stage: - Signed with PetroChina and Sinopec a framework agreement to promote joint projects in conventional and unconventional hydrocarbon plays in China and outside China. A similar agreement has been signed with Sonatrach to explore for and develop unconventional hydrocarbons in Algeria, particularly shale gas plays. - Signed a Memorandum of Understanding with South Africas State-owned oil company PetroSA to promote common opportunities to jointly expand operations in conventional and unconventional hydrocarbons in South Africa and in Africa. Eni will also ensure long-term LNG supplies as well as flows of refined products to support the Countrys economic development. - Acquired from Cadogan Petroleum plc an interest in two licenses for exploration and development in areas included in the Dniepr-Donetz basin in Ukraine. - Reached an agreement with MEO Australia to farm-in the Heron and Blackwood gas discoveries in the NT/P-68 permit, located in the Timor Sea. In addition, Eni acquired a 32.5% stake in the Evans Shoal gas discovery. - Awarded the Arguni I and the North Ganal operated gas exploration contracts located onshore and offshore Indonesia, respectively. - Awarded the operatorship of the PL657 license (Enis interest 80%) located in the Barents Sea nearby the Goliat operated field (Enis interest 65%). - Signed with the Angolan authority the Production Sharing Contract to explore Block 35 (Eni operator with a 30% interest) located in an offshore high mineral potential basin. New agreement of Karachaganak field in Kazakhstan I On December 14, 2011, the Republic of Kazakhstan and the contracting companies in the Final Production Sharing Agreement (FPSA) of the giant Karachaganak gas-condensate field reached an agreement to settle all pending claims. The agreement, effective from June 30, 2012 on satisfaction of conditions precedent, involves Kazakhstans KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies transferring 10% of their rights and interest in the Karachaganak FPSA to KMG. Production I In 2011, Eni reported liquids and gas production of 1,581 kboe/d, down by 12.9% from 2010, mainly due to a lowered output in Libya. Performance was also negatively impacted by lower entitlements in the Companys Production Sharing Agreements (PSAs) due to higher oil prices with an overall effect of approximately 30 kboe/d from 2010. Net of this effect and the above mentioned loss of Libyan output, production for the year was in line with 2010. - In the year oil spills from accidents declined by 23% from 2010, due to significant prevention activities undertaken. - In the year start-ups were achieved at eleven oil and gas fields which are expected to add approximately 80 kboe/d at plateau to Enis medium-term production. - Made final investment decisions to develop large projects such as the jointly-operated Samburgskoye and Urengoskoye giant gas fields in Siberia, in addition to the above mentioned Perla project, as well as projects in Norway and the Gulf of Mexico which are expected to add 140 kboe/d at plateau in 2015. Reserves I Estimated net proved reserves at December 31, 2011, were 7.09 bboe (up 3.6% from 2010) based on a 12-month average Brent price of $111 per barrel. All sources reserves replacement ratio was 142%. Excluding price effect, the replacement ratio would be 159%. The reserves life index is 12.3 years (10.3 years in 2010). Capital expenditure I In 2011, capital expenditure amounted to euro 9,435 million to enhance assets in well established areas of Africa, the Gulf of Mexico and Central Asia. Exploration expenditure amounted to euro 1,210 million (up 19.6% from 2010) to execute a selective campaign with the completion of 56 new exploratory wells (28 net to Eni) and an overall commercial success rate of 42% (38.6% net to Eni). In addition 17 exploratory wells drilled are in progress at year end (9.9 net to Eni). - Exploration successes in the year contributed to increase our resource base by 1.1 bboe. New resources were, in addition to the above mentioned Mozambique discovery, the appraisal of Perla giant field in Venezuela, significant discoveries of Jangkrik North East (Eni operator with a 55% interest) in Indonesia and Skrugard/Havis (Enis interest 30%) in the Barents Sea, the appraisal/discovery wells in Block 15/06 (Eni operator with a 35% interest) in the Angolan offshore, as well as other successes in the Gulf of Mexico, Ghana, Egypt, Pakistan, the United Kingdom and Nigeria. - Development expenditure was euro 7,357 million to fuel the growth of major projects in Norway, Kazakhstan, Algeria, the United States, Italy, Congo and Egypt. - In 2011 overall R&D expenditure of Exploration & Production Division amounted to approximately euro 90 million (euro 98 million in 2010).

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Activity areas n Italy Eni has been operating in Italy since 1926. In 2011, Enis oil and gas production amounted to 186 kboe/d. Enis activities in Italy are deployed in the Adriatic Sea, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley, on a total acreage of 21,648 square kilometers (16,872 net to Eni). Enis exploration and development activities are regulated by concession contracts. During the year, Eni finalized the purchase of an additional interest in the Annamaria field (Enis interest 100%). In the R&D area, 11 applications of new technologies and four projects have been developed and applied on Italian assets. Cooperation projects are underway with sixteen academic and research institutions in Italy with an overall expenditure of approximately euro 9 million. Adriatic Sea Production Fields in the Adriatic Sea accounted for 46% of Enis domestic production in 2011. Main fields are Barbara, Angela-Angelina, Porto Garibaldi, Cervia and Bonaccia (for an overall production of approximately 270 mmcf/d). Production is operated by means of 71 fixed platforms (3 of these are manned) installed on the main fields, to which satellite fields are linked by underwater infrastructures. Production is carried by sealine to the mainland where it is input in the national gas network. During the year, Eni renewed the VI Cooperation Agreement over the 2011-2014 period with the city of Ravenna to protect the coastline area. Development In 2011, production started-up at the Guendalina field (Enis interest 80%) flowing at the initial rate of approximately 3 kboe/d. Other activities for the year concerned sidetrack and workover activities on Calpurnia, Daria (Enis interest 51%), Barbara and Clara Nord (Enis interest 51%) fields for the production optimization. Proprietary technology has been successfully applied on the Clara Est field for the characterization of thin layer fields and it identified approximately 3 mmboe of additional hydrocarbon volumes. Central-Southern Apennines Production Eni is the operator of the Val dAgri concession (Enis interest 60.77%) in the Basilicata Region in Southern Italy, resulting from the unitization of the Volturino and Grumento Nova concessions made in late 2005. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is fed by 24 production wells and is treated by the Viggiano oil center with an oil capacity of 104 kbbl/d. Oil produced is carried to Enis refinery in Taranto via a 136-kilometer long pipeline. Gas produced is treated at the Viggiano oil center and then delivered to the national grid system. In 2011, the Val dAgri concession produced 95 kboe/d (52 kboe/d net to Eni) representing 28% of Enis production in Italy. Within the Intent Protocol with the Basilicata Region, the Environmental Observatory of Val dAgri for the monitoring of the quality of health and the environment in the area has been inaugurated. In 2011, production started-up at the Capparuccia field (Enis interest 95%) with an initial production at approximately 4 kboe/d. Development Development activities progressed at the Val dAgri concession with the linkage of Cerro Falcone to the oil treatment center and sidetrack activity as well as upgrading of production facilities. During the year, upgrading activities of compression plants and treatment facilities were performed at the Crotone plants. Exploration Exploration activity concerned the survey of mineral potential in the area. Sicily Production Eni is the operator of 14 production concessions onshore and offshore in Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2011 accounted for 11% of Enis production in Italy. Development Development activities concerned: (i) completion of development activities at the Tresauro field (Enis interest 45%); and (ii) sidetrack and workover activities on Gela field.

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n Rest of Europe Croatia Eni has been present in Croatia since 1996. In 2011, Enis production of natural gas averaged approximately 30 mmcf/d. Activities are deployed in the Adriatic Sea near the city of Pula over a developed and undeveloped area of 1,975 square kilometers (987 square kilometers net to Eni). Exploration and production activities in Croatia are regulated by Production Sharing Agreements (PSAs). Production The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ana, Vesna, Irina, Marica and Katarina and are operated by Eni through a 50/50 joint operating company with the Croatian oil company INA. Production is carried by sealine and sold on the Italian and Croatian market. Norway Eni has been operating in Norway since 1965. Enis activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea over a developed and undeveloped acreage of 8,100 square kilometers (2,335 square kilometers net to Eni). Enis production in Norway amounted to 131 kboe/d in 2011. Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for any given number of years with possible extensions. Norwegian Sea Production Eni currently holds interests in 8 production areas. The principal producing fields are Asgaard (Enis interest 14.82%), Kristin (Enis interest 8.25%), Heidrun (Enis interest 5.24%), Mikkel (Enis interest 14.9%), Tyrihans (Enis interest 6.2%) and Morvin (Enis interest 30%) which in 2011 accounted for 76% of Enis production in Norway. The gas produced in the area is collected at the Asgaard facilities, carried by pipeline to the Karsto treatment plant and then delivered to the Dornum terminal in Germany. Liquids recovered in the area mainly through FPSO units are sold FOB. The development plan of the Morvin field has been completed with a production peak of 22 kboe/d reached in the year. Development Development activities progressed to put in production discovered reserves near the Asgaard field with the Marulk development plan (Eni operator with a 20% interest). Production started-up in early days of April 2012 and is expected to reach approximately 20 kboe/d (4 kboe/d net to Eni) on average during the year. Exploration Eni holds interests in 33 prospecting licenses ranging from 5 to 70%, 5 of these are operated. Norwegian section of the North Sea Production Eni holds interests in 4 production licenses. The main producing field is Ekofisk (Enis interest 12.39%) in PL 018, which in 2011 produced approximately 32 kboe/d net to Eni and accounted for 24% of Enis production in Norway. Production from Ekofisk and satellites is carried by pipeline to the Teesside terminal in the United Kingdom for oil and to the Emdem terminal in Germany for gas. Development 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. Exploration Eni holds interests in 6 prospecting licenses ranging from 12 to 45%, one of them as operator. Barents Sea Eni is currently performing exploration and development activities in the Barents Sea. Eni is operator of Prospecting License 201 (Enis interest 66.67%), 489 (Enis interest 40%), 229-229B (Enis interest 65%), 529 (Enis interest 30%), 533 (Enis interest 40%) and hold a 30% interest in Prospecting License 393 and 532 as well as in PL 226 (Enis interest 31%). Exploration activities yielded positive results with the Skrugard and Havis oil and gas discoveries with recoverable reserves estimated at approximately 500 mmbbl at 100% in the PL 532 license. Both fields are planned to be put in production by means of a fast-track synergic development. Eni was awarded three exploration licenses: (i) the PL 657 license (Eni operator with an 80% interest) in January 2012. In case of exploration success, the project will benefit from the nearby facilities of the Goliat operated field (Enis interest 65%) thus significantly reducing time to market; (ii) in May 2011, the PL 608 (Enis interest 30%) license located near the Skrugard oil discovery and the PL 226B license (Enis interest 31%) located in high mineral potential basin. Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229. The project was sanctioned in 2009 and is progressing according to schedule. Start-up is expected at the end of 2013 with a production plateau at 100 kbbl/d. Subsea facilities were completed and an FPSO unit is in progress. During the year, Eni signed an intent protocol with Norwegian Authorities for the protection of biodiversity in the Goliat area. Within the procedures for coping with possible emergencies, Eni developed standards for testing dispersants and beach cleaners that

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could be used in case of oil spills near the coast. These emergency standards will be included in Norwegian laws and later presented internationally. In addition, Eni strengthened its cooperation and partnerships with Norwegian academic institutions for an upgrading of training activities for local professionals and technicians to be employed at the Goliat field and for the management of oil spills. Ukraine In July 2011, Eni acquired from Cadogan Petroleum plc an interest in two licenses for exploration and development in areas included in the Dniepr-Donetz Basin. Eni acquired 30% with an option to increase its participation to up to 60% in the Pokrovskoe exploration license and the acquisition of 60% interest in the Zagoryanska license. United Kingdom Eni has been present in the United Kingdom since 1964. Enis activities are carried out in the British section of the North Sea, the Irish Sea and certain areas East and West of the Shetland Islands over a developed and undeveloped acreage of 2,899 square kilometers (1,014 square kilometers). In 2011, Enis net production of oil and gas averaged 80 kboe/d, the portion of liquids being 50%. Exploration and production activities in the United Kingdom are regulated by concession contracts. Production Eni holds interests in 13 production areas; in the Hewett Area, Eni is operator with an 89% interest. The other main fields are Elgin/Franklin (Enis interest 21.87%), West Franklin (Enis interest 21.87%), Liverpool Bay (Enis interest 53.9%), J Block Area (Enis interest 33%), Andrew (Enis interest 16.21%), Flotta Catchment Area (Enis interest 20%) and MacCulloch (Enis interest 40%), which in 2011 accounted for 83% of Enis production in the UK. Development Main development activities concerned: (i) the construction of production platform and drilling activities at the gas and liquids Jasmine field (Enis interest 33%) with start-up expected at the end of 2012; (ii) Phase 2 development plan of the West Franklin field with the construction of a well-head platform and linkage to the Elgin/Franklin treatment plant. Drilling activities are progressing with start-up expected in 2013; (iii) development activities at the oil and gas Kinnoul field (Enis interest 16.67%). The drilling of producing subsea wells has been completed while the linkage to the production facilities of the Andrew field is in progress. Start-up is expected in 2013; and (iv) concept definition activities for the Mariner heavy oil field proceed with target to submit the Field Development Plan and sanction the project early in 2013. Exploration Eni holds interests in 43 exploration blocks ranging from 5 to 100%, in 5 of these Eni is operator. Exploration activities yielded positive results with the appraisal of Culzean discovery continuing (Enis interest 16.95%), near the Elgin/Franklin producing field. n North Africa Algeria Eni has been present in Algeria since 1981. In 2011, Enis oil and gas production averaged 72 kboe/d. Operating activities are located in the Bir Rebaa area in the South-Eastern Desert and include the following exploration and production blocks: (i) Blocks 403a/d (Enis interest up to 100%); (ii) Block Rom North (Enis interest 35%); (iii) Blocks 401a/402a (Enis interest 55%); (iv) Blocks 403 (Enis interest 50%) and 404a (Enis interest 12.25%); (v) Blocks 208 (Enis interest 12.25%) and 405b (Enis interest 75%) with ongoing development activities; (vi) Block 212 (Enis interest 22.38%) with discoveries already made; and (vii) Blocks 316b, 319a and 321a (Eni operator with a 49% interest) in the Kerzaz area with ongoing exploration activities. Developed and undeveloped acreage of Enis interests in Algeria was 19,619 square kilometers (9,065 square kilometers net to Eni). In April 2011, Eni signed a cooperation agreement with Sonatrach to explore for and develop unconventional hydrocarbons, particularly shale gas plays. Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

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Blocks 403a/d and Rom North Production Production in the area comes mainly from the HBN and Rom and satellite fields and represented approximately 20% of Enis production in Algeria in 2011. Production from Rom and Satellites (Zea, Zek and Rec) is treated at the Rom Central Production Facilities (CPF) and sent to the BRN treatment plant for final treatment, while production from the HBN field is treated at the HBN/HBNS oil center at the Groupment Berkine. Development A new multiphase pumping system is under finalization in compliance with applicable Country law to reduce gas flaring by 2012. Blocks 401a/402a Production Production from this area is supplied mainly by the ROD/SFNE and satellite fields and accounted for approximately 25% of Enis production in Algeria in 2011. Infilling activities are being performed in order to maintain the current production plateau. Block 403 Production The main fields in the area are BRN, BRW and BRSW which accounted for approximately 18% of Enis production in Algeria in 2011. Block 405b Development Activities in the area concerned the joint development MLE and CAFC, assets acquired from Canadian company First Calgary in 2008. The final investment decision was sanctioned for both projects (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. Production start-up is expected in 2012. The CAFC project provides the construction of an oil treatment plant and will also benefit from synergies with MLE production facilities. Gas and oil production start-up of CAFC field are expected in 2012 and 2014, respectively. The overall Block 405b will target a production plateau of approximately 33 kboe/d net to Eni by 2015. Block 208 Development Block 208 is located south of Bir Rebaa. The El Merk project is designed to jointly develop this block and adjoining blocks operated by other companies. The final investment decision was reached in 2009. The project is progressing with the drilling activities and the construction of treatment facilities. The development program provides for the construction of a gas treatment plant with a capacity of approximately 600 mmcf/d, two oil trains with a capacity of 65 kbbl/d and three export pipelines with linkage to the national system for an overall production of approximately 11 kbbl/d. Start-up is expected in 2013. Egypt Eni has been present in Egypt since 1954 and is the first international oil operator with a production amounting to 236 kboe/d net to Eni in 2011 and accounted for 15% of Enis total annual hydrocarbon production. Developed and undeveloped acreage in Egypt was 15,836 square kilometers (5,898 square kilometers net to Eni). Enis main producing liquid fields are located in the Gulf of Suez, primarily in Belayim field (Enis interest 100%) and in the Western Desert mainly Melehia concession (56% interest) and Ras Qattara (75% interest). Gas production mainly comes from the operated or participated concession of North Port Said (Enis interest 100%), El Temsah (50% interest), Baltim (50% interest) and Ras el Barr (50% interest, non operated) and all located in the offshore the Nile Delta. In 2011, production from these main concessions accounted for approximately 91% of Enis production in Egypt. In July 2011, Eni and the Egyptian Authorities reaffirmed their upstream commitment in the Country, particularly in the Western Desert, the Mediterranean Sea and the Sinai Basins. Agreed plans foresee drilling additional producing wells and the fast track of recent discoveries as well as an exploration plan including the drilling of 12 wells. Development of proprietary technologies progressed with the Eni Circulation Device technology to enhance hydraulic control in drilling activities, an innovative enhanced recovery technique (acoustic simulation) and a system for consolidating sands to keep production sand free. Exploration and production activities in Egypt are regulated by Production Sharing Agreements. Gulf of Suez Production Production mainly comes from the Belayim field, Enis first large oil discovery in Egypt, which produced approximately 59 kbbl/d net to Eni in 2011. Development Infilling activities and basic engineering activities continued for the upgrading of water injection facilities to recover remaining reserves of the Belayim field. Exploration Exploration activities yielded positive results with near field activities in the Belayim concession with three oil discovery wells (BB-10, BLNE-1 and EBLS-1) that were linked to the existing facilities.

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Nile Delta North Port Said Production Enis production for the year amounted to 31 kboe/d net to Eni (approximately 140 mmcf/d of gas and 4 kbbl/d of condensates). Part of the production of this concession is supplied to the NGL (natural gas liquids) plant owned by United Gas Derivatives Co (Enis interest 33%) with a treatment capacity of 1.1 bcf/d of natural gas and a yearly production of 380 ktonnes of propane, 305 ktonnes of LPG and 1.5 mmbbl of condensates. A plan is being studied for upgrading the plants capacity to 1.3 bcf/d. Development Ongoing development activities aim at supporting current gas production levels. Upgrading progressed at the El Gamil compression facility to support the North Port Said, el Temsah and Ras el Barr production concessions. Baltim Production In this concession, Enis production for the year amounted to approximately 20 kboe/d net to Eni (approximately 106 mmcf/d of gas and 3 kbbl/d of condensates). Development Upgrading was completed at the Abu Madi plant to increase the compression capacity supporting Belayim production. Ras el Barr Production This concession contains three fields: Hapy, Akhen and Taurt. Enis production in 2011 amounted to approximately 177 mmcf/d net to Eni. El Temsah Production This concession includes the Temsah, Denise and Tuna fields. Enis production in 2011 amounted to approximately 63 kboe/d (approximately 318 mmcf/d of gas and approximately 6 kbbl/d of condensates) net to Eni. In 2011 production was started-up at the Denise B field, the second development phase of the homonymous field with the drilling of 3 other subsea wells linked to the production facilities in the area flowing initially at 7 kboe/d net to Eni. Production peak is expected at 14 kboe/d in 2012. Natural gas production of this concession is supplied to the Damietta natural gas liquefaction plant owned by Unión Fenosa Gas, with 35 bcf/y of feed gas for a 20-year period. Development Main activities of the year were: (i) the upgrading of the El Gamil plant by adding new compression capacity to support production; (ii) the Seth project (Enis interest 50%). The development activity provides the drilling of two wells and the installation of production platform. Start-up is expected in 2012. Exploration in the Nile Delta This area shows a relevant mineral potential. Exploration activities yielded positive results with near field activities in the Abu Madi West development lease (Enis interest 75%) with Nidoco West and Nidoco East gas discoveries. The linkage to the existing facilities was completed. Western Desert Production Other operated production activities are located in the Western Desert, in particular in the Melehia (Enis interest 56%), Ras Qattara (Enis interest 75%), West Abu Gharadig (Enis interest 45%) and West Razzak (Enis interest 80%) development permits containing mainly oil. Concessions in the Western Desert accounted for approximately 5% of Enis production in Egypt in 2011. Exploration Exploration activities yielded positive results with near field activities in the: (i) Melehia development lease with the Aman SW, Dorra-1X and Melehia North-1X oil wells that were started-up; and (ii) East Kanayis concession (Enis interest 100%) with the Qattara Rim-3 and Qattara North-1 oil discoveries. Libya Eni started operations in Libya in 1959. In 2011, Enis oil and gas production averaged 112 kboe/d. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan Desert area, over a developed and undeveloped acreage of 26,634 square kilometers (13,295 square kilometers net to Eni). Onshore contract areas are: (i) Area A consisting in the former concession 82 (Enis interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC125 Block (Enis interest 50%); (iii) Area E with El Feel (Elephant) field (Enis interest 33.3%); and (iv) Area F with former Block NC118 (Enis interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Enis interest 50%); and (ii) Area D with Blocks NC41 and NC169 (onshore) including the Western Libyan Gas Project (Enis interest 50%). In the exploration phase, Eni is operator in the Kufra area (186/1, 2, 3 & 4) and in the contract Areas A, B and D. Exploration and production activities in Libya are regulated by Exploration and Production Sharing contracts (EPSA). The licenses of Enis assets in Libya expire in 2042 and 2047 for oil and gas properties, respectively. In 2011, the situation of conflict forced Eni to shut down almost all its producing facilities including exports through the GreenStream

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gas pipeline for a period of approximately 8 months, with the sole exception of certain gas fields to support local production of electricity for humanitarian purposes. Gas export via the GreenStream pipeline has been re-opened in October and export gas has subsequently been increased from November when Bahr Essalam field re-started operations. Management is targeting to achieve the pre-crisis production plateau of 280 kboe/d and full ramp-up by the second half of 2012. Tunisia Eni has been present in Tunisia since 1961. In 2011, Enis production amounted to 18 kboe/d. Enis activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed and undeveloped acreage of 6,464 square kilometers (2,274 square kilometers net to Eni). Exploration and production in this Country are regulated by concessions. Production Production mainly comes from operated Maamoura and Baraka offshore blocks (Enis interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), MLD (Enis interest 50%) and El Borma (Enis interest 50%) onshore blocks. Development Optimization of production was carried out at the Adam, Djebel Grouz (Enis interest 50%), Oued Zar and El Borma fields. Exploration An exploration campaign, geological and geophysical studies started in the area for assessing the residual mineral potential of conventional and unconventional gas resources. n Sub-Saharan Africa Angola Eni has been present in Angola since 1980. In 2011, Enis production averaged 102 kboe/d. Enis activities are concentrated in the conventional and deep offshore over a developed and undeveloped acreage of 24,996 square kilometers (6,218 square kilometers net to Eni). The main producing blocks with Enis participation are: (i) Block 0 in Cabinda (Enis interest 9.8%) north of the Angolan coast; (ii) Development Areas in the former Block 3 (Enis interest ranging from 12% to 15%) in the offshore of the Congo Basin; (iii) Development Areas in the former Block 14 (Enis interest 20%) in the deep offshore west of Block 0; and (iv) Development Areas in the former Block 15 (Enis interest 20%) in the deep offshore of the Congo Basin. In the exploration and development phase, Eni is operator of Block 15/06 (Enis interest 35%). Eni also holds interests in other non producing concessions, in particular in the Lianzi Development Area (Block 14K/A IMI Unit Area - Enis interest 10%), in Block 3/05-A (Enis interest 12%), in onshore Cabinda North (Enis interest 15%) and in the Open Areas of Block 2 awarded to the Gas Project (Enis interest 20%) (see below). In January 2011, Eni was awarded the right to explore and the operatorship of the 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 the exploration phase. This deal was approved by the relevant authorities. Exploration and production activities in Angola are regulated by concessions and PSAs.

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Block 0 Production Block 0 is divided into Areas A and B. In 2011, production from this block amounted to 364 kbbl/d (approximately 36 kbbl/d net to Eni). Oil production from Area A, deriving mainly from the Takula, Malongo and Mafumeira fields amounted to approximately 23 kbbl/d net to Eni. Production of Area B derives mainly from the Bomboco, Kokongo, Lomba, NDola, Nemba and Sanha fields, and amounted to approximately 13 kbbl/d net to Eni. Development 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) the completion of linkage and treatment facilities at the Malongo plant; and (ii) the installation of a second compression unit at the Nemba platform in Area B. In the Area A the concept definition phase has been completed for the further development of the Mafumeira field. Project sanctioning is expected in 2012 with start-up in 2015. Infilling activities are underway on the whole block in order to contrast natural decline. Block 3 Production Block 3 is divided into three production offshore areas. In 2011, production from this block amounted to 65 kbbl/d (approximately 5 kbbl/d net to Eni). Development Concept Definition studies are underway in the Punja and Caco-Gazela discoveries. Block 14 Production In 2011, Development Areas in former Block 14 produced approximately 193 kbbl/d (approximately 23 kbbl/d net to Eni), accounting for approximately 18% of Enis production in Angola. It is one of the most fruitful areas in the West African offshore, recording 9 commercial discoveries to date. Its main fields are: (i) Kuito, started-up in 1999, flowing at approximately 3 kbbl/d net to Eni in 2011; (ii) Landana and Tombua, started-up in 2009, flowing at approximately 9 kboe/d net to Eni. Production is supported by a Compliant Piled Tower provided with treatment facilities; (iii) Benguela-Belize/Lobito-Tomboco, started-up in 2006, flowing at approximately 11 kbbl/d net to Eni. Production from these fields is supported by a Compliant Piled Tower provided with treatment facilities for Benguela-Belize and an underwater linkage system for Lobito-Tomboco. Oil produced is treated at the Malongo plant. Associated gas of Landana/Tombua and Benguela-Belize/Lobito-Tomboco will be re-injected in the Nemba reservoir and later it will be delivered via a transport facility under construction to the A-LNG liquefaction plant (see below). Start-up is expected in 2014. Development Concept Selection activities are underway in the recent Malange and Lucapa discoveries. Concept Definition studies are underway in the Lianzi field. Block 15 Production Development Areas in former Block 15 produced on average 453 kbbl/d (approximately 34 kbbl/d net to Eni) in 2011. This is considered the most interesting area in the West African offshore with recoverable reserves estimated at 2.55 bbbl of oil. Production derives mainly from the Kizomba discovery area with: (i) the Hungo/Chocalho fields, started-up in August 2004 as part of phase A of the global development plan of the Kizomba reserves; (ii) the Kissanje/Dikanza fields, started-up in July 2005, as part of Phase B. In 2011, these fields operated by FPSO unit yielded production of approximately 272 kbbl/d (approximately 16 kbbl/d net to Eni). Other fields in Block 15 are Mondo, Saxi/Batuque and Xikombo fields which produced approximately 159 kbbl/d (approximately 17 kbbl/d net to Eni) in 2011. In the medium-term, production plateau will be supported by phased development of satellite discoveries. Development Main projects underway concerned: (i) the satellites of Kizomba Phase 1, with start-up expected before by mid 2012 and peaking production at 100 kbbl/d (approximately 21 kbbl/d net to Eni) in 2013; and (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 completed and will provide for the collection of all the gas of the Kizomba, Mondo and Saxi/Batuque fields to be delivered to the A-LNG liquefaction plant. Block 15/06 Exploration activities yielded positive results with: (i) the significant gas and condensates Lira discovery; and (ii) the Mukuvo-1 oil discovery and the Cinguvu-2 and Cabaça South East-3 appraisal wells containing oil. The discoveries of Block 15/06 increased the potential resources to be developed within two projects: the West Hub project, sanctioned in 2010, and the East Hub. Drilling and commitment activities were completed in advance of scheduled terms also thanks to the application of proprietary technologies. Eni Deep water dual casing running (e-dwdc TM ), Depth velocity analysis and Eni Circulation Device allowed enhancing the safety of drilling operations in deep water by means of accurate hydraulic control of the well and the real-time updating of subsurface data. The West Hub project includes the development of the Sangos, NGoma and Cinguvu discoveries which increases the potential of the hub up to more 200 mmbbl. Planned activity concerned drilling of 16 subsea wells (10 producers and 6 injectors) and linkage to an FPSO unit with a capacity of 100 kbbl/d. Associated gas will be re-injected in the reservoir. Start-up is expected in 2014 with a peaking production at 80 kbbl/d. The East Hub project intends to develop the Cabaça North e South-East discoveries with potential resources estimated at more 230 mmbbl. Development activity provides for the drilling of 23 subsea wells and the installation of an FPSO unit with a capacity of 100 kbbl/d. Start-up is expected in 2015. Further development phases are planned to start-up nearby discoveries. The LNG business in Angola Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant with a processing capacity of approximately 1.1 bcf/d of natural gas and produce 5.2 mmtonnes/y of LNG and over 50 kbbl/d of 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. Exports start-up is expected in the second quarter of 2012. LNG may be delivered to the United States market at the re-gasification plant in Pascagoula (Enis capacity amounting to approximately 205 bcf/y) in Mississippi. A joint company has been established to assess further possible marketing opportunities. In addition, Eni is part of the Gas Project, a second gas consortium with the Angolan national company and other partners that will explore further potential gas discoveries to support the feasibility of a second LNG train or other marketing projects to deliver gas and associated liquids. Eni is technical advisor with a 20% interest. This Gas Project covers Block 2 and agreement provides for a possible awarding of blocks 1, 3, 15 and 15/06, the Lower Congo Basin located in the Angolan offshore. Exploration activities yielded positive results in

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the Block 2 with the Garoupa-2 and Garoupa Norte 1 appraisal gas and condensates wells. A project is underway for the upgrade of primary health care services in the Luanda area by means of the rehabilitation of structures providing them with new equipment, among which a new center of nutrition and a network of day care centers. In addition Eni supported vaccination campaigns in cooperation with the local health center also organizing training sessions for local personnel. Congo Eni has been present in Congo since 1968. In 2011, production averaged 108 kboe/d net to Eni. Enis activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore covering a developed and undeveloped acreage of 9,516 square kilometers (5,020 square kilometers net to Eni). Enis main operated oil producing interests in Congo are the Zatchi (Enis interest 65%) and Loango (Enis interest 50%), Ikalou (Enis interest 100%), Djambala, Foukanda and Mwafi (Enis interest 65%), Kitina (Enis interest 35.75%), Awa Paloukou (Enis interest 90%), MBoundi (Enis interest 83%), Kouakouala (Enis interest 75%), Zingali and Loufika (Enis interest 100%) fields. Other relevant producing areas are a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits. In the exploration phase, Eni also holds interests in the Mer Très Profonde Sud deep offshore block (Enis interest 30%), the Noumbi onshore permit (Enis interest 37%) and the Marine XII offshore permit (Eni operator with a 65% interest). In 2011, Eni signed with the local authorities a Memorandum of Understanding to improve people living conditions in the MBoundi area. The integrated project concerns health, education, environmental and economic development. Exploration and production activities in Congo are regulated by Production Sharing Agreements. Production Production is provided mainly by the MBoundi (43 kboe/d), Awa Paloukou (6 kboe/d), Zatchi (9 kboe/d), Loango (6 kboe/d), Ikalou (6 kboe/d), Foukanda, Djambala and Mwafi and Kitina (overall 7 kboe/d) fields and by non-operated fields located in production PEX, Pointe Noire Grand Fond and Likouala (overall 24 kboe/d) permits. In 2011, production started-up at the Libondo offshore field in the PEX permit with production of approximately 3 kboe/d net to Eni. Development Activities on the MBoundi field moved forward with the application of advanced recovery techniques and a design to monetize associated gas within the activities aimed at zero gas flaring by 2012. In addition starting from 2009, Eni finalized long-term agreements to supply associated gas from the MBoundi field to feed three facilities in the Pointe Noire area: (i) the under construction potassium plant, owned by the Canadian Company MAG Industries; (ii) the existing Djeno power plant (CED - Centrale Electrique du Djeno) with a 50 MW generation capacity; and (iii) the recently built CEC Centrale Electrique du Congo power plant (Enis interest 20%) with a 300 MW generation capacity. These facilities will also receive in the future gas from the offshore discoveries of the Marine XII permit. In 2011, MBoundi supply to the CEC and CED power plants was approximately 106 mmcf/d (17 kboe/d net to Eni). The RIT project progressed for the rehabilitation of the power grid from Pointe Noire to Brazzaville within the integrated project to monetize gas in Congo. Other activities in the area concerned the optimization of producing fields by means of new technologies: (i) a drilling technique to increase the well-reservoir contact area at the Loango field with an additional volumes of approximately 300 bbl/d; (ii) in the Zatchi field, a system for consolidating sands to keep production sand free. The zero gas flaring has been achieved at the offshore Kitina field following the completion of the second phase of the water alternate gas project. Within the cooperation agreement, a project concerns the development and extraction of unconventional oil from the Tchikatanga and Tchikatanga-Makola oil sands deposits. The two deposits cover an area of 1,790 square kilometers and are deemed to contain significant amounts of resources based on a recent survey. Eni plans to monetize heavy oils extracted from these sands also through the possible application of its proprietary Eni Slurry Technology (EST). This technology can totally abate heavy residues and maximize light products. The project will also benefit from synergies resulting from the close proximity of the MBoundi operated field. Ghana Eni has been present in Ghana since 2009, following the acquisition of the Offshore Cape Three Points South and Offshore Cape Three Points (Eni operator with a 47.2% interest) exploration permits. Exploration activities yielded positive results with the Sankofa-2 appraisal well and the Gye Nyame discovery, both containing gas and condensates in the Offshore Cape Three Points license. Exploration success was boosted by the application of proprietary technologies in the area of seismic imaging and drilling, such as Eni Circulation Device enhancing hydraulic control of activities. Possible development synergies are under evaluation. During 2011 a project started for the fishing community of the Jomoro District that provides for better access to health services, support to local economy and training programs for improving management of economic activities by women and young people.

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Mozambique Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 block (Eni operator with a 70% interest) located in the offshore Rovuma Basin. Exploration activities yielded positive results with the following giant gas discoveries: (i) the Mamba South 1 exploration well with mineral potential estimated at 22.5 tcf in place; (ii) the Mamba North 1 with mineral potential estimated at 7.5 tcf; and (iii) the Mamba North East 1 with mineral potential estimated at 10 tcf. Exploration success was boosted by the application of proprietary technologies in the area of seismic imaging. Wells have been drilled with Enis proprietary technique deep water dual casing (e-dwdc TM ). The volume of natural gas discovered beyond expectation in Mozambique will lead to a new significant development opportunities in Far East Countries with an energy demand growth at fast pace. This is the largest operated discovery in the Companys exploration history. In a final completion configuration, production per well is expected to reach over 140 mmcf/d (approximately 25 kboe/d). In the next two years up to 8 additional wells are expected to be drilled in the nearby areas in order to monetize the high potential of the Mamba reservoir, investing euro 400 million. Nigeria Eni has been present in Nigeria since 1962. In 2011, Enis oil and gas production averaged 160 kboe/d over a developed and undeveloped acreage of 40,625 square kilometers (8,491 square kilometers net to Eni) located mainly in the onshore and offshore of the Niger Delta. In the development/production phase Eni is operator of onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Enis interest 20%) and onshore and offshore OML 125 (Enis interest 85%) and OMLs 120-121 (Enis interest 40%), holding interests in OML 118 (Enis interest 12.5%) as well as in OML 119 and 116 Service Contracts. As partners of SPDC JV, the largest joint venture in the Country, Eni also holds a 5% interest in 28 onshore blocks and a 12.86% interest in 5 conventional offshore blocks. In the exploration phase Eni is operator of offshore Oil Prospecting Leases (OPL) 244 (Enis interest 60%), OML 134 (former OPL 211 - Enis interest 85%) and onshore OPL 282 (Enis interest 90%) and OPL 135 (Enis interest 48%). Eni also holds a 12.5% interest in OML 135 (former OPL 219). In 2011, Eni optimized its producing asset portfolio: (i) the purchase from GEC Petroleum Development Co (GDPC) a 49% interest in Block OPL 2009 in addition to the awarding from the Nigerian Government a 50% interest in Block OPL 245 as well as relative license and operatorship; (ii) the divestment of a 5% interest in blocks OML 26 and OML 42; and (iii) the finalization of the divestment of a 40% interest in blocks OML 120 and 121. The transaction is subject to the approval of relevant authorities. During the year facilities to supply electricity in eight villages located in the Niger Delta area were completed with a total expenditure of euro 1 million. The project provides for the construction of required infrastructure for reaching 17 additional local communities.

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Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for state-owned company. Blocks OMLs 60, 61, 62 and 63 Production Onshore licenses OMLs 60, 61, 62 and 63 produced 66 kboe/d and accounted for 42% of Enis production in Nigeria in 2011. Liquid and gas production is supported by the NGL plant at Obiafu-Obrikom with a treatment capacity of approximately 1 bcf/d and by the oil tanker terminal at Brass with a storage capacity of approximately 3.5 mmbbl. A large portion of the gas reserves of these four OMLs is destined to supply the Bonny liquefaction plant (see below). Another portion of gas production is employed in firing the combined cycle power plant at Kwale-Okpai with a 480 MW generation capacity. In 2011, supplies to this power station were an overall amount of approximately 70 mmcf/d, corresponding to approximately 11 kboe/d (approximately 2 kboe/d net to Eni). This project is part of the Nigerian government and Enis plans for the reduction of carbon dioxide emissions and qualifies as CDM (Clean Development Mechanism) as provided for by the Kyoto Protocol. Development Activities aimed at guaranteeing production to feed gas to the Bonny liquefaction plant and flaring down progressed. As part of supply to the Bonny liquefaction plant, the compression and gas export capacity at the Obiafu/Obrikom plant was increased to ensure 170 mmcf/d net to Eni of feed gas for 20 years for sixth train. To the same end the development plan progressed at the Tuomo field with early-production start-up in 2012. Flaring down projects were completed at the Kwale and Obiafu/Obrikom production unit as well as the Ebocha oil center over the 2010-2011 period. The program includes also upgrading of the flowstation at the Idu field and the Ogbainbiri treatment plant with completion expected in 2012. Block OML 118 Production The Bonga oil field produced approximately 14 kbbl/d of oil net to Eni in 2011. Production is supported by an FPSO unit with a 225 kbbl/d treatment capacity and a 2 mmbbl storage capacity. Associated gas is carried to a collection platform on the EA field and, from there, is delivered to the Bonny liquefaction plant. Block OML 119 Production Production derived mainly from the Okono/Okpoho fields which yielded approximately 7 kbbl/d of oil net to Eni in 2011. Production is supported by an FPSO unit with an 80 kbbl/d treatment capacity and a 1 mmbbl storage capacity. Phase 2A project progressed to develop 23 mmbbl additional resources. Planned activity provides for the drilling of 2 subsea wells and the linkage to the existing FPSO unit. Start-up is expected in 2012. Block OML 125 Production The Abo field production amounted to approximately 21 kbbl/d of oil net to Eni in 2011. Production is supported by an FPSO unit with a 45 kbbl/d capacity and an 800 kbbl storage capacity. Block OPL 245 With almost 500 mmbbl of already discovered reserves, this deep-offshore block includes the largest undeveloped mineral resources potential in the Country. Enis activities concerned exploration and pre-development phases. Enis commitment is for a fast track development with an early-production of the Zabazaba and Etan fields in 2014. The preliminary development scheme provides for the installation of an FPSO unit with a capacity of 120 kboe/d, the drilling of 28 wells and the construction of transportation facilities to Bonny LNG plant. Exploration commitment concerned the appraisal of already discoveries. SPDC Joint Venture (NASE) In 2011, production from the SPDC JV accounted for approximately 30% of Enis production in Nigeria (47 kboe/d). The Forcados/Yokri oil and gas field is under development as part of the integrated associated gas gathering project aimed at supplying gas to the domestic market through Escravos-Lagos pipeline system. First gas is expected in 2013. In block OML 28 within the integrated oil and natural gas project in the Gbaran-Ubie area, the drilling program progressed. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of approximately 1 bcf/d of gas and 120 kbbl/d of liquids. Exploration activities yielded positive results in Block OML 36 with the Opugbene 2 appraisal well containing natural gas and condensates. The LNG business in Nigeria 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 six trains. The seventh unit is being engineered as it is in the planning phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 bcf/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount at the end of 2011 of 2,797 mmcf/d (267 mmcf/d net to Eni corresponding to approximately 48 kboe/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co. Eni holds a 17% interest in Brass LNG Ltd 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 2017 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 60 net to Eni) of feed gas on two trains for 20-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. Enis capacity amounts to approximately 201 bcf/y. Front end engineering activities progressed. The final investment decision is expected in 2012. n Kazakhstan Eni has been present in Kazakhstan since 1992 where the Company co-operates the Karachaganak producing field and is a partner of the consortium of the North Caspian Sea PSA to develop the Kashagan field.

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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 North Caspian Operating Company (NCOC) BV participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and the onshore part of Phase 2. The Consortium is currently focused on completing Phase 1 and starting commercial oil production. Management estimates that Phase 1 was 90% completed as of end of December 2011. Tranches 1 and 2 of the scope of work which target commercial production start-up reached approximately 98% at the end of the year. The Consortium continues to target the achievement of first commercial oil production by the end of 2012 or in the early 2013. The project Phase 1 (Experimental Program) as sanctioned by the partners of the venture targets an initial production capacity of 150 kbbl/d. In 2014, the second train of treatment and compression facilities for gas re-injection will be completed and come online enabling to increase the production capacity up to 370 kbbl/d. The partners are planning to further increase available production capacity up to 450 kbbl/d by installing additional gas compression capacity for re-injection in the reservoir. The partners intend to submit the scheme of this additional gas compression activity to the relevant Kazakh Authorities in the course of 2012 in order to obtain approval to start the engineering design. The partners are currently assessing the Phase 2 of the development of the Kashagan field with a view of optimizing the development lay-out. The review is expected to be completed by 2012. 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 Companys 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. Eni continues its commitment in the protection of the environment and ecosystems in the Caspian area with the completion of the first phase of the integrated program for the management of biodiversity. Enis Ural River Park project is nearing completion and Enis aim is to include it in the Man and Biosphere Program of UNESCO under the patronage of the Kazakh Ministry for Environmental Protection. Enis Extreme Lean Profile (x-lpt TM ) proprietary technology has been applied in drilling operations allowing to reduce costs and the environmental impact in drilling activities. In addition, Eni applied for the first time in a development well, an innovative safety valve installed in the casing and made with special steel resistant to corrosive conditions related of field fluids. Karachaganak Located in West onshore Kazakhstan, Karachaganak is a giant liquid and gas field with recoverable reserves of 5 bboe. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture with a 32.5% interest each. On December 14, 2011, the Republic of Kazakhstan and the contracting companies of Karachaganak Final Production Sharing Agreement (FPSA) reached an agreement to settle all pending claims. The agreement, effective from June 30, 2012 on satisfaction of conditions precedent, involves Kazakhstans KazMunaiGas (KMG) acquiring a 10% interest in the project. This will be done by each of the contracting companies transferring 10% of their rights and interest in the Karachaganak FPSA to KMG. The contracting companies will receive $1 billion net cash consideration ($325 million being Enis share). In addition the agreement provides for the allocation of an extra nominal capacity of 2 million tonnes of oil per annum capacity for the Karachaganak project in the Caspian Pipeline Consortium export pipeline. The effects of the agreement on profit and loss, reserve and production entitlements will be recognized in the 2012 financial statements. Production In 2011, production of the Karachaganak field averaged 239 kbbl/d of liquids (64 net to Eni) and 784 mmcf/d of natural gas (231 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. Approximately 85% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 240 kbbl/d and exported to Western markets through the Caspian Pipeline Consortium (Enis interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production and associated raw gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg. Development The fourth liquids stabilization train has been completed

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and allowed to increase export oil volumes through the Caspian Pipeline Consortium. Phase 3 of the Karachaganak project is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation of gas treatment plant and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing discussion to be presented to the relevant Authorities. In the area of water and energy management Eni is carrying out projects to support local communities. In particular the construction of the Aksai-Uralsk gas pipeline was completed. Other planned activities include: (i) facilities to increase drinking water availability in the Berezovka area; and (ii) construction of a power grid with the linkage to the Uralsk power station with a 54 MW generation capacity. n Rest of Asia China Eni has been present in China since 1984. In 2011, Enis production amounted to 8 kboe/d. Activities are located in the South China Sea over a developed and undeveloped acreage of 5,526 square kilometers (5,365 square kilometers net to Eni). In January 2011, Eni 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. The parties will also cooperate in the field of advanced technology, with a special focus on the exploitation of unconventional oil and gas resources. In July 2011, a similar agreement has been signed with Sinopec. In April 2012, Eni and China National Offshore Oil Corporation (CNOOC) signed a Production Sharing Contract for the exploration of Block 30/27, which has a high exploration potential and is located in one of the most attractive areas in the Chinese offshore. The agreement foresees the acquisition seismic 3D data and the drilling of 1 commitment well to be carried out in the first year of the exploration phase. Eni will be the Operator of the project, with a 100% interest. In the case of a discovery, CNOOC has a back-in right of up to 51%. Exploration and production activities in China are regulated by Production Sharing Agreements. Production Hydrocarbons are produced from the offshore Blocks 16/08 and 16/19 through eight platforms connected to an FPSO. Natural gas production from the HZ21-1 field is delivered through a sealine to the Zhuhai Terminal and sold to the CNOOC. Oil is mainly produced from HZ25-4 field (Enis interest 49%). Activity is operated by the CACT-Operating Group (Enis interest 16.33%). India Eni has been present in India since 2005 and is performing exploration and development activities over a developed and undeveloped acreage of 25,570 square kilometers (9,206 square kilometers net to Eni). In 2011, Enis production amounted to 4 kboe/d. Enis main fields in production/development are located in the offshore Cauvery Basin near the south-eastern coast. Production Production mainly comes from the PY-1 gas field which is part of the assets belonging to Hindustan Oil Exploration Co Ltd (Enis interest 47.18%) acquired within the Burren acquisition. Gas production is sold to the local national oil company. Indonesia Eni has been present in Indonesia since 2001. Enis production amounted to 18 kboe/d, mainly gas, in 2011. Activities are concentrated in the Eastern offshore and onshore East Kalimantan, offshore Sumatra, and offshore/onshore areas of West Timor, over a developed and undeveloped acreage of 28,841 square kilometers (17,719 square kilometers net to Eni) in 12 blocks. In 2011, Eni was awarded two operated gas exploration licenses: (i) the Arguni I block with a 100% interest located onshore and offshore in the Bintuni Basin near a liquefaction facility. The agreement foresees seismic data acquisition and the drilling of 2 commitment wells to be carried out in the first three years of exploration phase; and (ii) the North Ganal block, located offshore Indonesia near the relevant Jangkrik discoveries and the Bontang liquefaction terminal, in a consortium with other international oil companies. The commitment activities provide for the seismic data acquisition and the drilling of one well in the first three years. Exploration and production activities in Indonesia are regulated by PSAs. Production Production consists mainly of gas and derives from the Sanga Sanga permit (Enis interest 37.81%) with seven production fields. This gas is treated at the Bontang liquefaction plant, one of the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets. Development In 2011, the development plan of the operated Jangkrik (Enis interest 55%) and Jau (Enis interest 85%) gas fields has been approved by relevant authorities. Planned development activities at the Jangkrik offshore field include drilling of production wells, installation of a Floating Production Unit for gas and condensate treatment and construction of a transport facility connecting to the existing onshore network linked to the Bontang liquefaction plant for gas, while condensates will be supplied to the treatment plants in the area. Start-up is expected in 2016.

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The Jau offshore project provides for the drilling of production wells and the linkage to onshore plants via pipeline. Start-up is expected in 2016. The exploration activities related to the coal bed methane project progressed at the Sanga Sanga PSC. Pre-development activities are underway exploiting the synergy opportunities provided by the existing production and treatment facilities also including the Bontang LNG plant. Start-up is expected in 2013. In November 2011, Eni signed with the national power company PT Perusahaan Listrik Negara a Memorandum of Understanding to supply approximately 494 kcf/d of CBM gas for at least 5 years (corresponding to approximately 180 mmcf/y) to feed a power plant. The contract is in the process of being finalized. Within the activities carried out by Eni in support of local communities, medical and surgical interventions were directed to children in the area of East Kalimantan, near the Bukat permit (Eni operator with a 66.25% interest). Exploration Exploration activities yielded positive results with Jangkrik North East gas discovery in the Muara Bakau block (Eni operator with a 55% interest), located in the Kutei basin. Iran The formal hand over of operations to local partners at the Darquain project is almost completed. This was the sole Eni operated project in the Country. When the final hand over of operations will be completed, Enis involvements essentially will consist of being reimbursed for its past investments. Iraq Eni has been present in Iraq since 2009 and is performing development activities over a developed acreage of 1,074 square kilometers (352 square kilometers net to Eni). Production comes from Zubair oil field (Enis interest 32.8%) with a production of 7 kbbl/d net to Eni in 2011. Exploration and production activities in Iraq are regulated by a Technical Service Contract. The project, lasting 20-years term with a further 5 years extension, foresees to gradually increase production to a target plateau level of 1.2 mmbbl/d by 2016 and provides for two phases: (i) Rehabilitation plan aimed at improving current operations and reducing production decline as well as appraisal of both producing and undeveloped discovered reservoirs; and (ii) Enhanced Redevelopment Plan allowing to reach target plateau. The Water Agribusiness pilot project started in the Zubair area. The program is aimed at implementing a sustainable agricultural production model based on the reuse of water in agricultural activities creating producing units with low management costs also by means of higher energy efficiency. In addition the program aims at creating an international benchmark development model that will increase investment opportunities and promote employment. Pakistan Eni has been present in Pakistan since 2000. In 2011, Enis production averaged 58 kboe/d mainly of gas. Activities are located onshore covering a developed and undeveloped acreage of 22,953 square kilometers (9,289 square kilometers net to Eni). Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). Production Enis main permits in the Country are Bhit (Eni operator with a 40% interest), Sawan (Enis interest 23.68%) and Zamzama (Enis interest 17.75%) which, in 2011, accounted for approximately 81% of Enis production in Pakistan. Development Main development activities were aimed at reducing natural decline in: (i) the Bhit field where the installation of a compression facility was completed. Drilling activities and optimization of current production are underway to extend production plateau; (ii) the Zamzama field where the first phase of the Front End Compression project has been completed. Two additional wells will be drilled in 2012; and (iii) the Miano Front End Compression (Enis interest 15%) and Badhra Field Compression (Eni operator with a 40% interest) projects have been completed in 2011. As a part of activity to support local communities, medical centers and drinking water distribution facilities have been built in the Bhit, Badhra and Kadanwari areas. The innovative proprietary algorithms application for processing seismic data, such as the Common Reflection Surface Stack (e-crs TM ) allowed to improve the reservoir structure knowledge thus positioning successfully the Badhra 6 well. Exploration Exploration activity yielded positive results with: (i) the Kadanwari-27 exploration well, in the homonymous permit (Enis interest 18.42%) which yielded up to approximately 50 mmcf/d of gas in test production; (ii) the Lundo discovery and Tajjal 4 appraisal well in the Gambat permit (Enis interest 23.7%). The latter start-up is expected in 2012; and (iii) the Misri Bhambroo exploration well located in the SW Miano II permit (Enis interest 33.3%). Russia Eni has been present in Russia since 2007 following the acquisition of Lot 2 in the Yukos liquidation procedure. In particular, acquired assets included three Russian companies operating in the exploration and development of natural gas reserves: OAO Arctic Gas Co, ZAO Urengoil Inc and OAO Neftegaztechnologia. In September 2009, Eni and its Italian partner Enel in the 60-40% owned joint venture completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. The three companies

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managed by the subholding OOO SeverEnergia (Enis interest 29.4%) own 4 exploration/development blocks located in the Yamal Nenets region, with significant predominantly gas resources estimated in 1.6 bboe: (i) OAO Arctic Gas Company owns two exploration licenses, Sambursky and Yevo-Yakhinsky including seven gas and condensates fields currently in the appraisal/development phase. Main fields are Samburgskoye, Urengoiskoye and Yevo. The Samburgskoye field has been the first to be developed. In September 2011, Eni signed a contract whereby Gazprom commits to purchase volumes of gas produced by the Samburgskoye field. The agreement secured a final investment decision for the field development and in April 2012, Eni started production with an expected peak production of approximately 43 kboe/d (approximately 14 kboe/d, net to Eni). In the year, the Final Investment Decision of the onshore gas and condensate Urengoskoye field was sanctioned. Start-up is expected in 2014; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensates field. The development plan is in the process of being approved by relevant Authorities. Start-up is expected in 2012; and (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chaselskoye field. Full production plateau estimated at an overall 200 kboe/d is expected in 2019 following two additional start-ups of Yevo and Severo fields in 2018. Turkmenistan Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused in the Western part of the Country over a developed area of 200 square kilometers net to Eni, splitted into four development areas. In 2011, Enis production averaged 11 kbbl/d. Exploration and production activities in Turkmenistan are regulated by PSAs. Production Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap with the Turkmen Authorities, an equivalent amount of oil at the Okarem field, close to the South coast of the Caspian Sea. Enis entitlement is sold FOB. Associated natural gas is used for own consumption and gas lift system. The remaining amount is delivered to Turkmenneft, via national grid. n America Ecuador Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Enis interest 100%) located in the Oriente Basin, in the Amazon forest over a developed acreage of 1,985 square kilometers net to Eni. In 2011, Enis production averaged 7 kbbl/d. Exploration and production activities in Ecuador are regulated by a service contract, due to expire in 2023. Production Production derives from the Villano field, started-up in 1999. Production is carried out by means of a Central Production Facility linked by pipeline to the storage facility located in the Pacific Coast. Main development activities were aimed at reducing natural production decline. Trinidad & Tobago Eni has been present in Trinidad and Tobago since 1970. In 2011, Enis production averaged 57 mmcf/d (10 kboe/d). Activity is concentrated offshore North of Trinidad over a developed acreage of 382 square kilometers (66 square kilometers net to Eni). Exploration and production activities in Trinidad and Tobago are regulated by PSAs. Production Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields in the North Coast Marine Area 1 Block (Enis interest 17.3%). Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidads cost and sold under long-term contracts. LNG production is manly sold in the United States. Additional cargoes are sent to alternative destinations on a spot basis. United States Eni has been present in the USA since 1968. Activities are performed in the Gulf of Mexico, Alaska and more recently onshore in Texas. Developed and undeveloped acreage covers 8,982 square kilometers (5,123 square kilometers net to Eni). In 2011, Enis oil and gas production averaged 98 kboe/d. Exploration and production activities in the USA are regulated by concessions. Gulf of Mexico Eni holds interests in 307 exploration and production blocks in the conventional and deep-offshore in the Gulf of Mexico, of which 191 are operated by Eni. Production The main fields operated by Eni are Allegheny, Appaloosa and Morpeth (Enis interest 100%), Longhorn-Leo, Devils Towers and Triton (Enis interest 75%) as well as King Kong (Enis interest 54%) and Pegasus (Enis interest 58%). Eni also holds interests in the Medusa (Enis interest 25%), Europa (Enis interest 32%), and Thunder Hawk (Enis interest 25%) fields. In 2011, production started at the Appaloosa field with a production of 7 kbbl/d through linkage to the Corral operated platform with a treatment capacity of 33 kbbl/d net to Eni. Development Main activities included work-over activities at the Goldfinger (Enis interest 100%) and Spiderman (Enis interest 36.7%) fields as well as the drilling of development wells in the Triton field. Exploration Exploration activities yielded positive results in the offshore block KC919 (Enis interest 25%) with Hadrian North appraisal well containing oil and natural gas resources. The discovery allowed approving the development of the Greater Hadrian Area project. Texas Development The development activity progressed at the Alliance area (Enis interest 27.5%), in the Fort Worth basin in Texas. This area, including gas shale reserves, was acquired in 2009 following a strategic alliance Eni signed with Quicksilver Resources Inc. Production plateau at 9 kboe/d net to Eni is expected in 2012. Alaska Eni holds interests in 135 exploration and development blocks with interests ranging from 10% to 100%, for 59 of these blocks Eni is the operator. Production The Ooguruk offshore oil field (Enis interest 30%) produced 7 kbbl/d (approximately 2 kbbl/d net to Eni) in 2011. Production is treated at the onshore DS-3H plant. In 2011 production started at the Nikaitchuq operated field (Enis interest 100%), located in North Slope basins offshore Alaska, with resources of 220 million barrels. Drilling continues as scheduled. Start-up was achieved with application innovative technologies: (i) Eni

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Eni Fact Book Exploration & Production

proprietary Circulation Device that allowed maximizing the horizontal part of wells also at low depths; (ii) completion by means of distributed temperature sensing and injection control devices to enhance the recovery factor; and (iii) the first installation in the world of a submerged electrical pump completely extractible without employing workover plants. Development plan completion is expected in 2014 with an average production plateau at approximately 21 kbbl/d net to Eni in 2016. Venezuela Eni has been present in Venezuela since 1998. In 2011, Enis production averaged 9 kbbl/d. Activity is concentrated in the Gulf of Venezuela, in the Gulf of Paria and onshore in the Orinoco Oil Belt, over a developed and undeveloped acreage of 2,427 square kilometers (914 square kilometers net to Eni). Exploration and production of oil fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP). Production Production derives from the Corocoro oil field (Enis interest 26%) located in the Gulf of Paria West. In 2012 with the start-up of the Central Production Facility, Eni foresees to exceed current peak production of 42 kbbl/d (approximately 11 kbbl/d net to Eni). The subsequent development phase will allow reaching production of over 51 kbbl/d in 2015. Development Planning activities progressed at the Junin 5 field (Enis interest 40%) with 35 bbbl of certified heavy oil in place, located in the central part of the Orinoco Belt. First oil is expected in 2012 with a production plateau in the first phase of 75 kbbl/d, targeting a long-term production plateau of 240 kbbl/d to be reached in 2018. The project provides the construction of a refinery with a capacity of 350 kbbl/d that will allow also the treatment of intermediate streams from other PDVSA facilities. In 2011, upstream engineering contracts related to the processing plants were awarded. Start-up of drilling activity is expected in 2012. Eni agreed to finance part of PDVSAs development costs for the early production phase up to $1.5 billion. In addition, Eni will secure a tranche of the Junin 5 bonus and an additional financing to PDVSA for a total of $500 million to fund the construction of a power station in the Guiria peninsula, confirming its commitment to sustainable development. Exploration Pre-development and appraisal activities were completed at the large Perla gas field, located in the Cardon IV block (Enis interest 50%) in the Gulf of Venezuela. The results of Perla 4 and 5 appraisal wells exceeded the initial resource estimation to more than 16,000 bcf. PDVSA owns a 35% back-in right to be exercised in the development phase, and at that time Eni will hold a 32.5% joint controlled interest in the company. The final investment decision for the first development

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phase was sanctioned in the year and a Gas Sale Agreement was signed. EPC contracts for the project are being awarded. In addition, as part of the activities to support local communities, Eni started to build schools in the coastal area of the block. The early production phase includes the utilization of the already successfully drilled wells and the installation of production platforms linked by pipelines to the onshore treatment plant. The target production of approximately 300 mmcf/d is expected in 2014. The development of Perla is currently planned to continue with two more phases by means of the drilling of additional wells and the upgrading of treatment facilities to reach a plateau production of 1,200 mmcf/d. Eni is also participating with a 19.5% interest in the Gulfo de Paria Centrale offshore oil exploration block, where the Punta Sur oil discovery is located and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest, the latter coinciding with the Corocoro oil field area. n Australia and Oceania Australia Eni has been present in Australia since 2001. In 2011, Enis production of oil and natural gas averaged 28 kboe/d. Activities are focused on conventional and deep offshore fields over a developed and undeveloped area of 50,520 square kilometers (25,647 square kilometers net to Eni). The main production blocks in which Eni holds interests are WA-33-L (Enis interest 100%), WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Enis interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest). In the exploration phase Eni holds interests in 10 licenses (of which one with a 100% interest). In May 2011, Eni signed an agreement with MEO Australia Ltd to farm-in the Heron and Blackwood gas discoveries in permit NT/P-68, located in the Timor Sea. Eni acquired a 50% stake and operatorship in the first gas discovery by financing exploration activities relating to the drilling of two appraisal wells. Eni was granted an option to earn a 50% stake in Blackwood discovery by performing seismic surveys and drilling one well in the area. The agreement also provides an option to acquire an additional 25% in both the discoveries by financing the development plan required to reach a final investment decision. In November 2011, Eni acquired a 32.5% stake in the Evans Shoal gas discovery in the Timor Sea with approximately 7 tcf of volumes of gas in place. Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs. Block WA-25-L Production The Wollybutt oil field, started-up in 2003, produced approximately 3 kbbl/d (approximately 2 kbbl/d net to Eni) in 2011. Production is supported by horizontal wells and operated by an FPSO unit. Block JPDA 03-13 Production The liquids and gas Bayu Undan field, started-up in 2004, and produced 190 kboe/d (approximately 13 kboe/d net to Eni) in 2011. Liquid production is supported by 3 treatment platforms and an FSO unit. Production of natural gas is mostly carried by a 500-kilometer long pipeline and is treated at the Darwin liquefaction plant which has a capacity of 3.2 mmtonnes/y of LNG (equivalent to approximately 173 bcf/y of feed gas). LNG is sold to Japanese power generation companies under long-term contracts. Block WA-33-L Production The Blacktip gas field (Enis interest 100%), started-up in 2009, and produced approximately 21 bcf/y in 2011. The project is supported by a production platform and carried by a 108-kilometer long pipeline to an onshore treatment plant with a capacity of 42 bcf/y. Natural gas extracted from this field will be sold under a 25-year contract signed with Power & Water Utility Co. Block JPDA 06-105 Production In October 2011, production started at the Kitan oil field (Eni operator with a 40% interest) located between Timor Leste and Australia. Start-up was achieved by means of: (i) the completion of drilling activities in the deep offshore, whose positioning has been optimized with the application of innovative methods for seismic data developed by Eni (Depth Velocity Analysis, e-dva™ and Reverse Time Migration); and (ii) the linkage to an FPSO plant (Floating Production Storage and Offloading). Peak production of over 40 kbbl/d is expected in 2012.

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Eni Fact Book Exploration & Production

Estimated net proved hydrocarbons reserves by geographic area (a) (mmboe)

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

2007 — Estimated net proved hydrocarbons reserves	747	638	1,897	1,100	1,061	514	280	133	6,370
Consolidated subsidiaries	747	638	1,879	1,095	1,061	198	259	133	6,010
Equity-accounted
entities			18	5		316	21		360
Developed	534	537	1,198	769	494	172	158	63	3,925
Consolidated
subsidiaries	534	537	1,183	766	494	127	158	63	3,862
Equity-accounted entities			15	3		45			63
Undeveloped	213	101	699	331	567	342	122	70	2,445
Consolidated subsidiaries	213	101	696	329	567	71	101	70	2,148
Equity-accounted
entities			3	2		271	21		297
2008
Estimated net proved hydrocarbons reserves	681	525	1,939	1,154	1,336	579	254	132	6,600
Consolidated subsidiaries	681	525	1,922	1,146	1,336	265	235	132	6,242
Equity-accounted
entities			17	8		314	19		358
Developed	465	417	1,242	831	647	212	140	62	4,016
Consolidated
subsidiaries	465	417	1,229	827	647	168	133	62	3,948
Equity-accounted entities			13	4		44	7		68
Undeveloped	216	108	697	323	689	367	114	70	2,584
Consolidated subsidiaries	216	108	693	319	689	97	102	70	2,294
Equity-accounted
entities			4	4		270	12		290
2009
Estimated net proved hydrocarbons reserves	703	590	1,937	1,163	1,221	545	279	133	6,571
Consolidated subsidiaries	703	590	1,922	1,141	1,221	236	263	133	6,209
Equity-accounted
entities			15	22		309	16		362
Developed	490	432	1,278	804	614	183	181	122	4,104
Consolidated
subsidiaries	490	432	1,266	799	614	139	168	122	4,030
Equity-accounted entities			12	5		44	13		74
Undeveloped	213	158	659	359	607	362	98	11	2,467
Consolidated subsidiaries	213	158	656	342	607	97	95	11	2,179
Equity-accounted
entities			3	17		265	3		288
2010
Estimated net proved hydrocarbons reserves	724	601	2,119	1,161	1,126	612	373	127	6,843
Consolidated subsidiaries	724	601	2,096	1,133	1,126	295	230	127	6,332
Equity-accounted
entities			23	28		317	143		511
Developed	554	405	1,237	817	543	182	167	117	4,022
Consolidated
subsidiaries	554	405	1,215	812	543	139	141	117	3,926
Equity-accounted entities			22	5		43	26		96
Undeveloped	170	196	882	344	583	430	206	10	2,821
Consolidated subsidiaries	170	196	881	321	583	156	89	10	2,406
Equity-accounted
entities			1	23		274	117		415
2011
Estimated net proved hydrocarbons reserves	707	630	2,052	1,104	950	886	624	133	7,086
Consolidated subsidiaries	707	630	2,031	1,021	950	230	238	133	5,940
Equity-accounted
entities			21	83		656	386		1,146
Developed	540	374	1,194	746	482	134	188	112	3,770
Consolidated
subsidiaries	540	374	1,175	742	482	129	162	112	3,716
Equity-accounted entities			19	4		5	26		54
Undeveloped	167	256	858	358	468	752	436	21	3,316
Consolidated subsidiaries	167	256	856	279	468	101	76	21	2,224
Equity-accounted
entities			2	79		651	360		1,092

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.
(b)	i	Including
approximately, 749, 746, 769, 767 and 767 billion of
cubic feet of natural gas held in storage at December 31,
2007, 2008, 2009, 2010 and 2011, respectively.
(c)	i	Enis
proved reserves of the Kashagan field were determined
based on Eni working interest of 16.81% since December
31, 2008 and 18.52% in 2007.
(d)	i	Includes a
29.4% stake of the reserves of the three equity-accounted
Russian companies participated by joint venture OOO
SeverEnergia, owned by Eni (60%) and its Italian partner
Enel (40%) which on September 23, 2009, completed the
divestment of the 51% stake in the venture to Gazprom in
line with the call option arrangement.

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Estimated net proved liquids reserves by geographic area (mmbbl)

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

2007 — Estimated net proved liquids reserves	215	345	894	730	753	94	159	29	3,219
Consolidated subsidiaries	215	345	878	725	753	44	138	29	3,127
Equity-accounted
entities			16	5		50	21		92
Developed	133	299	662	513	219	41	81	26	1,974
Consolidated
subsidiaries	133	299	649	511	219	35	81	26	1,953
Equity-accounted entities			13	2		6			21
Undeveloped	82	46	232	217	534	53	78	3	1,245
Consolidated subsidiaries	82	46	229	214	534	9	57	3	1,174
Equity-accounted
entities			3	3		44	21		71
2008
Estimated net proved liquids reserves	186	277	837	791	911	157	150	26	3,335
Consolidated subsidiaries	186	277	823	783	911	106	131	26	3,243
Equity-accounted
entities			14	8		51	19		92
Developed	111	222	624	580	298	97	81	23	2,036
Consolidated
subsidiaries	111	222	613	576	298	92	74	23	2,009
Equity-accounted entities			11	4		5	7		27
Undeveloped	75	55	213	211	613	60	69	3	1,299
Consolidated subsidiaries	75	55	210	207	613	14	57	3	1,234
Equity-accounted
entities			3	4		46	12		65
2009
Estimated net proved liquids reserves	233	351	908	777	849	144	169	32	3,463
Consolidated subsidiaries	233	351	895	770	849	94	153	32	3,377
Equity-accounted
entities			13	7		50	16		86
Developed	141	218	669	548	291	52	93	23	2,035
Consolidated
subsidiaries	141	218	659	544	291	45	80	23	2,001
Equity-accounted entities			10	4		7	13		34
Undeveloped	92	133	239	229	558	92	76	9	1,428
Consolidated subsidiaries	92	133	236	226	558	49	73	9	1,376
Equity-accounted
entities			3	3		43	3		52
2010
Estimated net proved liquids reserves	248	349	997	756	788	183	273	29	3,623
Consolidated subsidiaries	248	349	978	750	788	139	134	29	3,415
Equity-accounted
entities			19	6		44	139		208
Developed	183	207	674	537	251	44	87	20	2,003
Consolidated
subsidiaries	183	207	656	533	251	39	62	20	1,951
Equity-accounted entities			18	4		5	25		52
Undeveloped	65	142	323	219	537	139	186	9	1,620
Consolidated subsidiaries	65	142	322	217	537	100	72	9	1,464
Equity-accounted
entities			1	2		39	114		156
2011
Estimated net proved liquids reserves	259	372	934	692	653	216	283	25	3,434
Consolidated subsidiaries	259	372	917	670	653	106	132	25	3,134
Equity-accounted
entities			17	22		110	151		300
Developed	184	195	638	487	215	34	117	25	1,895
Consolidated
subsidiaries	184	195	622	483	215	34	92	25	1,850
Equity-accounted entities			16	4			25		45
Undeveloped	75	177	296	205	438	182	166		1,539
Consolidated subsidiaries	75	177	295	187	438	72	40		1,284
Equity-accounted
entities			1	18		110	126		255

i	i	i
(a)	i	Enis
proved reserves of the Kashagan field were determined
based on Eni working interest of 16.81% since December
31, 2008 and 18.52% in 2007.
(b)	i	Includes a
29.4% stake of the reserves of the three equity-accounted
Russian companies participated by joint venture OOO
SeverEnergia, owned by Eni (60%) and its Italian partner
Enel (40%) which on September 23, 2009, completed the
divestment of the 51% stake in the venture to Gazprom in
line with the call option arrangement.

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Estimated net proved natural gas reserves by geographic area (bcf)

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

2007 — Estimated net proved natural gas reserves	3,057	1,675	5,766	2,124	1,770	2,404	696	598	18,090
Consolidated subsidiaries	3,057	1,675	5,751	2,122	1,770	880	696	598	16,549
Equity-accounted
entities			15	2		1,524			1,541
Developed	2,304	1,364	3,077	1,471	1,580	753	442	213	11,204
Consolidated
subsidiaries	2,304	1,364	3,065	1,469	1,580	530	442	213	10,967
Equity-accounted entities			12	2		223			237
Undeveloped	753	311	2,689	653	190	1,651	254	385	6,886
Consolidated subsidiaries	753	311	2,686	653	190	350	254	385	5,582
Equity-accounted
entities			3			1,301			1,304
2008
Estimated net proved natural gas reserves	2,844	1,421	6,324	2,086	2,437	2,430	600	606	18,748
Consolidated subsidiaries	2,844	1,421	6,311	2,084	2,437	911	600	606	17,214
Equity-accounted
entities			13	2		1,519			1,534
Developed	2,031	1,122	3,548	1,444	2,005	657	340	221	11,368
Consolidated
subsidiaries	2,031	1,122	3,537	1,443	2,005	439	340	221	11,138
Equity-accounted entities			11	1		218			230
Undeveloped	813	299	2,776	642	432	1,773	260	385	7,380
Consolidated subsidiaries	813	299	2,774	641	432	472	260	385	6,076
Equity-accounted
entities			2	1		1,301			1,304
2009
Estimated net proved natural gas reserves	2,704	1,380	5,908	2,212	2,139	2,301	631	575	17,850
Consolidated subsidiaries	2,704	1,380	5,894	2,127	2,139	814	629	575	16,262
Equity-accounted
entities			14	85		1,487	2		1,588
Developed	2,001	1,231	3,498	1,468	1,859	756	506	565	11,884
Consolidated
subsidiaries	2,001	1,231	3,486	1,463	1,859	539	506	565	11,650
Equity-accounted entities			12	5		217			234
Undeveloped	703	149	2,410	744	280	1,545	125	10	5,966
Consolidated subsidiaries	703	149	2,408	664	280	275	123	10	4,612
Equity-accounted
entities			2	80		1,270	2		1,354
2010
Estimated net proved natural gas reserves	2,644	1,401	6,231	2,245	1,874	2,391	552	544	17,882
Consolidated subsidiaries	2,644	1,401	6,207	2,127	1,874	871	530	544	16,198
Equity-accounted
entities			24	118		1,520	22		1,684
Developed	2,061	1,103	3,122	1,554	1,621	774	437	539	11,211
Consolidated
subsidiaries	2,061	1,103	3,100	1,550	1,621	560	431	539	10,965
Equity-accounted entities			22	4		214	6		246
Undeveloped	583	298	3,109	691	253	1,617	115	5	6,671
Consolidated subsidiaries	583	298	3,107	577	253	311	99	5	5,233
Equity-accounted
entities			2	114		1,306	16		1,438
2011
Estimated net proved natural gas reserves	2,491	1,427	6,210	2,287	1,648	3,718	1,897	604	20,282
Consolidated subsidiaries	2,491	1,425	6,190	1,949	1,648	685	590	604	15,582
Equity-accounted
entities		2	20	338		3,033	1,307		4,700
Developed	1,977	995	3,087	1,441	1,480	552	393	491	10,416
Consolidated
subsidiaries	1,977	995	3,070	1,437	1,480	528	385	491	10,363
Equity-accounted entities			17	4		24	8		53
Undeveloped	514	432	3,123	846	168	3,166	1,504	113	9,866
Consolidated subsidiaries	514	430	3,120	512	168	157	205	113	5,219
Equity-accounted
entities		2	3	334		3,009	1,299		4,647

i	i	i
(a)	i	Including
approximately, 749, 746, 769, 767 and 767 billion of
cubic feet of natural gas held in storage at December 31,
2007, 2008, 2009, 2010 and 2011, respectively.
(b)	i	Enis
proved reserves of the Kashagan field were determined
based on Eni working interest of 16.81% since December
31, 2008 and 18.52% in 2007.
(c)	i	Includes a
29.4% stake of the reserves of the three equity-accounted
Russian companies participated by joint venture OOO
SeverEnergia, owned by Eni (60%) and its Italian partner
Enel (40%) which on September 23, 2009, completed the
divestment of the 51% stake in the venture to Gazprom in
line with the call option arrangement.

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Oil and natural gas production by Country (a) (b) (kboe/d) 2007 2008 2009 2010 2011

Italy	212	199	169	183	186
Rest of Europe	270	249	247	222	216
Croatia	9	12	17	8	5
Norway	137	129	126	123	131
United Kingdom	124	108	104	91	80
North Africa	594	645	573	602	438
Algeria	88	83	83	77	72
Egypt	238	240	230	232	236
Libya	252	306	244	273	112
Tunisia	16	16	16	20	18
Sub-Saharan Africa	327	335	360	400	370
Angola	136	126	130	118	102
Congo	69	87	102	110	108
Nigeria	122	122	128	172	160
Kazakhstan	112	111	115	108	106
Rest of Asia	108	124	135	131	112
China	8	8	8	7	8
India			1	8	4
Indonesia	20	20	21	19	18
Iran	26	28	35	21	6
Iraq				5	7
Pakistan	52	56	58	59	58
Russia	2
Turkmenistan		12	12	12	11
America	95	117	153	143	125
Brazil					1
Ecuador	16	16	14	11	7
Trinidad
& Tobago	10	9	12	12	10
United States	69	87	119	109	98
Venezuela		5	8	11	9
Australia and Oceania	18	17	17	26	28
Australia	18	17	17	26	28
Total outside Italy	1,524	1,598	1,600	1,632	1,395
	1,736	1,797	1,769	1,815	1,581
of which equity-accounted
entities	18	20	23	25	26
Angola	5	3	3	3	4
Brazil					1
Indonesia	6	6	6	6	6
Russia	2
Tunisia	5	6	6	5	6
Venezuela		5	8	11	9

i i i

Oil and natural gas production sold (c) (mmboe) 2007 2008 2009 2010 2011

| Oil and natural gas production — Change in
inventories other | | 633.7 — (3.5 | ) | 657.5 — (7.6 | ) | 645.7 — (3.8 | ) | 662.3 — (3.4 | ) | 577.0 — (7.4 | ) |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Own consumption of gas | | (18.8 | ) | (17.9 | ) | (19.1 | ) | (20.9 | ) | (21.1 | ) |
| Oil and natural gas production sold | | 611.4 | | 632.0 | | 622.8 | | 638.0 | | 548.5 | |
| Oil | (mmbbl) | 370.28 | | 370.24 | | 365.20 | | 361.30 | | 302.61 | |
| - of
which to R&M Division | | 227.68 | | 194.64 | | 224.98 | | 206.41 | | 190.65 | |
| Natural gas | (bcf) | 1,385 | | 1,503 | | 1,479 | | 1,536 | | 1,367 | |
| - of
which to G&P Division | | 510 | | 480 | | 444 | | 432 | | 423 | |

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.
(b)	i	Includes
volumes of gas consumed in operations (321, 318, 300, 281
and 296 mmcf/d, in 2011, 2010, 2009, 2008 and 2007,
respectively).
(c)	i	Includes 7.7
mmboe of equity-accounted entities production sold in
2011 (8, 7.1, 5.7 and 5.3 mmboe in 2010, 2009, 2008 and
2007, respectively).

36 -

Contents

Eni Fact Book Exploration & Production

Liquids production by Country (kbbl/d) 2007 2008 2009 2010 2011

Italy	75	68	56	61	64
Rest of Europe	157	140	133	121	120
Norway	90	83	78	74	80
United
Kingdom	67	57	55	47	40
North Africa	337	338	292	301	209
Algeria	85	80	80	74	69
Egypt	97	98	91	96	91
Libya	142	147	108	116	36
Tunisia	13	13	13	15	13
Sub-Saharan Africa	280	289	312	321	278
Angola	132	121	125	113	95
Congo	67	84	97	98	87
Nigeria	81	84	90	110	96
Kazakhstan	70	69	70	65	64
Rest of Asia	37	49	57	48	34
China	6	6	7	6	7
India				1
Indonesia	2	2	2	2	2
Iran	26	28	35	21	6
Iraq				5	7
Pakistan	1	1	1	1	1
Russia	2
Turkmenistan		12	12	12	11
America	53	63	79	71	65
Brazil					1
Ecuador	16	16	14	11	7
United States	37	42	57	49	48
Venezuela		5	8	11	9
Australia and Oceania	11	10	8	9	11
Australia	11	10	8	9	11
Total outside Italy	945	958	951	936	781
	1,020	1,026	1,007	997	845
of which equity-accounted
entities	12	14	17	19	19
Angola	5	3	3	3	3
Brazil					1
Indonesia	1	1	1	1	1
Russia	2
Tunisia	4	5	5	4	5
Venezuela		5	8	11	9

Oil and natural gas production available for sale (a) (b) (kboe/d) 2007 2008 2009 2010 2011

Italy	208	195	165	178	181
Rest of
Europe	263	242	239	214	209
North Africa	573	627	554	582	420
Sub-Saharan
Africa	318	325	349	386	354
Kazakhstan	109	108	113	104	102
Rest of
Asia	102	119	130	126	106
America	93	116	150	141	124
Australia
and Oceania	18	16	16	26	27
	1,684	1,748	1,716	1,757	1,523
of which equity-accounted
entities	16	19	21	23	23
North Africa	5	5	5	5	5
Sub-Saharan Africa	4	3	3	3	3
Rest of Asia	7	6	5	5	4
America		5	8	10	11

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.
(b)	i	Do not
include natural gas consumed in operation (321, 318, 300,
281 and 296 mmcf/d, in 2011, 2010, 2009, 2008 and 2007,
respectively).

37 -

Contents

Eni Fact Book Exploration & Production

Natural gas production by Country (a) (b) (mmcf/d) 2007 2008 2009 2010 2011

Italy	789.7	749.9	652.6	673.2	674.3
Rest of Europe	647.2	626.7	655.5	559.2	537.9
Croatia	52.5	68.7	95.5	45.3	29.9
Norway	271.1	264.8	273.7	271.6	284.0
United Kingdom	323.6	293.2	286.3	242.3	224.0
North Africa	1,474.2	1,761.6	1,614.2	1,673.2	1,271.5
Algeria	18.8	18.5	19.7	20.2	19.0
Egypt	811.2	818.4	793.7	755.1	800.7
Libya	629.6	907.6	780.4	871.1	423.2
Tunisia	14.6	17.1	20.4	26.8	28.6
Sub-Saharan Africa	274.2	260.7	274.3	441.5	508.0
Angola	25.1	28.1	29.3	31.9	34.7
Congo	11.4	12.7	27.3	67.9	119.1
Nigeria	237.7	219.9	217.7	341.7	354.2
Kazakhstan	237.9	244.7	259.0	237.0	231.0
Rest of Asia	408.9	426.2	444.8	463.9	430.1
China	11.0	10.9	8.2	6.7	5.0
India			3.7	36.6	19.6
Indonesia	105.4	99.7	104.8	94.4	84.3
Pakistan	292.5	315.6	328.1	326.2	321.2
America	240.3	311.5	424.7	396.0	334.0
Trinidad
& Tobago	58.9	54.6	67.0	63.6	56.7
United States	181.4	256.9	357.7	332.4	277.3
Australia and Oceania	41.5	42.2	48.6	95.7	97.8
Australia	41.5	42.2	48.6	95.7	97.8
Total outside Italy	3,324.2	3,673.6	3,721.1	3,866.5	3,410.3
	4,113.9	4,423.5	4,373.7	4,539.7	4,084.6
of which equity-accounted
entities	37.5	35.6	38.3	35.6	34.0
Angola	0.7	0.6	0.7	0.8	1.9
Indonesia	32.2	30.5	32.1	28.9	25.7
Tunisia	4.6	4.5	5.5	5.9	6.4

Natural gas production available for sale (b) (mmcf/d) 2007 2008 2009 2010 2011

Italy	763	725	630	648	648
Rest of
Europe	607	588	608	517	498
North Africa	1,357	1,661	1,503	1,559	1,169
Sub-Saharan
Africa	220	204	213	365	422
Kazakhstan	222	227	241	221	212
Rest of
Asia	380	396	417	436	398
America	232	304	416	385	323
Australia
and Oceania	38	38	46	91	93
	3,819	4,143	4,074	4,222	3,763
of which equity-accounted
entities	28	26	29	27	24
North Africa	1	1	8	3	4
Sub-Saharan Africa	1
Rest of Asia	26	24	26	24	20

i	i	i
(a)	i	Includes
volumes of gas consumed in operations (321, 318, 300, 281
and 296 mmcf/d, in 2011, 2010, 2009, 2008 and 2007,
respectively).
(b)	i	Do not
include natural gas consumed in operation.

38 -

Contents

Eni Fact Book Exploration & Production

Average realizations 2007 2008 2009 2010 2011


Liquids
($/bbl)

| Italy — Rest of
Europe | 62.47 — 70.84 | | 84.87 — 71.90 | | 56.02 — 56.46 | | 72.19 — 67.26 | | 101.20 — 97.56 | 97.18 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| North Africa | 68.39 | 14.56 | 85.38 | 14.70 | 56.42 | 14.60 | 70.96 | 16.09 | 97.63 | 17.98 |
| Sub-Saharan
Africa | 69.77 | 70.72 | 91.58 | 98.40 | 59.75 | 56.85 | 78.23 | 77.78 | 110.09 | 108.92 |
| Kazakhstan | 59.34 | | 79.06 | | 52.34 | | 66.74 | | 98.68 | |
| Rest of
Asia | 66.60 | 31.41 | 75.29 | | 55.34 | 9.01 | 75.20 | 57.05 | 101.09 | 74.98 |
| America | 66.37 | | 88.88 | 86.42 | 55.66 | 56.41 | 72.84 | 71.70 | 101.15 | 93.03 |
| Australia
and Oceania | 71.23 | | 82.80 | | 50.40 | | 73.00 | | 98.05 | |
| | 67.94 | 20.97 | 84.31 | 56.04 | 57.02 | 44.43 | 72.95 | 58.86 | 102.47 | 84.78 |
| Natural gas | | | | | | | | | | |
| ($/kcf) | | | | | | | | | | |
| Italy | 8.58 | | 13.06 | | 9.01 | | 8.71 | | 11.56 | |
| Rest of
Europe | 6.71 | | 10.55 | | 7.06 | | 7.40 | | 9.72 | 10.65 |
| North Africa | 4.61 | | 7.15 | | 5.79 | | 6.87 | | 5.95 | 5.39 |
| Sub-Saharan
Africa | 1.21 | | 1.50 | | 1.66 | | 1.87 | | 1.97 | |
| Kazakhstan | 0.41 | | 0.53 | | 0.45 | | 0.49 | | 0.57 | |
| Rest of
Asia | 4.04 | 8.48 | 5.05 | 12.40 | 4.09 | 7.44 | 4.35 | 9.87 | 5.27 | 15.68 |
| America | 6.69 | | 8.81 | | 4.05 | | 4.70 | | 4.02 | |
| Australia
and Oceania | 5.94 | | 9.59 | | 8.14 | | 7.40 | | 7.38 | |
| | 5.40 | 8.08 | 7.99 | 11.91 | 5.62 | 6.81 | 6.01 | 8.73 | 6.44 | 13.89 |
| Hydrocarbons | | | | | | | | | | |
| ($/boe) | | | | | | | | | | |
| Italy | 54.03 | | 78.46 | | 53.17 | | 56.60 | | 77.26 | |
| Rest of
Europe | 57.95 | | 67.15 | | 49.53 | | 56.00 | | 79.03 | 66.14 |
| North Africa | 50.70 | 13.61 | 64.91 | 13.86 | 45.47 | 13.19 | 55.06 | 13.53 | 64.85 | 20.87 |
| Sub-Saharan
Africa | 62.36 | 70.72 | 81.77 | 98.40 | 54.61 | 56.85 | 66.35 | 77.78 | 88.02 | 108.92 |
| Kazakhstan | 38.98 | | 51.30 | | 33.65 | | 42.24 | | 62.87 | |
| Rest of
Asia | 38.96 | 43.43 | 48.85 | 69.22 | 38.21 | 41.80 | 42.45 | 55.04 | 51.51 | 85.80 |
| America | 54.23 | | 70.41 | 86.42 | 39.29 | 56.32 | 47.84 | 71.70 | 60.28 | 93.03 |
| Australia
and Oceania | 57.72 | | 71.43 | | 48.63 | | 52.51 | | 61.00 | |
| | 53.29 | 33.11 | 68.21 | 60.50 | 46.90 | 42.82 | 55.59 | 56.10 | 72.20 | 83.15 |

Enis Group	2007	2008	2009	2010	2011
Liquids ($/bbl) (a)	67.70	84.05	56.95	72.76	102.11
Natural
gas ($/kcf)	5.42	8.01	5.62	6.02	6.48
Hydrocarbons ($/boe)	53.17	68.13	46.90	55.60	72.26

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

Net developed and undeveloped acreage (square kilometers) 2007 2008 2009 2010 2011

Europe	32,055	30,511	31,607	29,079	26,023
Italy	20,664	20,409	22,038	19,097	16,872
Rest of Europe	11,391	10,102	9,569	9,982	9,151
Africa	227,932	249,672	158,749	152,671	137,220
North Africa	62,886	31,088	46,011	44,277	30,532
Sub-Saharan
Africa	165,046	218,584	112,738	108,394	106,688
Asia	80,339	93,710	125,641	112,745	55,284
Kazakhstan	959	880	880	880	880
Rest of Asia	79,380	92,830	124,761	111,865	54,404
America	12,804	12,043	11,523	11,187	10,209
Australia and Oceania	41,361	29,558	20,342	15,279	25,685
Total	394,491	415,494	347,862	320,961	254,421

39 -

Contents

Eni Fact Book Exploration & Production

Principal oil and natural gas interests at December 31, 2011

Commencement of operations Number of interests Gross developed (a) (b) acreage Net developed (a) (b) acreage Gross undeveloped (a) acreage Net undeveloped (a) acreage Type of fields/acreage Number of producing fields Number of other fields

EUROPE		286	17,324	11,216	24,007	14,807		138	101
Italy	1926	151	10,927	9,055	10,721	7,817	Onshore/Offshore	83	72
Rest of Europe		135	6,397	2,161	13,286	6,990		55	29
Croatia	1996	2	1,975	987			Offshore	9	3
Norway	1965	50	2,262	337	5,838	1,998	Offshore	16	16
Poland	2010	3			1,968	1,968	Onshore
United Kingdom	1964	74	2,110	807	789	207	Offshore	29	10
Ukraine	2011	2	50	30	49	15	Onshore	1
Other countries		4			4,642	2,802	Offshore
AFRICA		270	67,154	20,167	200,957	117,053		276	136
North Africa		112	31,781	13,877	36,772	16,655		101	59
Algeria	1981	39	2,261	815	17,358	8,250	Onshore	28	13
Egypt	1954	52	5,109	1,837	10,727	4,061	Onshore/Offshore	41	26
Libya	1959	10	17,947	8,951	8,687	4,344	Onshore/Offshore	11	15
Tunisia	1961	11	6,464	2,274			Onshore/Offshore	21	5
Sub-Saharan Africa		158	35,373	6,290	164,185	100,398		175	77
Angola	1980	68	4,636	625	20,360	5,593	Onshore/Offshore	47	32
Congo	1968	26	1,835	1,012	7,681	4,008	Onshore/Offshore	25	4
Dem. Republic of
Congo	2010	1			478	263	Onshore
Gabon	2008	6			7,615	7,615	Onshore/Offshore
Ghana	2009	2			5,144	1,885	Offshore
Mali	2006	1			32,458	21,640	Onshore
Mozambique	2007	1			12,956	9,502	Offshore
Nigeria	1962	46	28,902	4,653	11,723	3,838	Onshore/Offshore	103	41
Togo	2010	2			6,192	6,192	Offshore
Other
countries		5			59,578	39,862	Onshore
ASIA		74	17,478	5,893	100,759	49,391		39	31
Kazakhstan	1992	6	324	105	4,609	775	Onshore/Offshore	1	5
Rest of Asia		68	17,154	5,788	96,150	48,616		38	26
China	1984	10	200	39	5,326	5,326	Offshore	11
India	2005	13	206	109	25,364	9,097	Onshore/Offshore	5	1
Indonesia	2001	12	1,735	656	27,106	17,063	Onshore/Offshore	7	15
Iran	1957	4	1,456	820			Onshore/Offshore	3
Iraq	2009	1	1,074	352			Onshore	1
Pakistan	2000	18	8,781	2,582	14,172	6,707	Onshore/Offshore	9	1
Russia	2007	4	3,502	1,030	1,495	439	Onshore		9
Timor Leste	2006	4			8,087	6,740	Offshore
Turkmenistan	2008	1	200	200			Onshore	2
Other countries		1			14,600	3,244	Offshore
AMERICA		460	5,979	3,052	15,602	7,157		68	20
Brazil	1999	2	1,513	50	745	745	Offshore	1
Ecuador	1988	1	1,985	1,985			Onshore	1	1
Trinidad &
Tobago	1970	1	382	66			Offshore	7
United
States	1968	442	1,721	853	7,261	4,270	Onshore/Offshore	58	15
Venezuela	1998	6	378	98	2,049	816	Onshore/Offshore	1	3
Other
countries		8			5,547	1,326	Offshore		1
AUSTRALIA AND OCEANIA		16	1,980	1,045	49,304	24,640		4	2
Australia	2001	15	1,980	1,045	48,540	24,602	Offshore	4	2
Other countries		1			764	38	Offshore
Total		1,106	109,915	41,373	390,629	213,048		525	290

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.

40 -

Contents

Eni Fact Book Exploration & Production

Capital expenditure (euro million) 2007 2008 2009 2010 2011

| Acquisition of proved and
unproved properties | 96 | 836 | 697 | | 754 |
| --- | --- | --- | --- | --- | --- |
| North
Africa | 11 | 626 | 351 | | 57 |
| Sub-Saharan Africa | | 210 | 73 | | 697 |
| Rest
of Asia | | | 94 | | |
| America | 85 | | 179 | | |
| Exploration | 1,659 | 1,918 | 1,228 | 1,012 | 1,210 |
| Italy | 104 | 135 | 40 | 34 | 38 |
| Rest
of Europe | 195 | 227 | 113 | 114 | 100 |
| North Africa | 373 | 379 | 317 | 84 | 128 |
| Sub-Saharan
Africa | 246 | 485 | 284 | 406 | 482 |
| Kazakhstan | 36 | 16 | 20 | 6 | 6 |
| Rest
of Asia | 162 | 187 | 159 | 223 | 156 |
| America | 505 | 441 | 243 | 119 | 60 |
| Australia
and Oceania | 38 | 48 | 52 | 26 | 240 |
| Development | 4,643 | 6,429 | 7,478 | 8,578 | 7,357 |
| Italy | 461 | 570 | 689 | 630 | 720 |
| Rest of Europe | 429 | 598 | 673 | 863 | 1,596 |
| North
Africa | 948 | 1,246 | 1,381 | 2,584 | 1,380 |
| Sub-Saharan Africa | 1,343 | 1,717 | 2,105 | 1,818 | 1,521 |
| Kazakhstan | 733 | 968 | 1,083 | 1,030 | 897 |
| Rest of Asia | 238 | 355 | 406 | 311 | 361 |
| America | 345 | 655 | 706 | 1,187 | 831 |
| Australia and
Oceania | 146 | 320 | 435 | 155 | 51 |
| Other expenditure | 82 | 98 | 83 | 100 | 114 |
| | 6,480 | 9,281 | 9,486 | 9,690 | 9,435 |

i i i

Reserve life index (a) (years) 2007 2008 2009 2010 2011

Italy	9.7	9.3	11.4	10.9	10.4
Rest of
Europe	6.5	5.8	6.6	7.4	8.0
North Africa	8.8	8.2	9.3	9.6	12.8
Sub-Saharan
Africa	9.2	9.5	8.9	7.9	8.2
Kazakhstan	26.0	32.9	29.0	28.7	24.5
Rest of
Asia	13.2	12.8	11.1	12.8	21.7
America	8.1	5.9	5.0	7.2	13.6
Australia
and Oceania	19.7	21.0	21.5	13.1	12.8
	10.0	10.0	10.2	10.3	12.3

i i i

Reserve replacement ratio, all sources (a) (%) 2007 2008 2009 2010 (b) 2011

Italy	25	10	136	107	75
Rest of
Europe	30	-	174	102	136
North Africa	36	118	99	167	58
Sub-Saharan
Africa	76	142	106	90	58
Kazakhstan	-	776	-	-	-
Rest of
Asia	791	248	-	212	771
America	474	40	144	273	647
Australia
and Oceania	-	75	112	5	163
	90	135	96	125	142

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

41 -

Contents

Eni Fact Book Exploration & Production

Exploratory wells activity

Net wells completed Wells in progress at Dec. 31 (a)

2009 2010 2011 2011

(units) Productive Dry (b) Productive Dry (b) Productive Dry (b) Gross Net

| Italy — Rest of
Europe | 4.1 | 1.0 — 0.2 | 1.7 | 0.5 — 1.1 | 0.3 | 0.7 | 6.0 — 21.0 | 4.4 — 6.5 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| North Africa | 4.8 | 3.8 | 9.3 | 8.1 | 6.2 | 3.4 | 21.0 | 15.7 |
| Sub-Saharan
Africa | | 2.7 | 2.3 | 4.7 | 0.6 | 2.6 | 63.0 | 18.6 |
| Kazakhstan | | | | | | | 13.0 | 2.3 |
| Rest of
Asia | 2.3 | 3.9 | 1.0 | 2.8 | 0.2 | 7.6 | 16.0 | 6.9 |
| America | 1.0 | 3.8 | | 6.3 | 2.5 | | 11.0 | 3.3 |
| Australia
and Oceania | 0.8 | 1.4 | 1.0 | 0.4 | | 1.4 | | |
| | 13.0 | 16.8 | 15.3 | 23.9 | 9.8 | 15.7 | 151.0 | 57.7 |

Development wells activity

Net wells completed Wells in progress at Dec. 31

2009 2010 2011 2011

(units) Productive Dry (b) Productive Dry (b) Productive Dry (b) Gross Net

Italy	18.3		23.9	1.0	25.3		3.0	2.0
Rest of
Europe	12.5		2.9	0.2	3.3	0.3	18.0	3.9
North Africa	40.7	0.4	44.3	0.3	55.9	1.1	27.0	12.5
Sub-Saharan
Africa	35.8	1.9	28.0	2.5	28.2	1.0	28.0	6.6
Kazakhstan	3.8		1.8		1.3		13.0	2.2
Rest of
Asia	38.6	4.3	41.7	1.8	39.2	2.5	12.0	5.4
America	15.6	1.0	27.6	0.5	27.6		17.0	6.9
Australia
and Oceania	2.2		1.5		0.4
	167.5	7.6	171.7	6.3	181.2	4.9	118.0	39.5

i i i

Productive oil and gas wells at Dec. 31, 2011 (c)

2011

Oil wells Natural gas wells

(units) Gross Net Gross Net

Italy	237.0	191.5	630.0	546.5
Rest of
Europe	414.0	63.3	207.0	93.1
North Africa	1,357.0	651.8	144.0	56.0
Sub-Saharan
Africa	2,952.0	562.6	479.0	32.1
Kazakhstan	89.0	28.9
Rest of
Asia	602.0	381.5	849.0	328.7
America	152.0	79.8	344.0	113.2
Australia
and Oceania	7.0	3.8	14.0	3.3
	5,810.0	1,963.2	2,667.0	1,172.9

i	i	i
(a)	i	Includes
temporary suspended wells pending further evaluation.
(b)	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.
(c)		Includes
2,304 gross (741.7 net) multiple completion wells (more
than one producing into the same well bore). Productive
wells are producing wells and wells capable of
production. One or more completions in the same bore hole
are counted as one well.

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2007 2008 2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 7.37 | 5.30 | 3.85 | 3.74 | 2.33 | |
| --- | --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 16.34 | 12.24 | 9.48 | 8.24 | 8.38 | |
| Net sales from operations (a) | (euro million) | 27,793 | 37,062 | 30,447 | 29,576 | 34,731 | |
| Operating
profit | | 4,465 | 4,030 | 3,687 | 2,896 | 1,758 | |
| Adjusted operating profit | | 4,414 | 3,564 | 3,901 | 3,119 | 1,946 | |
| Marketing | | 2,284 | 1,309 | 1,721 | 733 | (550 | ) |
| Regulated
businesses in Italy | | 1,685 | 1,732 | 1,796 | 2,043 | 2,112 | |
| International
transport | | 445 | 523 | 384 | 343 | 384 | |
| Adjusted net profit | | 3,127 | 2,648 | 2,916 | 2,558 | 1,541 | |
| EBITDA
pro-forma adjusted | | 5,029 | 4,310 | 4,403 | 3,853 | 2,565 | |
| Marketing | | 3,061 | 2,271 | 2,392 | 1,670 | 364 | |
| Regulated
businesses in Italy | | 1,248 | 1,284 | 1,345 | 1,486 | 1,535 | |
| International
transport | | 720 | 755 | 666 | 697 | 666 | |
| Capital
expenditure | | 1,511 | 2,058 | 1,686 | 1,685 | 1,721 | |
| Adjusted capital employed, net at year end | | 21,364 | 22,273 | 25,024 | 27,270 | 27,660 | |
| Adjusted
ROACE | (%) | 15.2 | 12.2 | 12.3 | 9.8 | 5.6 | |
| Worldwide gas sales (b) | (bcm) | 98.96 | 104.23 | 103.72 | 97.06 | 96.76 | |
| LNG sales (c) | | 11.7 | 12.0 | 12.9 | 15.0 | 15.7 | |
| Customers in Italy | (million) | 6.61 | 6.63 | 6.88 | 6.88 | 7.10 | |
| Gas
volumes transported in Italy | (bcm) | 83.28 | 85.64 | 76.90 | 83.31 | 78.30 | |
| Electricity sold | (TWh) | 33.19 | 29.93 | 33.96 | 39.54 | 40.28 | |
| Employees
at year end | (units) | 11,893 | 11,692 | 11,404 | 11,245 | 10,907 | |
| Direct GHG emissions | (mmtonnes CO 2 eq) | 15.58 | 14.60 | 14.60 | 15.79 | 14.75 | |
| Customer
satisfaction index (PSC) | (%) | n.a. | 75.3 | 83.7 | 87.4 | 91.0 | |
| Water consumption/withdrawals per kWheq produced
(EniPower) | (cm/kWheq) | 0.015 | 0.015 | 0.015 | 0.013 | 0.014 | |

i	i	i
(a)	i	Before
elimination of intragroup sales.
(b)	i	Include
volumes marketed by the Exploration & Production
Division of 2.86 bcm (5.39, 6.00, 6.17 and 5.65 bcm in
2007, 2008, 2009 and 2010, respectively).
(c)	i	Refer to LNG
sales of the G&P Division (included in worldwide gas
sales) and the E&P Division.

Performance of the year Agreement with Gazprom I In March 2012, within their strategic partnership Eni and Gazprom signed an agreement on the revision of long-term natural gas supply contracts from Russia to Italy with retroactive effect from January 2011. The parties also discussed the execution of a detailed plan for the commencement of construction of the South Stream gas pipeline with the Final Investment Decision (FID) to be taken by November 2012. Divestment of international pipelines I In 2011, Eni finalized the divestment of its interests in importing pipelines of natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) as part of the agreements signed on September 29, 2010 with the European Commission. Total consideration amounted to approximately euro 1.5 billion. Enis ship-or-pay contracts will be unaffected. Belgium I In January 2012, Eni finalized the acquisition of Nuon Belgium NV and Nuon Power Generation Wallon NV, companies marketing gas and electricity mainly to residential and professional customers in Belgium, for an outlay of euro 214 million. Divestment of interest in Interconnector I On February 22, 2012, Snam and Fluxys G signed a preliminary agreement to purchase Enis 16.41% interest in Interconnector (UK) Limited, its 51% interest in Interconnector Zeebrugge Terminal SCRL and its 10% interest in Huberator SA for a total consideration of euro 150 million. These companies own and operate the subsea gas pipeline that provides a bi-directional link between the UK (Bacton) and Belgium (Zeebrugge) hubs. IZT and Huberator are Belgian companies: IZT owns the Belgian compressor terminal at the Interconnector in Zeebrugge, and Huberator offers trading-related services in the Zeebrugge Gas Hub. The completion of the transaction is subject to certain conditions precedent and is expected to occur by the second half of 2012. I The injury frequency rate continued to improve (down 38% from 2010) thanks to enhanced training, information and sensitization of workers. I With regard to sales to residentials in Italy, Enis customers satisfaction score (checked twice a year by the Authority for electricity and gas) increased to 91.0 (basis 100) in the first half of 2011 from an average 89.8 registered by the reference utility panel. I In 2011, adjusted net profit was euro 1,541 million, down 39.8% from 2010 due to a sharply lower operating performance of the Marketing business negatively impacted by weak demand and mounting competitive pressures fuelled by oversupply which squeezed selling margins and reduced volumes opportunities. The performance was also impacted by the disruption in Libyan gas availability, as well as by the unfavorable trends in energy parameters and unusual winter weather. Furthermore, the results reflected only a part of the benefits associated with the renegotiations of the supply contracts, certain of which have been finalized after 2011 year-end. These lower results were partly offset by the positive operating performance delivered by the International transport and Regulated businesses in Italy. I Adjusted ROACE was 5.6% (9.8% in 2010).

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I Worldwide gas sales were basically stable at 96.76 bcm supported by commercial initiatives, despite lower consumption and competitive pressure. We grew in many European Countries and in international LNG sales, while offtakes from importers into Italy of Libyan gas fell sharply and sales fell in Belgium. I Electricity sales of 40.28 TWh increased by 0.74 TWh from 2010, up 1.9%. I Natural gas volumes transported in Italy were 78.30 bcm, a decline of 6% from 2010 due to a steep decline in gas demand in Italy. I Capital expenditure amounted to euro 1,721 million for the development and upkeep of transport and distribution networks in Italy, increasing storage capacity and upgrading and improvement of efficiency standards in power generation. I In 2011, total R&D expenditure amounted to euro 2 million, net of overhead costs.

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Enis Gas & Power segment engages in all phases of the natural gas value chain: supply, trading and marketing of natural gas and electricity, gas infrastructures, and LNG supply and marketing. This segment also includes power generation activity, ancillary to the marketing of electricity. Enis leading position in the European gas market is ensured by a set of competitive advantages, including our multi-Country approach, long-term gas availability, access to infrastructures, market knowledge and a strong customer base. Furthermore, integration with our upstream operations provides valuable growth options whereby the Company targets to monetize its large gas reserves. 1. Marketing 1.1 Natural gas Supply The supply of natural gas is a free activity where prices are determined by free negotiations of demand and supply involving natural gas resellers and producers. In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets. These contracts have been ensuring approximately 80 bcm of gas availability from 2010 (including the Distrigas portfolio of supplies and excluding Enis other subsidiaries and affiliates) with a residual life of approximately 17 years and a pricing mechanism that indexed the cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.). Further competitive advantages are represented by the availability of natural gas deriving from equity production, the access to all phases of the LNG chain (liquefaction, shipping and regasification) and to other gas infrastructures, and by trading and risk management activity. Enis long-term gas requirements are met by natural gas from a total of 12 Countries, where Eni also holds upstream activities and by access to European spot markets. In 2011, Enis consolidated subsidiaries supplied 83.38 bcm of natural gas, representing an increase of 0.89 bcm, or 1.1% from 2010. In 2011, main gas volumes from equity production derived from: (i) Italian gas fields (6.7 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.4 bcm); (iii) the United States (2.2 bcm); and (iv) other European areas (Croatia with 0.3 bcm). Supplies from equity production fell sharply at the Wafa and Bahr Essalam fields (to 0.6 bcm) in Libya due to the conflict in the Country; in 2010 these two fields supplied 2.5 bcm net to Eni. Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 18 bcm representing 18% of total volumes available for sale. Marketing in Italy Eni operates in a liberalized market where energy customers are allowed to choose the supplier of gas and, according to their specific needs, to evaluate the quality of services and offers. With regard to the retail market in Italy, the Authority for Electricity and Gas regulates and defines the tariff system for those customers who have not chosen their supplier on the free market, mainly residentials and small enterprises. The Italian market includes four segments of customers: large businesses, the power generation sector, wholesalers and residential customers. Large businesses and power generation utilities are directly linked to the regional natural gas network. Wholesalers mainly include local selling companies that resell natural gas to residential customers through low pressure distribution networks. Residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and small businesses (also referred to as the middle market) located in large metropolitan areas and urban centers. Overall, Eni supplies approximately

Sales and market shares on the Italian gas market (bcm) 2010 2011

Volumes sold Market share (%) Volumes sold Market share (%) % Ch. 2011 vs 2010

Italy to third parties	28.10	33.8	28.47	36.6	1.3
Wholesalers	4.84		5.16		6.6
Gas release	0.68
Italian
gas exchange and spot markets	4.65		5.24		12.7
Industries	6.41		7.21		12.5
Medium-sized
enterprises and services	1.09		0.88		(19.3	)
Power generation	4.04		4.31		6.7
Residential	6.39		5.67		(11.3	)
Own consumption	6.19		6.21		0.3
TOTAL SALES IN ITALY	34.29	41.3	34.68	44.6	1.1
Gas demand (a)	83.10		77.84		(6.3	)

i	i	i
(a)	i	Source:
Italian Ministry of Economic Development.

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3,000 clients including large businesses, power generation utilities, wholesalers and distributors of natural gas for automotive use. Residential users are 7.10 million and include households, professionals, small and medium sized enterprises, and public bodies located all over Italy. In 2011, sales of natural gas were 96.76 bcm, down 0.30 bcm, or 0.3%. Despite a 6% decline in natural gas demand, sales volumes on the Italian market were substantially stable, to 34.68 bcm (up 0.39 bcm, or 1.1%) due to the positive effect of market initiatives that led to higher sales to industrial customers (up 0.80 bcm), wholesalers (up 0.32 bcm) and to the power generation segment (up 0.27 bcm). Sales on the Italian exchange for gas and spot markets increased by 0.59 bcm. Lower sales volumes to the residential segment (down 0.72 bcm) reflected the impact of unusual weather conditions on seasonal sales and competitive pressures.

Gas sales by market (bcm) 2007 2008 2009 2010 2011

ITALY	56.13	52.87	40.04	34.29	34.68
Wholesalers	10.01	7.52	5.92	4.84	5.16
Gas release	2.37	3.28	1.30	0.68
Italian
gas exchange and spot markets	1.90	1.89	2.37	4.65	5.24
Industries	11.77	9.59	7.58	6.41	7.21
Medium-sized
enterprises and services	1.00	1.05	1.08	1.09	0.88
Power generation	17.21	17.69	9.68	4.04	4.31
Residential	5.79	6.22	6.30	6.39	5.67
Own consumption	6.08	5.63	5.81	6.19	6.21
INTERNATIONAL SALES	42.83	51.36	63.68	62.77	62.08
Rest of Europe	35.02	43.03	55.45	54.52	52.98
Importers
in Italy	10.67	11.25	10.48	8.44	3.24
European markets	24.35	31.78	44.97	46.08	49.74
Iberian
Peninsula	6.91	7.44	6.81	7.11	7.48
Germany/Austria	5.03	5.29	5.36	5.67	6.47
Benelux		4.77	15.72	14.87	11.95
Hungary	2.74	2.82	2.58	2.36	2.24
UK/Northern
Europe	3.15	3.21	4.31	5.22	6.10
Turkey	4.62	4.93	4.79	3.95	6.86
France	1.62	2.66	4.91	6.09	7.01
Other	0.28	0.66	0.49	0.81	1.63
Extra European markets	2.42	2.33	2.06	2.60	6.24
E&P in Europe and in the
Gulf of Mexico	5.39	6.00	6.17	5.65	2.86
WORLDWIDE GAS SALES	98.96	104.23	103.72	97.06	96.76

Marketing in the rest of Europe Despite a challenging market scenario and rising competitive pressure, Eni intends to organically grow in particular in certain European key market such as France, Germany/Austria and Benelux, leveraging on our competitive cost-position, our multi-Country approach and on a pan-European commercial platform.

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In 2011, sales on target markets in Europe of 49.74 bcm showed a positive trend, increasing by 7.9%, except for Benelux where competitive pressure, in particular in the wholesalers segment, reduced Enis sale portfolio. The main increases were recorded in Turkey, due to increased off-takes by Bota, France also due to the consolidation of Altergaz, UK/Northern Europe, Germany/Austria and the Iberian Peninsula. A review of Enis presence in key European markets is presented below.

Benelux Eni holds a key position in the Benelux Countries (Belgium, the Netherlands and Luxembourg), in particular in Belgium, which are a strategic hub of the continental gas spot market in Western Europe, thanks to their central position and high level of interconnectivity with the gas transit networks of Central and Northern Europe. In 2011, sales in Benelux were mainly directed to industrial companies, wholesalers and power generation and amounted to 11.95 bcm (14.87 bcm in 2010), down by 2.92 bcm, or 19.6%, due to rising competitive pressure, in particular in the wholesalers segment. In January 2012, in order to consolidate its position in Belgium, Eni finalized the acquisition of Nuon Belgium NV and Nuon Power Generation Wallon NV, two companies engaged respectively in marketing gas and electricity mainly to residential and professional customers in the Country, and in managing a project aimed to build a CCGT power plant at Seneffe in Belgium. France Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the retail and middle market segments. Eni is present in the French market through its direct commercial activities and through its subsidiary Altergaz (Enis interest being 98.09% as of December 31, 2011). Furthermore, Eni holds a 34% interest in Gaz de Bordeaux SAS (with a 17% direct interest and a further 17% held by Altergaz) which is engaged in selling natural gas in the municipality of Bordeaux. In 2011, sales in France amounted to 7.01 bcm (6.09 bcm in 2010), an increase of 0.92 bcm, or 15.1%, from a year ago. Germany/Austria Eni is present in the German natural gas market through its associate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.68 bcm in 2011 (2.34 bcm net to Eni), and through a direct marketing structure which sold in 2011 approximately 3.23 bcm in Germany and 1.34 bcm in Austria. In 2011, sales in Germany/Austria market amounted to 6.47 bcm, an increase of 0.80 bcm, or 14.1%, from a year ago. Iberian Peninsula In 2011, total sales in the Iberian Peninsula amounted to 7.48 bcm, an increase of 0.37 bcm, or 5.2%, from a year ago. Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Enis interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2011, UFG gas sales in Europe amounted to 4.88 bcm (2.44 bcm Enis share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2011, Eni sales in Spain amounted to 5.79 bcm representing a slight increase from a year ago. Portugal . Eni operates on the Portuguese market through its affiliate Galp Energia (Enis interest 33.34%) which sold approximately 5.49 bcm in 2011 (1.83 bcm net to Eni). Turkey Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2011, sales amounted to 6.86 bcm, an increase of 2.91 bcm, or 73.7% from a year ago. UK/Northern Europe Eni through its subsidiary Eni UK Ltd markets in the UK the equity gas produced at Enis fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2011, sales amounted to 6.10 bcm, an increase of 16.9% from a year ago.

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Deborah Gas Storage Project in the Hewett area, UK Eni has progressed in developing the Gas Storage Project on the Deborah field in the Hewett area located in the Southern Gas Basin in the North Sea, near the Bacton terminal. The Deborah Gas Storage Project is designed to provide the UK and North Western Europe markets with 4.6 bcm of working gas. Over the last two years significant progress has been made by completing the Front End Engineering Design ("FEED"), obtaining most of the necessary approvals including the agreement with The Crown Estate, the Gas Storage License from the Department of Energy and Climate Change ("DECC") and relevant permits from the North Norfolk District Counsel on the Bacton terminal. In addition, the UK government has recently designated as strategic for the Country the need to develop storage infrastructures, also to support the development of power generation from renewable sources, which need an adequate production back-up from combined cycle plants in order to mitigate the risk associated to consumption peaks and the related price increases. Eni believes that recent positions taken by the UK authorities are very important and encouraging for the Deborah storage project. Thus, Eni together with other gas storage developers has started contacts with UK authorities to investigate any capacity mechanism that can reduce any possible risk associated to gas storage projects in the UK. FID on the project will depend on the outcome of said contacts with the UK governmental authorities and potential co-investors. 1.2 LNG Eni is present in all phases of the LNG business: liquefaction, shipping, re-gasification and sale through operated activities or interests in joint ventures and associates. Enis presence in the business is tied to the Companys plans to develop its large gas reserve base in Africa and elsewhere in the world. The LNG business has been deeply impacted by the economic downturn and oversupply affecting the European gas market, as well as by structural modifications in the US market where large availability of gas from unconventional sources have reduced the Countrys dependence on gas imports via LNG. Enis main assets and projects in the LNG business are described below. Egypt Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant with a capacity of approximately 5 mmtonnes/y of LNG which equates to a feedstock of 7.56 bcm/y of natural gas out of which the Gas & Power segment interest is up to 2.2 bcm/y to be marketed in Europe. Spain Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto re-gasification plant, near Valencia, with a capacity of 8.8 bcm/y and a LNG storage capacity of 450,000 cm which will be increased to 600,000 cm after the ongoing construction of a fourth tank. At present, Enis re-gasification capacity entitlement amounts to 1.9 bcm/y of gas. Eni through Unión Fenosa Gas also holds a 9.45% interest in the El Ferrol re-gasification plant, located in Galicia, with a treatment capacity of approximately 3.6 bcm/y, of which 0.34 bcm/y being Enis capacity entitlements. The LNG storage capacity of the plant is 300,000 cm in two tanks. United States Cameron . The Cameron LNG terminal is situated 18 miles from the Gulf of Mexico along the Calcasieu Channel in Hackberry, Louisiana. The facility where Eni owns a capacity entitlement to treat LNG commenced operations in the third quarter of 2009. In consideration of a changed demand outlook, on March 1, 2010, Eni renegotiated certain terms of the contract with US company Cameron LNG, relating to the farming out of a share of re-gasification capacity of the Cameron terminal. The new agreement provides that Eni will be entitled to a daily send-out of 572,000 mmbtu (approximately 5.7 bcm/y) and a dedicated storage capacity of 160 kcm, giving Eni more flexibility in managing seasonal swings in gas demand. Furthermore, keeping account of the current oversupply of the US gas market, the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant has been rescheduled with start-up in 2017. Pascagoula. This project is part of an upstream development project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 bcm/y) destined to the North American market in order to monetize part of the Companys gas reserves. As part of the downstream leg of the project, Eni signed a 20-year contract with Gulf LNG to buy 5.8 bcm/y of the re-gasification capacity of the plant near Pascagoula in Mississippi. The start-up of the re-gasification facility commenced in the fourth quarter of 2011, while the upstream project in Angola has yet to be started up. At the same time Eni USA Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 bcm/y of re-gasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG. Qatar Through its subsidiary Distrigas, Eni increased its development opportunities in the LNG business with access to new supply sources mainly from Qatar, under a 20-year agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and the Zeebrugge LNG terminal on the western coast of Belgium. 1.3 Power generation Enis power generation activity is conducted in the Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in Bolgiano plants, as well as in certain photovoltaic sites in Italy. In 2011, power production was 25.23 TWh, down 0.40 TWh, or 1.6% from 2010, mainly due to lower production at the Brindisi plant, partly offset by increases at the Ravenna and Ferrara plants. As of December 31, 2011, installed operational capacity was 5.3 GW 1 (5.3 GW in 2010). Power availability in 2011 was supported by growth in electricity trading activities (up 1.14 TWh, or 8.2%) due to higher volumes traded on the Italian power exchange benefiting from lower purchase prices. The power generation development plan mainly refers to the revamping of the Bolgiano plant (Eni 100%), the upgrading of the Taranto plant (Eni 100%), as well as the construction of a bio-mass power plant within the project for the remediation of the Porto Torres site. Development activities are currently underway also at the Ferrara plant (Eni 100%).

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

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International transport and Regulated businesses in Italy Eni has transport rights on a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (Russia, Algeria, Libya and the North Sea). In Italy, Eni operates the major part of the national transport network, a number of gas underground storage deposits and related facilities, a re-gasification plant in Panigaglia and can rely on an extended system of local distribution networks. 2.1 International transportation Eni owns capacity entitlements in an extensive network of international high pressure pipelines enabling the Company to import to Italy natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya. The Company participates to both entities which operate the pipelines and entities which manage transport rights. The structure of the Companys interests in these entities has significantly changed in 2011 following the divestment of Enis interests in importing pipelines of natural gas from Northern Europe (TENP and Transitgas) and Russia (TAG) and related carrier companies, as part of the agreements signed on September 29, 2010 with the European Commission to settle an antitrust proceeding related to alleged anti-competitive behavior in the natural gas market. The divestments will not affect Enis contractual gas transport rights. A description of the main international pipelines currently participated or operated by Eni is provided below: - the TTPC pipeline , 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia, from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. The pipeline was recently upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 bcm/y. The upgrade was finalized in 2008 and became fully-operational during 2009; - the TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system; - the GreenStream pipeline , jointly-owned with the Libyan National Oil Company, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y (expandable to 11 bcm/y) and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. From February 22, 2011 to October 2011, in consideration of the crisis in Libya, supplies of
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natural gas through the GreenStream pipeline have been suspended. Operations restarted late in October 2011; - Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 bcm/y. 2.2 The South Stream project In September 2011, Eni and Gazprom within their strategic partnership signed a series of agreements in areas of common interest including the development of the South Stream project through the definition of terms for the participation to the project of gas operators Wintershall and EDF, each with a 15% stake. Gazprom and Eni hold 50% and 20% interests, respectively. In March 2012, terms for the commencement of construction of the gas pipeline were also agreed with the Final Investment Decision (FID) expected by November 2012. 2.3 Regulated businesses in Italy Reorganization of regulated businesses in Italy Implementing the so-called Third Energy Package, on December 5, 2011 with effect from January 1, 2012, "Snam Rete Gas SpA" changed its company name in "Snam SpA". At the same date Snam SpA transferred the "transportation, dispatch, remote control and metering of natural gas" business unit to a new company that from January 1, 2012, took the name of Snam Rete Gas SpA. The reorganization of Regulated businesses in Italy based on Snam SpA as holding the 100% interest in the four companies operating the transport, re-gasification, storage and distribution of natural gas, intends to build an organizational model meeting the new legal provisions on the unbundling of transport activities as provided by Italian laws implementing European Directive No. 2009/73/EC. Infrastructure Eni, through Snam (Enis interest being 52.53%), which is listed on the Italian Stock Exchange, operates most of the Italian natural gas transport network, a re-gasification terminal located in Panigaglia, an extensive local distribution network and gas underground storage deposits and related facilities.

Major pricing elements for regulated activities

	TRANSPORTATION	REGASIFICATION	STORAGE
End of regulatory period	- December
31, 2013	- September 30, 2012	- December
31, 2014	- December 31, 2012
Calculation of net invested
capital recognized for regulatory purposes (RAB)	- Revalued
historical cost	- Revalued historical cost	- Revalued
historical cost - Deduction of restoration costs recognized	- Revalued historical cost - Parametric method for centralized assets
Return on net invested
capital recognized for regulatory purposes (pre-tax WACC)	- 6.4%
(transportation) - 6.9% (metering)	- 7.6%	- 6.7%	- 7.6% (transportation) - 8% (metering)
Incentives on new investments	- 1% over 5
years (on safety investments) - 2% over 7/10 years (on capacity upgrade investments) - 3% over 10/15 years (on entry capacity upgrade
investments)	- 2% over 8 years (on expanding of existing
terminals by less than 30%) - 3% over 16 years (on expanding of existing terminals by more than 30%)	- 4% over 8
years (on upgrading of existing capacity) - 4% over 16 years (on developing new storage fields)	- 2% over 8 years (on replacing cast-iron pipes
and renovating odorization systems)
Efficiency factor (X FACTOR)	- 2.1% on
operating costs	- 0.5% on operating costs	- 0.6% on
operating costs	- 3.2% on distribution operating costs - 3.6% on metering operating costs
Gas demand	- 15% of
revenues exposed to change in demand	- 10% of revenues exposed to change in demand	- No exposure
to change in demand	- No exposure to change in demand

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Italian transport activity In light of their nature of public services, transport and re-gasification activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This makes transport a low risk business capable of delivering stable returns. Snam Rete Gas (Snam 100%) is the main operator of natural gas transport in Italy with 32,010 kilometers of high and low pressure pipelines. Enis network comprises: - a national transport network extending 9,080 kilometers, made up of high pressure trunk-lines mainly with a large diameter, which carry natural gas from the entry points to the system import lines, storage sites and main Italian natural gas fields to the linking points with regional transport networks. Gaslines can be laid underground, with maximum diameter of 1,400 mm carrying gas at a pressure between 24 and 75 bar, or underwater crossing the Messina Strait, with diameter between 500 and 650 mm and pressure up to 115 bar. Natural gas coming from outside Italy is input in the national grid at 7 entry points, corresponding to the interconnections with import pipelines (Tarvisio, Gorizia, Gries Pass, Mazara del Vallo, Gela) and LNG regasification terminals (Panigaglia and Cavarzere). Storage fields are connected to the transport network at 2 virtual entry/exit points to the storage hubs. Natural gas leaving the national grid is carried on the regional network to the delivery points where it is offtaken by customers; and - a regional transport network extending over 22,930 kilometers, made up of smaller lines, generally operated to a lower pressure, and allowing the transport of natural gas to large industrial complexes, power stations and local distribution companies in the various local areas served. The major pipelines interconnected with import trunk-lines that are part of Enis national network are: for natural gas imported from Algeria (Mazara del Vallo delivery point): - two lines with a 48/42-inch diameter, each approximately 1,500-kilometer long, including the smaller pipes that cross underwater the Messina Strait, connect Mazara del Vallo on the southern coast of Sicily where they link with the TMPC pipeline carrying Algerian gas, to Minerbio (near Bologna). This pipeline is undergoing upgrades with the laying of a third line with a 48-inch diameter and 583-kilometer long (of these 525 kilometers are already operation). At the Mazara del Vallo entry point the available transport capacity, which is measured at the beginning of each thermal year starting on October 1, is approximately 105 mmcm/d; for natural gas imported from Libya (Gela delivery point): - a 36-inch diameter line and 67-kilometer long linking Gela, the entry point of the GreenStream underwater pipeline, to the national network near Enna along the trunk-line transporting gas coming from Algeria. Transport capacity at the Gela entry point is approximately 38 mmcm/d; for natural gas imported from Russia (Tarvisio and Gorizia delivery points): - two lines with 42/36/34-inch diameters extending for a total length of approximately 900 kilometers connecting the Austrian network at Tarvisio. This facility crosses the Po Valley reaching Sergnano (near Cremona) and Minerbio (near Bologna). This pipeline has been upgraded by the laying of a third 264-kilometer long line with a diameter from 48 to 56 inches. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 119 mmcm/d plus the transport capacity available at the Gorizia entry point of approximately 5 mmcm/d; for natural gas imported from the Netherlands and Norway (Gries Pass delivery point): - one line, with a 48-inch diameter and 177-kilometer long that extends from the Italian border at Gries Pass (Verbania), to the node of Mortara, in the Po Valley. The pipeline transport capacity at the Gries Pass entry point amounts to 64 mmcm/d; for natural gas coming from the Panigaglia LNG terminal: - one line, with a 30-inch diameter and 170-kilometer long that links

Transport capacity in Italy (mmcm/d) 2010-2011 Thermal year 2011-2012 Thermal year

Entry points Available capacity Awarded capacity Saturation (%) Available capacity Awarded capacity Saturation (%)

Tarvisio	119.2	110.3	92.5	118.8	109.9	92.5
Mazara del
Vallo	105.0	98.9	94.2	105.0	88.2	84.0
Gries Pass	64.8	55.0	84.9	64.4	61.7	95.8
Gela	35.2	34.3	97.4	37.6	21.9	58.2
Cavarzere (LNG)	26.4	24.6	93.2	26.4	24.6	93.2
Panigaglia
(LNG)	13.0	7.2	55.4	13.0	11.4	87.7
Gorizia	4.8	0.5	10.4	4.8	0.6	12.5
	368.4	330.8	89.8	370.0	318.3	86.0

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the Panigaglia terminal to the national transport network near Parma. The pipeline transport capacity at the Panigaglia entry point amounts to 13 mmcm/d; and for natural gas coming from the Rovigo Adriatic LNG terminal: - a 36-inch diameter connection at the Minerbio junction with the Cavarzere-Minerbio pipeline belonging to Edison Stoccaggio SpA, which receives gas from the LNG terminal located offshore of Porto Viro. The pipeline transport capacity at the Cavarzere entry point amounts to 26 mmcm/d. Enis transport system also includes: (i) eleven compressor stations with a total power of 883.7 MW used to increase gas pressure in pipelines to the level required for its flow; and (ii) four marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo and Messina in Sicily and Favazzina and Palmi in Calabria. The interconnections managed by Snam Rete Gas in the Italian transport network are guaranteed by 22 linkage and dispatching nodes and by 568 plant units including pressure reduction and regulation plants. These plants allow the regulation of the flow of natural gas in the network and guarantee the connection of pipes working at different pressures. Snam Rete Gas also provides dispatching services through a central operating plant that monitors and controls the operations of the transport network, receiving data from approximately 3,000 plants, of which over 1,500 are remotely controlled and are located all over Italy. In 2011, volumes of natural gas input in the national grid (78.30 bcm) decreasing by 5.01 bcm from 2010 due to declining domestic demand. Eni transported 43.18 bcm of natural gas on behalf of third parties, down 4.68 bcm from 2010, or 9.8%. Eni, through its subsidiary GNL Italia, operates the regasification terminal of Panigaglia (La Spezia, Liguria). At full capacity, this terminal can regasify 17,500 cm of LNG per day and input 3.5 bcm/y into the Italian transport network. In 2011, the LNG terminal in Panigaglia re-gasified 1.89 bcm of natural gas (1.98 bcm in 2010). Distribution Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. The Companys subsidiary Italgas and other subsidiaries operate in the distribution activity in Italy serving 1,330 municipalities through a low pressure network consisting of approximately 50,300 kilometers of pipelines supplying 5.9 million customers and distributing 7.64 bcm in 2011. Distribution activities are considered a public service and therefore are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. In accordance with the provisions of the relevant legislation, tenders for new natural gas distribution concessions will no longer be issued by each municipality but exclusively by the multi-municipality minimum geographical areas (known as "Ambiti Territoriali Minimi - ATEM", or local areas). Storage Eni through Stoccaggi Gas Italia SpA, operates in natural gas storage in Italy. Storage services are provided through 8 operating concessions, 4 of which are located in Lombardia (Brugherio, Ripalta, Sergnano e Settala), 3 in Emilia Romagna (Cortemaggiore, Minerbio e Sabbioncello) and 1 in Abruzzo (Fiume Treste). These storage sites are depleted gas fields and have been converted to storage by means of proper infrastructure and facilities that link them to the national grid. In particular, the storage system is managed in order to allow the optimal injection of gas and its supply in respect of technical and management constraints. Storage services are provided by means of: - storage fields; - wells; - linkage facilities; - compression stations; - treatment plants. Storage fields contain cushion gas and working gas. Cushion gas is the amount of gas necessary for the fields operation and is the minimum indispensable volume present or injected in the field at the beginning of storage, that needs to be always present in the field. Working gas is the volume of gas produced and injected cyclically during the year. Storage activity consists of two separate phases: - injection of gas underground; - offtake of previously injected gas. Injection of gas in the fields, through storage wells, usually taking place between April and October, is achieved through compression plants that increase the pressure of gas taken from the national distribution network. Gas offtake, usually taking place between November and the following March, is achieved through treatment plants required to bring gas back to the marketing specifications. In 2011, 7.78 bcm (down 0.22 bcm from 2010) were input to the Companys storage deposits, while 7.53 bcm of gas were off-taken (slightly lower than one year ago). In 2011, storage capacity amounted to 15 bcm, of which 5 were destined to strategic storage. The share of storage capacity used by third parties was 78% (71% in 2010).

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Supply of natural gas (bcm) 2007 2008 2009 2010 2011

Italy	8.65		8.00		6.86		7.29		7.22
Outside Italy
Russia	23.44		22.91		22.02		14.29		21.00
Algeria
(including LNG)	18.41		19.22		13.82		16.23		13.94
Libya	9.24		9.87		9.14		9.36		2.32
Netherlands	7.74		9.83		11.73		10.16		11.02
Norway	5.78		6.97		12.65		11.48		12.30
United
Kingdom	3.15		3.12		3.06		4.14		3.57
Hungary	2.87		2.84		0.63		0.66		0.61
Qatar
(LNG)			0.71		2.91		2.90		2.90
Other supplies of
natural gas	2.20		4.07		4.49		4.42		6.16
Other
supplies of LNG	2.32		2.11		1.34		1.56		2.34
	75.15		81.65		81.79		75.20		76.16
Total supplies of Enis own companies	83.80		89.65		88.65		82.49		83.38
Offtake from (input to) storage	1.49		(0.08	)	1.25		(0.20	)	1.79
Network
losses, measurement differences and other changes	(0.46	)	(0.25	)	(0.30	)	(0.11	)	(0.21	)
AVAILABLE FOR SALE BY
ENI'S CONSOLIDATED SUBSIDIARIES	84.83		89.32		89.60		82.18		84.96
Available for sale of Eni's affiliates	8.74		8.91		7.95		9.23		8.94
E&P volumes	5.39		6.00		6.17		5.65		2.86
GAS VOLUMES AVAILABLE FOR SALE	98.96		104.23		103.72		97.06		96.76

Gas sales by entity (bcm) 2007 2008 2009 2010 2011

| Sales of consolidated
companies | 84.83 | 89.32 | 89.60 | 82.00 | 84.37 |
| --- | --- | --- | --- | --- | --- |
| Italy
(including own consumption) | 56.08 | 52.82 | 40.04 | 34.23 | 34.60 |
| Rest of Europe | 27.86 | 35.61 | 48.65 | 46.74 | 45.16 |
| Outside
Europe | 0.89 | 0.89 | 0.91 | 1.03 | 4.61 |
| Sales of Enis
affiliates (net to Eni) | 8.74 | 8.91 | 7.95 | 9.41 | 9.53 |
| Italy | 0.05 | 0.05 | | 0.06 | 0.08 |
| Rest of Europe | 7.16 | 7.42 | 6.80 | 7.78 | 7.82 |
| Outside
Europe | 1.53 | 1.44 | 1.15 | 1.57 | 1.63 |
| E&P in Europe and in the
Gulf of Mexico | 5.39 | 6.00 | 6.17 | 5.65 | 2.86 |
| Worldwide gas sales | 98.96 | 104.23 | 103.72 | 97.06 | 96.76 |

LNG sales (bcm) 2007 2008 2009 2010 2011

G&P sales	8.0	8.4	9.8	11.2	11.8
Italy	1.2	0.3	0.1	0.2
Rest of Europe	5.6	7.0	8.9	9.8	9.8
Extra
European markets	1.2	1.1	0.8	1.2	2.0
E&P sales	3.7	3.6	3.1	3.8	3.9
Liquefaction
plants:
Bontang (Indonesia)	0.7	0.7	0.8	0.7	0.6
Point
Fortin (Trinidad & Tobago)	0.6	0.5	0.5	0.6	0.4
Bonny (Nigeria)	2.0	2.0	1.4	2.2	2.5
Darwin
(Australia)	0.4	0.4	0.4	0.3	0.4
	11.7	12.0	12.9	15.0	15.7

Electricity sales (TWh) 2007 2008 2009 2010 2011

| Free
market | 20.73 | 22.89 | 24.74 | 27.48 | 26.87 |
| --- | --- | --- | --- | --- | --- |
| Italian Exchange for electricity | 8.66 | 3.82 | 4.70 | 7.13 | 8.67 |
| Industrial
plants | 2.81 | 2.71 | 2.92 | 3.21 | 3.23 |
| Other (a) | 0.99 | 0.51 | 1.60 | 1.72 | 1.51 |
| Power sales | 33.19 | 29.93 | 33.96 | 39.54 | 40.28 |
| Power generation | 25.49 | 23.33 | 24.09 | 25.63 | 25.23 |
| Trading of electricity (a) | 7.70 | 6.60 | 9.87 | 13.91 | 15.05 |

i	i	i
(a)	i	Include
positive and negative imbalances.

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EniPower power stations Installed capacity as of December 31, 2011 (a) Full installed capacity (2016) (b) Effective/planned start-up Tecnology Fuel

Power stations — Brindisi	(MW) — 1,321	(GW) — 1.3	2006	CCGT	gas
Ferrera Erbognone	1,030	1.0	2004	CCGT	gas/syngas
Livorno	199	0.2	2000	Power station	gas/fuel oil
Mantova	836	0.9	2005	CCGT	gas
Ravenna	972	1.0	2004	CCGT	gas
Taranto	75	0.1	2000	Power station	gas/fuel oil
Ferrara	841	0.8	2008	CCGT	gas
Bolgiano	30	0.1	2012	Power station	gas
Photovoltaic
sites	2		2011-2015	Photovoltaic	photovoltaic
Porto Torres			2016	Cogeneration power
station	biomass
	5,306	5.4

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

Power generation 2007 2008 2009 2010 2011

| Purchases — Purchases
of natural gas | (mmcm) | 4,860 | 4,530 | 4,790 | 5,154 | 5,008 |
| --- | --- | --- | --- | --- | --- | --- |
| Purchases of other fuels | (ktoe) | 720 | 560 | 569 | 547 | 528 |
| - of which
steam cracking | | 137 | 131 | 82 | 103 | 99 |
| Production | | | | | | |
| Power
generation | (TWh) | 25.49 | 23.33 | 24.09 | 25.63 | 25.23 |
| Steam | (ktonnes) | 10,849 | 10,584 | 10,048 | 10,983 | 14,401 |
| Installed generation capacity | (GW) | 4.9 | 4.9 | 5.3 | 5.3 | 5.3 |

it i i

Gas volumes transported (a) and regasified in Italy (bcm) 2007 2008 2009 2010 2011

Gas volumes transported	83.28	85.64	76.90	83.31	78.30
Gas
volumes regasified	2.38	1.52	1.32	1.98	1.89

i	i	i
(a)	i	Include
amounts destined to domestic storage.

i i i

Transport infrastructure

Route Lines (units) Length of main line (km) Diameter (inch) Transport capacity (a) (mmcm/d) Pressure min-max (bar) Compression stations (units)

ITALY — Mazara del Vallo-Minerbio (under upgrading)	2/3	1,480	48/42 - 48	105.0	75	7
Tarvisio-Sergnano-Minerbio	3	434	42/36, 34 and 48/56	118.8	58/75	3
Passo Gries-Mortara	1/2	177	48/34	64.4	55/75	1
OUTSIDE ITALY	Lines (units)	Total
length (km)	Diameter (inch)	Transport
capacity (b) (mmcm/d)	Transit capacity (c) (bcm/y)	Compression
stations (units)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370	740	48	34.0	33.2	5
TMPC (Cap
Bon-Mazara del Vallo)	5 lines of km 155	775	20/26	33.5	33.5
GreenStream (Mellitah-Gela)	1 line of km 520	520	32	8.0	8.0	1
Blue
Stream (Beregovaya-Samsun)	2 lines of km 387	774	24	16.0	16.0	1

i	i	i
(a)	i	Transport
capacity refers to the capacity at the Entry Point
connected to the import pipelines.
(b)	i	Includes both
transit capacity and volumes of natural gas destined to
local markets and withdrawn at various points along the
pipeline.
(c)		The maximum
volume of natural gas which is input at various entry
points along the pipeline and transported to the next
pipeline.

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Distribution of natural gas in Italy 2007 2008 2009 2010 2011

Volumes distributed	(bcm)	7.44	7.63	7.73	8.15	7.64
to
Eni		5.66	6.33	6.26	6.30	5.59
to third
parties		1.78	1.30	1.47	1.85	2.05
Installed
network	(km)	48,746	49,410	49,973	50,307	50,301
Active meters	(contracts)	5,598,677	5,676,105	5,770,672	5,848,478	5,896,611
Municipalities
served	(units)	1,318	1,320	1,322	1,330	1,330

Storage 2007 2008 2009 2010 2011

Total storage capacity:	(bcm)	13.6	13.7	13.9	14.2	15.0
- of
which strategic storage		5.1	5.1	5.0	5.0	5.0
- of which available storage		8.5	8.6	8.9	9.2	10.0
Available capacity:	(%)
- share utilized by Eni		44	39	30	29	22
- share
utilized by third parties		56	61	70	71	78
Total offtake from (input to)
storage:	(bcm)	9.27	11.57	16.52	15.59	15.31
- input
to storage		4.00	6.30	7.81	8.00	7.78
- offtake from storage		5.27	5.27	8.71	7.59	7.53
Total customers	(No.)	44	48	56	60	104

Capital expenditures (euro million) 2007 2008 2009 2010 2011

Italy	1,219	1,750	1,564	1,575	1,661
Outside Italy	292	308	122	110	60
	1,511	2,058	1,686	1,685	1,721
Marketing	238	198	175	248	184
Marketing	63	91	102	133	97
Italy	13	16	12	40	45
Outside Italy	50	75	90	93	52
Power
generation	175	107	73	115	87
Regulated businesses in Italy	1,031	1,627	1,479	1,420	1,529
Transport	691	1,130	919	842	898
Distribution	195	233	278	328	337
Storage	145	264	282	250	294
International transport	242	233	32	17	8
	1,511	2,058	1,686	1,685	1,721

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Eni Fact Book Refining & Marketing

2007 2008 2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 3.57 | 2.88 | | 3.18 | | 1.77 | | 2.02 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 4.31 | 3.45 | | 4.35 | | 3.59 | | 3.21 | |
| Net sales from operations (a) | (euro million) | 36,349 | 45,017 | | 31,769 | | 43,190 | | 51,219 | |
| Operating
profit | | 686 | (988 | ) | (102 | ) | 149 | | (273 | ) |
| Adjusted operating profit | | 292 | 580 | | (357 | ) | (171 | ) | (535 | ) |
| Adjusted
net profit | | 294 | 521 | | (197 | ) | (49 | ) | (262 | ) |
| Capital expenditure | | 979 | 965 | | 635 | | 711 | | 866 | |
| Adjusted
capital employed, net at year end | | 7,149 | 8,260 | | 7,560 | | 7,859 | | 8,600 | |
| Adjusted ROACE | (%) | 4.6 | 6.5 | | (2.6 | ) | (0.6 | ) | (3.1 | ) |
| Refinery
throughputs on own account | (mmtonnes) | 37.15 | 35.84 | | 34.55 | | 34.80 | | 31.96 | |
| Conversion index | (%) | 56 | 58 | | 60 | | 61 | | 61 | |
| Balanced
capacity of refineries | (kbbl/d) | 748 | 737 | | 747 | | 757 | | 767 | |
| Retail sales of petroleum products in Europe (b) | (mmtonnes) | 12.65 | 12.03 | | 12.02 | | 11.73 | | 11.37 | |
| Service
stations in Europe at year end (b) | (units) | 6,440 | 5,956 | | 5,986 | | 6,167 | | 6,287 | |
| Average throughput per service station in Europe (b) | (kliters) | 2,486 | 2,502 | | 2,477 | | 2,353 | | 2,206 | |
| Retail
efficiency index | (%) | 1.49 | 1.56 | | 1.61 | | 1.53 | | 1.50 | |
| Employees at year end | (units) | 9,428 | 8,327 | | 8,166 | | 8,022 | | 7,591 | |
| Direct GHG
emissions | (mmtonnes CO 2 eq) | 8.42 | 7.74 | | 7.29 | | 7.76 | | 7.23 | |
| SO x (sulphur oxide) emissions | (ktonnes SO 2 eq) | 26.19 | 23.18 | | 21.98 | | 28.05 | | 23.07 | |
| NO x (nitrogen oxide) emissions | (ktonnes NO 2 eq) | 7.59 | 7.38 | | 7.35 | | 7.96 | | 6.74 | |
| Water consumption rate | (cm/tonnes) | 36.25 | 36.29 | | 35.99 | | 28.36 | | 31.07 | |
| Customer
satisfaction index | (likert scale) | 8.22 | 8.14 | | 7.93 | | 7.84 | | 7.74 | |

| (a) | Before
elimination of intragroup sales. |
| --- | --- |
| (b) | 2007 data
include downstream activities in the Iberian Peninsula
divested to Galp in October 2008. |

Performance of the year I The injury frequency rate for Eni employees increased by 14% from 2010: in 2011, 26 accidents occurred. I In 2011, NO x and SO x emissions significantly declined (down 15% and down 18%, respectively) from 2010, due to the use of natural gas to replace fuel oil and to energy saving measures. I In 2011, this segment reported an adjusted net loss of euro 262 million worsening by euro 213 million from 2010, reflecting unprofitable refining margins due to rising costs for oil-based feedstock and for energy utilities linked to the former that could not be transferred to prices at the pump, also due to weak demand and excess capacity in the Mediterranean basin. Marketing results were positive but shrinking due to the decline in retail and wholesale demand for products. I Return on average capital employed on an adjusted basis was a negative 3.1% (-0.6% in 2010). I In 2011, refining throughputs were 31.96 mmtonnes (down 8.2% from 2010). In Italy, processed volumes decreased by 8.7%, reflecting the decision to cut throughputs at the Venice plant in response to an unfavorable market scenario and the impact of planned standstills at the other plants. Outside Italy, Enis refining throughputs decreased by 5.3% in particular in the Czech Republic as a consequence of the relevant planned downtime at the Litvinov refinery. I Retail sales in Italy of 8.36 mmtonnes decreased by 3.1%, driven by lower consumption of gasoil and gasoline in an unfavorable market scenario with high competitive pressure. Enis average retail market share for 2011 was 30.5%, up 0.1 percentage points from 2010. I Retail sales in the rest of Europe of 3.01 mmtonnes were down by 2.9% from 2010. Volume additions in Austria, reflecting 2010 acquisitions were offset by lower sales in Germany due to certain lease contract terminations, in France due to the rationalization of the network of service stations and in Eastern Europe due to declining demand.

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I Capital expenditure of euro 866 million related mainly to projects designed to improve the conversion capacity and flexibility of refineries, logistics, upgrade of the fuel distribution network in Italy and in the rest of Europe and initiatives in the field of health, safety and the environment. I In 2011, total expenditure in R&D in the Refining & Marketing Division amounted to approximately euro 32 million, net of general and administrative costs. In the year, 8 patent applications were filed. Activities 1. Refining Eni, through its Refining & Marketing Division, is the leader operator in Italy in refining, with its five wholly owned refineries (Sannazzaro, Livorno, Porto Marghera, Taranto and Gela), and in marketing of petroleum products. In the rest of Europe Eni also holds interests in certain refining poles and is active in retail and wholesale sales in Central/Eastern Europe Countries. As of December 31, 2011, Enis refining system had total refinery capacity (balanced with conversion capacity) of approximately 38.3 mmtonnes (equal to 767 kbbl/d) and a conversion index of 61%. In 2011, total refinery throughputs were 31.96 mmtonnes, of which 27 mmtonnes in Italy and 4.96 mmtonnes outside Italy. Total throughputs in wholly-owned refineries were 22.75 mmtonnes, down by 2.95 mmtonnes from 2010, or 11.5%, determining a refinery utilization rate of 79%, declining from 2010 consistent with the unfavorable scenario. Approximately 22.3% of processed crude volumes was supplied by Enis Exploration & Production segment (15.8% in 2010) representing a 6.5 percentage point increase from 2010. n Italy Enis refining system in Italy is composed of five wholly-owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Enis refineries in Italy have operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to end markets and the integration with Enis other activities.

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Refining system in 2011

Ownership share (%) Distillation capacity (total) (kbbl/d) Distillation capacity (Enis share) (kbbl/d) Primary balanced refining capacity (Enis share) (kbbl/d) Conversion index (%) Fluid catalytic cracking - FCC (kbbl/d) Residue conversion (kbbl/d) Go-Finer (kbbl/d) Mild Hydro- cracking/ Hydro- cracking (kbbl/d) Visbreaking/ Thermal Cracking (kbbl/d) Coking (kbbl/d) Distillation capacity utilization rate (Enis share) (%) Balanced refining capacity utilization rate (Enis share) (%)

Wholly-owned refineries		685	685	574	64	69	42	37	29	89	46	66	79
Italy
Sannazzaro	100	223	223	190	59	34	12		29	29		80	94
Gela	100	129	129	100	142	35		37			46	50	65
Taranto	100	120	120	120	72		30			38		83	83
Livorno	100	106	106	84	11							67	85
Venice	100	107	107	80	20					22		38	51
Partially owned refineries (a)		874	245	193	51	167	25		99	27		88	101
Italy
Milazzo	50	248	124	80	76	45	25		32			89	119
Germany
Vohburg/Neustadt (Bayernoil)	20	215	43	41	36	49			43			92	92
Schwedt	8.33	231	19	19	42	49				27		105	105
Czech Republic
Kralupy
and Litvinov (Ceska Rafinerska)	32.4	180	59	53	30	24			24			79	88
Total		1,559	930	767	61	236	67	37	128	116	46	72	85

(a) Capacity of conversion plant is 100%.

Sannazzaro : the refinery has balanced refining capacity of 190 kbbl/d and a conversion index of 59%. Management believes that this unit is among the most efficient refineries in Europe. Located in the Po Valley, it mainly supplies markets in North-Western Italy and Switzerland. The high degree of flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genoa terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), two hydrocrackers (HdCK), which enable middle distillate conversion and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syn-gas to feed the nearby EniPower power plant at Ferrera Erbognone. Eni is developing a conversion plant employing the Eni Slurry Technology with a 23 kbbl/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled by the end of 2012. In addition the Short Contact Time-Catalytic Partial Oxidation project is underway for the production of hydrogen. Taranto : the refinery has balanced refining capacity of 120 kbbl/d and a conversion index of 72%. This refinery can process a wide range of crude and other feedstock. It principally produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Enis Val dAgri fields carried to Taranto through the Monte Alpi pipeline (in 2011, a total of 2.5 mmtonnes of this oil were processed). Gela : the refinery has balanced refining capacity of 100 kbbl/d and a conversion index of 142%. This refinery is located on the southern coast of Sicily and is integrated with upstream operations as it processes heavy crude produced from Enis nearby offshore and onshore fields in Sicily. Its high conversion level is ensured by an FCC unit with go-finer for feedstocks upgrading and two coking plants enabling conversion of heavy residues topping or vacuum residues. The power plant of this refinery also contains residue and exhaust fume treatment plants (so-called SNOx) which allow full compliance with the tightest environmental standards, removing almost all sulphur and nitrogen composites coming from the coke burning-process. An upgrade of the Gela refinery is underway by means of a refurbishment of its power plant, substantially renewing pet-coke boilers, aimed at increasing profitability maximizing synergies deriving from the integration of refining and power generation. Livorno : the refinery, with balanced refining capacity of 84 kbbl/d and a conversion index of 11%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its pipeline links with the local harbor and with the Florence storage sites by means of two pipelines optimizes intake, handling and distribution of products. Venice : the refinery, with balanced refining capacity of 80 kbbl/d and a conversion index of 20%, this refinery supplies mainly markets in North-Eastern Italy and Austria. Besides its primary distillation plants, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) designed to increase yields of valuable products. Milazzo : jointly-owned by Eni and Kuwait Petroleum Italy, the refinery has balanced primary refining capacity of 80 kbbl/d (Enis share) and a conversion rate of 73%. It is located on the northern coast of Sicily and is provided with two primary distillation plants, one unit of fluid catalytic cracking (FCC), one hydrocracking unit for the conversion of middle distillates (HdCK) and one unit devoted to the residue treatment process (LC-Finer).

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n Outside Italy In Germany, Eni holds an 8.33% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that included Vohburg and Neustadt refineries. Enis refining capacity in Germany amounts to approximately 60 kbbl/d mainly used to supply Enis distribution network in Bavaria and Eastern Germany. Eni holds a 32.4% stake in Ceska Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Enis share of refining capacity amounts to about 53 kbbl/d. In addition, through its 33.34% interest in Galp, Eni participates two refineries in Portugal: a small one in Porto specialized in the manufacture of lubricant bases and a larger and more complex refinery in Sines integrated with petrochemical productions. 2. Logistics Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 20 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude oil. Enis logistics model is organized in a hub structure including five main areas. These hubs monitor and centralize the handling of product flows aiming to drive forward more efficiency particularly in cost control of collection and delivery of orders. Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic cost, and increasing efficiency. Eni operates in the transport of oil and refined products: (i) by sea, through spot and long-term lease contracts of tanker ships; and (ii) on land, through the ownership of a pipeline network extending approximately 1,447 kilometers. Secondary distribution to retail and wholesale markets is effected through third parties who also own their means of transportation.

Marketing n Retail Italy In Italy Eni is leader in retail marketing of refined products with a 30.5% market share, up 0.1 percentage point from 2010. Retail sales in Italy of 8.36 mmtonnes (10.6 billion liters) decreased by approximately 270 ktonnes (10.9 billion liters), or down 3.1%, driven by lower consumption of gasoil and gasoline, particularly in the highway segment which was hit by automotive transport decline. Average gasoline and gasoil throughput (2,173 kliters) decreased by approximately 149 kliters from 2010. At December 31, 2011, Enis retail network in Italy consisted of 4,701 service stations, 159 more than at December 31, 2010 (4,542 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (158 units), the opening of new service stations (14 units), partly offset by the closing of service stations with low throughput (13 units). The re-branding of Enis service stations continued in 2011. We plan that by the end of 2012 80% of our proprietary service stations will have been re-branded to the "eni brand". In the context of weak domestic demand for fuels and rising competition, despite a planned reduction of approximately 500 service stations, management plans to preserve the
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market share achieved in 2011 (30.5%) by improving service quality, upgrading our outlets, retaining customers by means of innovative marketing actions and segmentation of the offering (in function of payment modalities or quality of the product, enhancing the role of loyalty programs). Great focus will be dedicated to improve efficiency by the automation of part of the network. Finally we expect a growing contribution to profitability by non-oil activities as we intend to expand the quality and range of products and services offered to our customers and pursue continuing innovation in the layout of our stores located at our proprietary outlets. Premium fuels In 2011, even sales of premium fuels (fuels of the "eni blu+" line with high performance and lower environmental impact), despite the support of strong promotional campaigns, were affected by the decline in domestic consumption and were lower than the previous year. In particular, sales of eni bludiesel+ amounted to approximately 493 mmtonnes (approximately 592 mmliters) with a decline of approximately 80 ktonnes from 2010 and represented 9% of volumes of gasoil marketed by Enis retail network. At December 31, 2011, service stations marketing bludiesel+ totaled 4,130 units (4,071 at 2010 year-end) covering approximately 88% of Enis network. Retail sales of blusuper+ amounted to 62 ktonnes (approximately 83 mmliters), with a slight decrease from 2010, and covered 2.4% of gasoline sales on Enis retail network (down 0.2% from a year ago). At December 31, 2011, service stations marketing blusuper+ totaled 2,703 units (2,672 at December 31, 2010), covering approximately 57% of Enis network. Within the development of innovative fuels and bio-fuels, in addition to the mentioned eni blu+ line, Eni is working at new catalysts for desulphuration for the optimization of gasoil quality and, with particular reference to bio-fuels, is studying the use of non food feedstocks deriving from biomass at the Donegani Research Center for its Ecofining proprietary technology, identifying new bio-components pro fuel, and evaluating their compatibility with engines. Promotional actions you&eni In 2010, Eni launched the new " you&eni " loyalty points program, which will last 3 years until January 31, 2013. This initiative offers prizes to customers in proportion to their purchases of fuels and convenience items through the accumulation of points on a loyalty card at service stations stores as well as at the ones of certain partners to the program. With reference to the promotional initiative, the cards that made at least one transaction in the period were approximately 6.5 million at December 31, 2011. The average number of cards monthly active was approximately 2.6 million. Volumes sold to customers cumulating points on their card were approximately 39% of total throughputs. Iperself In 2011, Eni, in addition to its "Iperself" promotional campaign which provides a discount to customers purchasing fuel in self-service stations during closing hours, launched a new promotional campaign denominated "Iperself h24". This promotion provides a discount on the corresponding price at self-service pump during the all day. Jointly with other marketing activities this initiative supported sales against the backdrop of weak demand and increased price elasticity. Multicard Routex The Routex Multicard paying card is addressed to professional transport (transporters and car fleets) and provides users with services ranging from delayed payment to discounts on fuel prices, centralized invoicing, reports on consumption and distances covered, in addition to toll paying in highways. This initiative aims at gaining loyalty from customers across Europe as the card can be used in Italy on all Agip branded service stations and, in its international version, on the service stations of all members of the Routex consortium (Aral, BP, OMV and Statoil). Non-oil In 2011, Eni continued to be engaged in increasing its supply of non-oil products and services in its service stations in Italy by developing a chain of franchised outlets, in particular: (i) "enicafé", a format present in 350 stations following the upgrading of bars and stores in its network; (ii) "enicafé&shop", a format including corners for the sale of food and car-care products in 200 Eni outlets. In 2011, Eni also launched a new self-service option h24 of food, non-food and personal care products by means of the installation of Eni branded vending machines in 150 outlets with the aim of extending this service to over 1,000 outlets in the next two years. In 2011, non-oil returns on retail network, including lubricants margins, were euro 67.4 million. n Retail rest of Europe In 2011, retail sales of refined products marketed in the rest of Europe (3.01 mmtonnes) were down 2.9% (approximately 90 ktonnes) from 2010. Volume additions in Austria, reflecting the 2010 acquisitions, were offset by lower sales in Germany due to certain lease contract terminations, in France due to the rationalization of service stations with lower throughput and in Eastern Europe due to declining demand. At December 31, 2011, Enis retail network in the rest of Europe consisted of 1,586 units, a decrease of 39 units from December 31, 2010 (1,625 service stations). The network evolution was as follows: (i) the closing of 41 low throughput service stations mainly in Austria and France; (ii) the negative balance of acquisitions/releases of lease concessions (17 units) with negative changes in particular in Germany, Austria and Switzerland; (iii) the purchase of 12 service stations, in particular in France and Germany; and (iv) the opening of 7 new outlets. Average throughput (2,299 kliters) decreased by 142 kliters from 2010 (2,441 kliters). Enis strategy in the rest of Europe is focused on selectively growing its market share, particularly in Germany and Eastern Countries (e.g. Czech Republic) leveraging on the synergies

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ensured by the proximity of these markets to Enis production and logistics facilities. 4. Wholesale Business Fuels Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution is supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and concessionaires. In 2011, sales volumes on wholesale markets in Italy (9.36 mmtonnes) were down by approximately 90 ktonnes from 2010, or 1%, mainly reflecting a decline in demand from transports and industrial customers due to a generalized slowdown and strong competitive pressure which affected in particular bunkering and bitumen, but also LPG due to unusual weather conditions. Jet fuel and fuel oil sales increased, while gasoil sales dropped starkly in 2011. Enis wholesale market share for 2011 averaged 28.3%, down 0.9 percentage points from 2010 (29.2%). Supplies of feedstock to the petrochemical industry (1.71 mmtonnes) were basically in line with 2010 recording a slight decline of 10 ktonnes related to lower feedstock supplies due to lowering demand from industrial customers. Sales on wholesale markets outside Italy (3.84 mmtonnes) decreased by 1%, mainly in Hungary, Germany and the Czech Republic, while sales increased in Austria, Switzerland and France. Other sales (18.31 mmtonnes) decreased by 1.29 mmtonnes, or 6.6%, mainly due to lower sale volumes to oil companies. Eni also markets jet fuel directly at 49 airports, of which 27 are in Italy. In 2011, these sales amounted to 2.1 mmtonnes (of which 1.6 mmtonnes in Italy). Eni is also active in the international market of bunkering, marketing marine fuel mainly in 120 ports, of which 80 in Italy. In 2011, marine fuel sales were 1.98 mmtonnes (1.91 mmtonnes in Italy). LPG In Italy, Eni is leader in LPG production, marketing and sale with 601 ktonnes sold for heating and automotive use equal to a 18.9% market share. An additional 214 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna. Outside Italy, LPG sales in 2011 amounted to 485 ktonnes of which 384 ktonnes in Ecuador where LPG market share is around 37.5%. Lubricants Eni operates seven (owned and co-owned) blending plants, in Italy, Europe, North and South America, Africa and the Far East. With a wide range of products composed of over 650 different blends Eni masters international state-of-the-art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Enis refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero. In 2011, retail and wholesale sales in Italy amounted to 100 ktonnes with a 23.6% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 140 ktonnes, of these about 60% were registered in Europe (mainly Spain, Germany, Austria and France). Oxygenates Eni, through its subsidiary Ecofuel (Enis interest 100%), sells approximately 1.7 mmtonnes/y of oxygenates mainly ethers (approximately 5.3% of world demand) and methanol (approximately 0.9% of world demand). About 80% of products are manufactured in Italy in Enis plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic) and the remaining 20% is bought and resold. Eni also distributes bio-ETBE on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio-ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. Starting from March 1, 2010, Italian regulation on bio-fuels content has been changed from 3% to 3.5%. Through bio-ETBE and FAME blending into fossil fuels Eni covered the compliance within 96% in 2011. From January 1, 2012, the compulsory content of bio-fuels increases to 4.5% from 2011 4%, Eni plans to cover compliance through bio-ETBE, FAME and direct blending of ethanol in gasolines in particular in some extents of Sannazzaro refinery inland.

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Supply of oil (mmtonnes) 2007 2008 2009 2010 2011

| Equity crude oil — Production
outside Italy | 27.47 | | 26.14 | | 29.84 | | 26.9 | | 24.29 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Production in Italy | 4.10 | | 3.57 | | 2.91 | | 3.24 | | 3.35 | |
| | 31.57 | | 29.71 | | 32.75 | | 30.14 | | 27.64 | |
| Other crudes oil | | | | | | | | | | |
| Purchases
on spot markets | 11.34 | | 12.09 | | 14.94 | | 20.95 | | 20.44 | |
| Purchases under long-term contracts | 16.65 | | 16.11 | | 19.71 | | 17.16 | | 10.94 | |
| | 27.99 | | 28.20 | | 34.65 | | 38.11 | | 31.38 | |
| Total crude oil purchases | 59.56 | | 57.91 | | 67.40 | | 68.25 | | 59.02 | |
| Purchases
of intermediate products | 3.59 | | 3.39 | | 2.92 | | 3.05 | | 4.26 | |
| Purchase of products | 16.14 | | 17.42 | | 13.98 | | 15.28 | | 15.85 | |
| TOTAL PURCHASES | 79.29 | | 78.72 | | 84.30 | | 86.58 | | 79.13 | |
| Consumption for power generation | (1.13 | ) | (1.00 | ) | (0.96 | ) | (0.92 | ) | (0.89 | ) |
| Other
changes (a) | (2.19 | ) | (1.04 | ) | (1.64 | ) | (2.69 | ) | (1.12 | ) |
| | 75.97 | | 76.68 | | 81.70 | | 82.97 | | 77.12 | |

| (a) | | Includes
changes in inventories, transport decline, consumption
and losses. |
| --- | --- | --- |
| i | i | i |

Refinery capacity 2007 2008 2009 2010 2011

Primary distillation capacity (a)	(kbbl/d)	910	930	930	930	930
Balanced
capacity (a)		748	737	747	757	767
Refinery throughputs on own account		743	717	480	514	455
Distillation
capacity utilization rate	(%)	81	81	73	73	61

(a) Enis share.

i i i

Availability of refined products (mmtonnes) 2007 2008 2009 2010 2011

| ITALY — At
wholly-owned refineries | 27.79 | | 25.59 | | 24.02 | | 25.70 | | 22.75 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Less input on account of third parties | (1.76 | ) | (1.37 | ) | (0.49 | ) | (0.50 | ) | (0.49 | ) |
| At
affiliate refineries | 6.42 | | 6.17 | | 5.87 | | 4.36 | | 4.74 | |
| Refinery throughputs on own
account | 32.45 | | 30.39 | | 29.40 | | 29.56 | | 27.00 | |
| Consumption
and losses | (1.63 | ) | (1.61 | ) | (1.60 | ) | (1.69 | ) | (1.55 | ) |
| Products available for sale | 30.82 | | 28.78 | | 27.80 | | 27.87 | | 25.45 | |
| Purchases
of refined products and change in inventories | 2.16 | | 2.56 | | 3.73 | | 4.24 | | 3.22 | |
| Products transferred to operations outside Italy | (3.80 | ) | (1.42 | ) | (3.89 | ) | (4.18 | ) | (1.77 | ) |
| Consumption
for power generation | (1.13 | ) | (1.00 | ) | (0.96 | ) | (0.92 | ) | (0.89 | ) |
| Sales of products | 28.05 | | 28.92 | | 26.68 | | 27.01 | | 26.01 | |
| OUTSIDE ITALY | | | | | | | | | | |
| Refinery throughputs on own
account | 4.70 | | 5.45 | | 5.15 | | 5.24 | | 4.96 | |
| Consumption
and losses | (0.31 | ) | (0.25 | ) | (0.25 | ) | (0.24 | ) | (0.23 | ) |
| Products available for sale | 4.39 | | 5.20 | | 4.90 | | 5.00 | | 4.73 | |
| Purchases
of finished products and change in inventories | 13.91 | | 15.14 | | 10.12 | | 10.61 | | 12.51 | |
| Products transferred from Italian operations | 3.80 | | 1.42 | | 3.89 | | 4.18 | | 1.77 | |
| Sales of products | 22.10 | | 21.76 | | 18.91 | | 19.79 | | 19.01 | |
| Refinery throughputs on own
account | 37.15 | | 35.84 | | 34.55 | | 34.80 | | 31.96 | |
| Total equity crude input | 9.29 | | 6.98 | | 5.11 | | 5.02 | | 6.54 | |
| Total sales of refined
products | 50.15 | | 50.68 | | 45.59 | | 46.80 | | 45.02 | |
| Crude oil sales | 25.82 | | 26.00 | | 36.11 | | 36.17 | | 32.10 | |
| TOTAL SALES | 75.97 | | 76.68 | | 81.70 | | 82.97 | | 77.12 | |

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Production and sales (mmtonnes) 2007 2008 2009 2010 2011

Production: — Gasoline	8.85	8.32	8.43	7.81	7.24
Gasoil	13.91	13.44	13.33	13.63	12.95
Jet
fuel/kerosene	1.38	1.54	1.42	1.46	1.41
Fuel oil	4.89	4.34	4.01	3.75	2.65
LPG	0.69	0.71	0.66	0.50	0.57
Lubricants	0.64	0.60	0.49	0.67	0.54
Petrochemical
feedstock	1.89	2.16	2.08	2.59	2.49
Other	2.96	2.86	2.28	2.46	2.33
Total production	35.21	33.97	32.70	32.87	30.18
Sales:
Italy	28.05	28.92	26.68	27.01	26.01
Gasoline	3.34	3.26	3.17	2.91	2.78
Gasoil	9.67	10.03	10.04	9.94	9.63
Jet fuel/kerosene	1.97	1.94	1.42	1.45	1.64
Fuel
oil	0.95	0.85	0.72	0.44	0.46
LPG	0.54	0.57	0.57	0.59	0.60
Lubricants	0.13	0.13	0.09	0.11	0.10
Petrochemical
feedstock	1.93	1.70	1.33	1.72	1.71
Other	9.52	10.44	9.34	9.85	9.09
Rest of Europe	20.08	19.63	16.02	16.66	15.88
Gasoline	2.14	2.21	1.89	1.85	1.79
Gasoil	5.16	5.11	3.55	3.95	3.71
Jet
fuel/kerosene	0.38	0.47	0.35	0.38	0.48
Fuel oil	0.25	0.23	0.29	0.25	0.23
LPG	0.13	0.16	0.14	0.12	0.12
Lubricants	0.10	0.11	0.08	0.10	0.09
Other	11.92	11.34	9.72	10.01	9.46
Extra Europe	2.02	2.13	2.89	3.13	3.13
Gasoline	1.52	1.63	2.51	2.74	2.62
LPG	0.36	0.37	0.36	0.37	0.38
Lubricants	0.02	0.03	0.02	0.02	0.02
Other	0.12	0.10	0.00	0.00	0.11
Worldwide
Gasoline	7.00	7.10	7.57	7.50	7.19
Gasoil	14.83	15.14	13.59	13.89	13.34
Jet fuel/kerosene	2.35	2.41	1.77	1.83	2.12
Fuel
oil	1.20	1.08	1.01	0.69	0.69
LPG	1.03	1.10	1.07	1.08	1.10
Lubricants	0.25	0.27	0.19	0.23	0.21
Petrochemical
feedstock	1.93	1.70	1.33	1.72	1.71
Other	21.56	21.88	19.06	19.86	18.66
Total sales	50.15	50.68	45.59	46.80	45.02

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Sales in Italy and outside Italy by market (mmtonnes) 2007 2008 2009 2010 2011

Retail	8.62	8.81	9.03	8.63	8.36
Wholesale	11.09	11.15	9.56	9.45	9.36
	19.71	19.96	18.59	18.08	17.72
Petrochemicals	1.93	1.70	1.33	1.72	1.71
Other markets	6.41	7.26	6.76	7.21	6.58
Sales in Italy	28.05	28.92	26.68	27.01	26.01
Retail rest of Europe	4.03	3.22	2.99	3.10	3.01
Wholesale
rest of Europe	4.39	3.94	3.66	3.88	3.84
Wholesale outside Europe	0.57	0.56	0.41	0.42	0.43
	8.99	7.72	7.06	7.40	7.28
Other markets	13.11	12.52	11.85	12.39	11.73
Sales outside Italy	22.10	20.24	18.91	19.79	19.01
Total sales (a)	50.15	49.16	45.59	46.80	45.02

(a) 2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Retail and wholesale sales of refined products (mmtonnes) 2007 2008 2009 2010 2011

Italy	19.71	19.96	18.59	18.08	17.72
Retail sales	8.62	8.81	9.03	8.63	8.36
Gasoline	3.19	3.11	3.05	2.76	2.60
Gasoil	5.25	5.50	5.74	5.58	5.45
LPG	0.17	0.19	0.22	0.26	0.29
Other	0.01	0.01	0.02	0.03	0.02
Wholesale sales	11.09	11.15	9.56	9.45	9.36
Gasoil	4.42	4.52	4.30	4.36	4.18
Fuel oil	0.95	0.85	0.72	0.44	0.46
LPG	0.37	0.38	0.35	0.33	0.31
Gasoline	0.15	0.15	0.12	0.16	0.19
Lubricants	0.13	0.12	0.09	0.10	0.10
Bunker	1.58	1.70	1.38	1.35	1.26
Jet
fuel	1.95	1.94	1.43	1.46	1.65
Other	1.54	1.49	1.17	1.25	1.21
Outside Italy (retail + wholesale)	8.99	7.72	7.06	7.40	7.28
Gasoline	2.29	2.12	1.89	1.85	1.79
Gasoil	5.16	3.80	3.54	3.95	3.82
Jet fuel	0.38	0.47	0.35	0.40	0.49
Fuel
oil	0.25	0.23	0.28	0.25	0.23
Lubricants	0.09	0.11	0.10	0.10	0.10
LPG	0.49	0.52	0.50	0.49	0.50
Other	0.33	0.47	0.40	0.36	0.35
Total (a)	28.70	27.68	25.65	25.48	25.00

(a) 2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Number of service stations (units) 2007 2008 2009 2010 2011

Italy		4,390	4,409	4,474	4,542	4,701
Ordinary
stations		4,253	4,273	4,344	4,415	4,574
Highway stations		137	136	130	127	127
Outside Italy		2,050	1,547	1,512	1,625	1,586
Germany		672	521	478	455	454
France		202	199	196	188	181
Iberian Peninsula (a)		371	-	-	-	-
Austria/Switzerland		443	458	446	582	547
Eastern Europe		362	369	392	400	404
Service
stations selling Blu products		4,357	4,445	4,822	4,994	5,179
"Multi-Energy"
service stations		4	4	4	5	5
Service
stations selling LPG and natural gas		538	537	690	657	864
Non-oil sales	(euro million)	144	153	147	136.9	156

(a) In October 2008 downstream activities including 371 service stations were sold to Galp.

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Average throughput (kliters/No. of service stations) 2007 2008 2009 2010 2011

Italy	2,444	2,470	2,482	2,322	2,173
Germany	2,968	2,868	3,167	3,360	3,237
France	2,365	2,152	2,193	2,310	2,209
Iberian
Peninsula (a)	2,910	2,519	-	-	-
Austria/Switzerland	1,767	1,763	1,691	1,711	1,645
Eastern
Europe	2,348	2,832	2,642	2,508	2,591
Average throughput	2,486	2,502	2,477	2,352	2,206

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

Market shares in Italy (%) 2007 2008 2009 2010 2011

Retail	29.2	30.6	31.5	30.4	30.5
Gasoline	27.3	28.5	29.0	27.9	27.8
Gasoil	31.2	32.7	33.8	32.5	32.6
LPG
(automotive)	18.2	19.1	20.2	21.4	22.7
Lubricants	24.3	23.7	21.5	35.7	27.6
Wholesale	29.0	30.4	27.5	29.2	28.3
Gasoil	31.3	31.8	32.0	33.5	30.8
Fuel oil	16.2	16.3	17.2	17.8	25.5
Bunker	44.0	44.6	40.1	40.4	33.6
Lubricants	24.3	25.0	23.3	24.0	23.6
Domestic market share	29.5	31.0	29.3	29.8	29.3

Retail market shares outside Italy (%) 2007 2008 2009 2010 2011

Central Europe — Austria	7.8	7.0	7.3	7.0	9.6
Switzerland	5.9	6.4	6.4	6.5	6.6
Germany	4.2	3.8	3.4	3.4	3.1
France	1.1	1.1	1.1	1.1	1.0
Eastern Europe
Hungary	7.9	11.6	11.6	11.9	11.9
Czech
Republic	7.7	11.4	11.3	11.8	11.6
Slovakia		10.2	9.2	9.7	9.8
Slovenia	2.0	2.1	2.4	2.3	2.2
Romania			1.2	1.5	1.7

Capital expenditures (euro million) 2007 2008 2009 2010 2011

Italy	873	850	581	633	803
Outside Italy	106	115	54	78	63
	979	965	635	711	866
Refining, supply and logistic	675	630	436	446	629
Italy	675	630	436	444	626
Outside
Italy				2	3
Marketing	282	298	172	246	228
Italy	176	183	118	170	168
Outside Italy	106	115	54	76	60
Other	22	37	27	19	9
	979	965	635	711	866

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2007 2008 2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 3.74 | 2.57 | | 2.34 | | 1.54 | | 1.47 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 10.25 | 9.95 | | 8.12 | | 5.94 | | 4.60 | |
| Net sales from operations (a) | (euro million) | 6,934 | 6,303 | | 4,203 | | 6,141 | | 6,491 | |
| Basic
petrochemicals | | 3,582 | 3,060 | | 1,832 | | 2,833 | | 2,987 | |
| Polymers | | 3,109 | 2,961 | | 2,185 | | 3,126 | | 3,299 | |
| Other
sales | | 243 | 282 | | 186 | | 182 | | 205 | |
| Operating profit | | 100 | (845 | ) | (675 | ) | (86 | ) | (424 | ) |
| Adjusted
operating profit | | 116 | (398 | ) | (426 | ) | (113 | ) | (276 | ) |
| Adjusted net profit | | 74 | (323 | ) | (340 | ) | (85 | ) | (208 | ) |
| Capital
expenditures | | 145 | 212 | | 145 | | 251 | | 216 | |
| Production | (ktonnes) | 8,795 | 7,372 | | 6,521 | | 7,220 | | 6,245 | |
| Sales of
petrochemical products | | 5,513 | 4,684 | | 4,265 | | 4,731 | | 4,040 | |
| Average plant utilization rate | (%) | 80.6 | 68.6 | | 65.4 | | 72.9 | | 65.3 | |
| Employees
at year end | (units) | 6,534 | 6,274 | | 6,068 | | 5,972 | | 5,804 | |
| Direct GHG emissions | (mmtonnes CO 2 eq) | 5.65 | 4.90 | | 4.63 | | 4.69 | | 4.12 | |
| NMVOC
(Non-Methane Volatile Organic Compounds) emissions | (tonnes) | 4.07 | 3.61 | | 3.83 | | 4.71 | | 4.18 | |
| SO x (sulphur oxide) emissions | (ktonnes of SO 2 eq) | 6.97 | 5.12 | | 4.59 | | 3.30 | | 3.18 | |
| NO x (nitrogen oxide) emissions | (ktonnes of NO 2 eq) | 6.00 | 5.27 | | 4.78 | | 4.87 | | 4.14 | |
| Recycled/reused water | (%) | n.a. | n.a. | | 81.6 | | 82.7 | | 81.8 | |

(a) Before elimination of intragroup sales.

Performance of the year I In 2011, injury rates of employees and contractors continued to follow the positive trends of previous years (down 4.5% and 22.6%, respectively). I In 2011, emissions of greenhouse gases NMVOC, SO x and NO x decreased due to lower sale volumes and to energy saving interventions performed in the year. I In 2011, the percentage of reused water was approximately 80%, barely unchanged from previous years. I In 2011, the sector reported a significant increase in adjusted net loss (euro 208 million, down euro 123 million) from 2010, due to higher supply costs of oil-based feedstock which were not recovered in sale prices on end markets in a context of substantial decrease in demand. I Sales of petrochemical products were 4,040 ktonnes, down 691 ktonnes, or 14.6%, from 2010 due to lower demand. Petrochemical production volumes were 6,245 ktonnes, decreased by 975 ktonnes, or down 13.5%, due to a decline in demand for petrochemical products in all business, with the only exception of elastomers (up 1%). In 2011, the average plant utilization rate decreased from 72.9 to 65.3 due to reduced production in a phase of economic slowdown. I Average unit sales prices increased by 20% from 2010 due to the positive impact of the oil price scenario (virgin naphtha prices increased by 31% from 2010). I In 2011, overall expenditure in R&D amounted to approximately euro 32 million in line with the previous year. A total of new 13 patent applications were filed. Green Chemistry I In June 2011 Eni, through its subsidiary Polimeri Europa 1 , signed a cooperation agreement with Novamont SpA to convert Enis Porto Torres chemical plant into an innovative bio-based chemical complex to produce bio-plastics and other bio-based products (bio-lubricants and bio-additives) for which significant growth is expected in the medium/long-term. The project will be supported by an integrated supply chain and raw materials of vegetable origin. Novamont will contribute with its technologies and skills in the bio-plastics and bio-based chemical sector. Eni will contribute to the joint entity with its Porto Torres plant, infrastructure and professional staff as well as its industry, technical engineering and commercial know-how in the petrochemical sector. In addition, Eni aims to build a biomass power plant and to carry out a number of projects for the environmental restoration and clean-up

(1) i From April 5, 2012 Polimeri Europa SpA changed its company name in Versalis.

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activities. Eni plans to make capital expenditures totaling approximately euro 1.2 billion in the 2011-2016 period to execute the above mentioned projects, directly or through the joint entity. Activities Eni through Versalis performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies, advanced production facilities, as well as a large and efficient retail network present in 18 European Countries. The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibers and polystyrene. In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

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Business areas Basic petrochemicals Basic petrochemicals account for one of the pillars of the petrochemical activities of Versalis, whose products have a range of important industrial uses, such as the production of polyethylene, polypropylene, PVC and polystyrene. They are also used in the production of petrochemical intermediates that converge, in turn, into a range of other productive processes: plastics, rubbers, fibers, solvents and lubricants. Basic petrochemicals revenues (euro 2,987 million) increased by euro 154 million from 2010 (up 5.4%) in all main business segments due to the steep increase in average unit prices (olefins/aromatics up 20%, intermediates up 16%) as a result of an improved scenario, partly offset by lower volumes sold (down 18% on average). In particular, a decline was reported in sale volumes of olefins (ethylene down 22%; butadiene down 57% due to the lack of raw material) and intermediates (down 21% on average, in particular phenol and acetone). Basic petrochemicals production (4,101 ktonnes) decreased by 759 ktonnes from last year (down 15.6%) due to lower sales/demand of monomers. Lower ethylene production reflected facility downtimes in the Porto Marghera and Porto Torres plants. In addition, intermediates sales decreased (down 14%) due to unavailability of raw material and planned facility downtimes in the Mantova plant. In the intermediates business a new technology was introduced at a pilot scale aimed at eliminating the coproduction of acetone, a dangerous and unwanted co-product. Polymers In polymers business, Versalis is active in the production of: - Polyethylene that accounts for 40% of the total volume of world production of plastic materials. It is a basic plastic material, used as a raw material by companies that transform it into a range of finished goods. - Styrenics are polymeric materials based on styrenes that are used in a very large number of sectors through a range of transformation technologies. The most common applications are for industrial packaging and in the food industry, small and large electrical appliances, building isolation, electrical and electronic devices, household appliances, car components and toys. - Elastomers are polymers characterized by high elasticity that allow them to regain their original shape even after having been subjected to extensive deformation. Versalis has a leading position in this sector and produces a wide range of products for the following sectors: tyres, footwear, adhesives, building components, pipes, electrical cables, car components and sealings, household appliances; they can be used as modifiers for plastics and bitumens, as additives for lubricating oils (solid elastomers); paper coating and saturation, carpet backing, molded foams, adhesives (synthetic latex). Versalis is one of the worlds major producers of elastomers and synthetic latex. In 2011 polymers revenues (euro 3,299 million) increased by euro 173 million from 2010 (up 5.5%) due to increases in average unit prices (elastomers up 34%, styrene polymers up 12%; polyethylene up 11%). Sale volumes decreased on average by 11.5% (main decreases were registered in polyethylene, down 16%, lattices down 15%, polybutadiene and thermoplastic rubbers down approximately 9%) due to a steep decline in demand. Sales of ABS and SBR rubbers showed an opposite trend, up 5% and 2%, respectively. Polymers production (2,144 ktonnes) decreased by 216 ktonnes from 2010 (down 9%), mainly polyethylene (down 15%) due to the delay in the restart of the Dunkerque production lines, planned facility downtimes at Priolo, Ragusa and Gela in the last part of the year as well as decline in demand.

Product availability (ktonnes) 2007 2008 2009 2010 2011

Basic petrochemicals — Polymers	6,274 — 2,521		5,110 — 2,262		4,350 — 2,171		4,860 — 2,360		4,101 — 2,144
Production	8,795		7,372		6,521		7,220		6,245
Consumption
and losses	(4,099	)	(3,539	)	(2,701	)	(2,912	)	(2,631	)
Purchases and change in inventories	816		851		445		423		426
	5,512		4,684		4,265		4,731		4,040

Revenues by geographic area (euro million) 2007 2008 2009 2010 2011

Italy	3,327	3,290	2,215	3,131	3,364
Rest of
Europe	3,231	2,646	1,701	2,632	2,747
Asia	190	200	169	139	182
Africa	115	88	76	127	101
Americas	69	75	39	108	93
Other
areas	2	4	3	4	4
	6,934	6,303	4,203	6,141	6,491

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Revenues by product (euro million) 2007 2008 2009 2010 2011

Olefins	2,047	1,763	1,059	1,705	1,754
Aromatics	781	679	486	704	835
Intermediates	754	618	287	424	398
Elastomers	709	754	579	834	1,062
Styrenics	718	633	465	695	741
Polyethylene	1,682	1,574	1,140	1,597	1,496
Other	243	282	187	182	205
	6,934	6,303	4,203	6,141	6,491

Capital expenditures (euro million) 2007 2008 2009 2010 2011

Total capital expenditures	145	212	145	251	216
of which:
- upkeeping	29	84	28	59	59
- plant
upgrades	47	51	58	116	53
- HSE	39	41	28	29	46
-
energy recovery				45	42

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2007 2008 2009 2010 2011

| Employee injury frequency rate | (No. of accidents per
million hours worked) | 0.87 | 0.70 | 0.40 | 0.45 | 0.44 |
| --- | --- | --- | --- | --- | --- | --- |
| Contractors
injury frequency rate | | 0.62 | 0.38 | 0.57 | 0.33 | 0.21 |
| Fatality index | (No. of fatalities per
100 million hours worked) | 4.00 | 2.83 | 0.86 | 2.14 | 1.82 |
| Net sales
from operations (a) | (euro million) | 8,678 | 9,176 | 9,664 | 10,581 | 11,834 |
| Operating profit | | 837 | 1,045 | 881 | 1,302 | 1,422 |
| Adjusted
operating profit | | 840 | 1,041 | 1,120 | 1,326 | 1,443 |
| Adjusted net profit | | 658 | 784 | 892 | 994 | 1,098 |
| Capital
expenditure | | 1,410 | 2,027 | 1,630 | 1,552 | 1,090 |
| Adjusted ROACE | (%) | 17.1 | 16.8 | 15.4 | 14.0 | 13.9 |
| Orders
acquired | (euro million) | 11,845 | 13,860 | 9,917 | 12,935 | 12,505 |
| Order backlog | | 15,390 | 19,105 | 18,730 | 20,505 | 20,417 |
| Employees
at year end | (units) | 33,111 | 35,629 | 35,969 | 38,826 | 38,561 |
| Employees outside Italy rate | (%) | 84.9 | 84.8 | 85.6 | 87.3 | 86.5 |
| Local
managers rate | | n.a. | n.a. | 41.1 | 45.3 | 43.0 |
| Local procurement rate | | n.a. | n.a. | 47.0 | 61.3 | 56.4 |
| Healthcare
expenditures | (euro thousand) | 13,064 | 15,436 | 25,205 | 19,506 | 32,410 |
| Security expenditures | | 70,523 | 57,477 | 68,954 | 26,403 | 50,541 |
| Direct GHG
emissions | (mmtonnes CO 2 eq) | 1.07 | 1.36 | 1.28 | 1.11 | 1.32 |

(a) Before elimination of intragroup sales.

Performance of the year I The percentage of managerial positions covered by local personnel is constantly higher than 40% of total managerial positions, except for Italy and France, reflecting however fluctuations due to the opening of new yards and short-term projects. I The overall amount of procurement was euro 8,740 million in 2011, of which euro 6,510 million related to operating projects, 56.4% of which was procured with local suppliers. I In 2011, the injury frequency rate improved from 2010 (down 2% and down 36% for employees and contractors, respectively). I Health and safety expenditures for individual protection equipment and medical assistance increased by 81% from 2010 (from euro 46 million to euro 83 million). I In 2011, the Engineering & Construction sector achieved a positive performance with an adjusted net profit amounting to euro 1,098 million, up euro 104 million, or 10.5%, from a year ago, mainly due to a higher turnover and increasing project profitability. I Return on average capital employed calculated on an adjusted basis was 13.9% in 2011 (14% in 2010). I Orders acquired amounted to euro 12,505 million (euro 12,935 million in 2010), of these projects to be carried outside Italy represented 91%, while orders from Eni companies amounted to 7% of the total. I Order backlog amounted to euro 20,417 million at December 31, 2011 (euro 20,505 million at December 31, 2010), of which euro 9,451 million to be carried out within 2012. I Capital expenditures amounting to euro 1,090 million (euro 1,552 million in 2010) mainly regarded the upgrading of the drilling and construction fleet. I In 2011, overall expenditure in R&D amounted approximately to euro 15 million in line with 2010. A total of 28 new patent applications were filed.

Engineering & Construction Offshore Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the

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marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented business model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies ("NOCs"). Higher levels of efficiency and flexibility are expected to be achieved by reaching the technological excellence and the highest economies of scale in its engineering hubs employing local resources in contexts where this represents a competitive advantage, integrating in its own business model the direct management of construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a pipelayer and other supporting assets for offshore activity. This capital expenditure will enable Saipem to underpin its operations in deepwater and sub-artic. In 2011, revenues amounted to euro 4,908 million, increasing by 10.4% from 2010, due to higher levels of activity in Northern Europe, Kazakhstan and Asia Pacific. Orders acquired amounted to euro 6,131 million (euro 4,600 million in 2010). The most significant order awarded in 2011 in Engineering & Construction Offshore construction were: (i) the EPIC contract on behalf of South Oil Co for the expansion of the Basra oil center and related infrastructures in the field of the Iraq Crude Oil Export Expansion - Phase 2 project; (ii) the EPIC contract on behalf of Saudi Aramco for the realization of the offshore infrastructures in the field of the development of the offshore fields Arabiyah and Hasbah in the Arabian section of the Persian Gulf; and (iii) an EPIC contract on behalf of Husky Oil China Ltd for the installation of two subsea pipelines and related production system for the South China Sea. Engineering & Construction Onshore In the Engineering & Construction Onshore construction business, Saipem is one of the largest operators on turnkey contract base at a worldwide level in the oil&gas segment, especially through the acquisition of Snamprogetti. Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem preserves its own competitiveness through its technology excellence granted by its engineering hubs, its distinctive know-how in the construction of projects in the high-tech market of LNG and the management of large parts of engineering activities in cost efficient areas. In the medium term, underpinning upward trends in the oil service market, Saipem will be focused on taking advantage of the opportunities arising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of Middle-East/Caspian Sea, Northern and Western Africa and Russia. In 2011, revenues amounted to euro 5,369 million, increasing by 13.6% from 2010, due to higher levels of activity in the Middle East, Canada and Australia. Orders acquired amounted to euro 5,006 million (euro 7,744 million in 2010). The principal orders awarded in 2011 in Engineering & Construction onshore were: (i) the realization of 39 kilometers high-speed/high-capacity railway along the Treviglio-Brescia railway in Northern Italy on behalf of Rete Ferroviaria SpA; (ii) the EPC contract for the construction of a Secondary Upgrader with a capacity of 43 kbbl/d of Hydrotreated gas oil. The infrastructure will be part of the Horizon Oil Sands Project Hydrotreater Phase 2 in Alberta, in the Athabasca Region, Canada; and (iii) the EPC contract for the realization of a gas pipeline, 42 inches in diameter and 435-kilometer long, which will connect the gas fields in the Bowen and Surat Basins to the Gladstone State Development Area (GSDA), near the city of Gladstone, in the western Australian coast on behalf of Gladstone Operations Pty Ltd.

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Offshore drilling Saipem is the only engineering and construction contractor that provides both offshore and onshore drilling services to oil companies. In the offshore drilling segment, Saipem mainly operates in West Africa, the North Sea, the Mediterranean Sea and the Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum water depth of 3,600 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-the-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In particular, in the following years, Saipem intends to complete the building of the Scarabeo 8 and 9, new generation semi-submersible platforms, that have been already rented to Eni through multi-year contracts. In parallel, investments are ongoing to renew and to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment). In 2011, revenues amounted to euro 833 million, increasing by 11.1% from 2010 mainly due to the entry in full activity of the Saipem 10000 and Saipem 12000 drilling vessels and of the Perro Negro 8 jack up. In 2001 orders acquired amounted to euro 780 million (euro 326 million in 2010). The most significant order awarded in 2011 in Offshore drilling were: (i) a 24-month extension contract, from August 2012, for the lease of the drilling vessel Saipem 10000 on behalf of Eni; (ii) a 24-month extension contract, from August 2015, for the lease of the drilling vessel Saipem 12000; and (iii) a 36- month extension contract for the lease of the jack up Perro Negro 7. Onshore drilling Saipem operates in this area as a main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this area Saipem can leverage its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments. In 2011, revenues amounted to euro 724 million, increasing by 9.5% from 2010 mainly due to higher utilization of equipments in South America and entry in operation of new plants in Kazakhstan. Orders acquired amounted to euro 588 million (euro 265 million in 2010). The most significant order awarded in 2011 in Onshore drilling were: (i) a contract on behalf on Saudi Aramco in Saudi Arabia for the lease of nine rigs with a contract duration from one to three years; (ii) contracts on behalf of various clients in Peru, Colombia and Bolivia for the lease of fourteen rigs with a contract duration from 4 to 24 months; and (iii) two contracts on behalf of Ural Oil and Samek for the lease of 2 rigs with a contract duration of 4 and 12 months, respectively.

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Main operating data 2007 2008 2009 2010 2011

Offshore pipelines laid	(km)	665	815	1,000	1,365	1,682
Onshore
pipelines laid	(km)	770	683	716	385	889
Offshore structures installed	(t)	187,054	24,835	62,333	46,606	105,033
Onshore
structures installed	(t)	194,561	163,137	76,543	874,428	353,480
Offshore drilling	(km)	123	150	140	130	178
Onshore
drilling	(km)	657	622	719	881	985
Offshore wells drilled	(units)	47	50	54	44	64
Onshore
wells drilled	(units)	256	241	241	279	307

Drilling vessels

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

| Perro Negro 2 | Jack up | Oilwell
E 2000 | 90 | 6,500 | Heliport provided |
| --- | --- | --- | --- | --- | --- |
| Perro
Negro 3 | Jack up | Ideco E 2100 | 90 | 6,000 | Heliport provided |
| Perro Negro 4 | Jack up | National
110 UE | 45 | 5,000 | Heliport provided |
| Perro
Negro 5 | Jack up | National 1320 UE | 90 | 6,500 | Heliport provided |
| Perro Negro 6 | Jack up | National
SSDG 3000 | 107 | 9,150 | Heliport provided |
| Perro
Negro 7 | Jack up | National 1625 UE | 115 | 9,150 | Heliport provided |
| Perro Negro 8 | Jack up | NOV
SSDG-3000 | 107 | 9,100 | |
| Scarabeo 3 | Semi-submersible
drilling platform helped propulsion system | National 1625 DE | 550 | 7,600 | Heliport provided |
| Scarabeo 4 | Semi-submersible drilling platform helped
propulsion system | National
1625 DE | 550 | 7,600 | Heliport provided |
| Scarabeo 5 | Semi-submersible
drilling platform, self-propelled | Emco C3 | 1,900 | 8,000 | Heliport provided |
| Scarabeo 6 | Semi-submersible drilling platform,
self-propelled | Oilwell
E 3000 | 500 | 7,600 | Heliport provided |
| Scarabeo 7 | Semi-submersible
drilling platform, self-propelled | Wirth SH 3000 EG | 1,500 | 8,000 | Heliport provided |
| Saipem 10000 | Ultra deep waters drillship, self-propelled,
dynamic positioning | Wirth
GH 4500 EG | 3,000 | 9,200 | Oil storage capacity:
140,000 bbl; heliport provided |
| Saipem
12000 | Ultra deep
waters drillship, self-propelled, dynamic positioning | NOV SSDG-5750 | 3,650 | 10,000 | Heliport provided |
| Saipem TAD | Tender assisted drilling barge | Bentec
1500 Hp | 150 | 4,877 | Heliport provided |

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Construction vessels

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

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

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

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Eni Fact Book Financial Data

Profit and loss account (euro million) 2007 2008 2009 2010 2011

| Net sales from operations — Other
income and revenues | 87,204 — 833 | | 108,082 — 728 | | 83,227 — 1,118 | | 98,523 — 956 | | 109,589 — 933 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Total revenues | 88,037 | | 108,810 | | 84,345 | | 99,479 | | 110,522 | |
| Purchases,
services and other | (58,133 | ) | (76,350 | ) | (58,351 | ) | (69,135 | ) | (79,191 | ) |
| Payroll and related costs | (3,800 | ) | (4,004 | ) | (4,181 | ) | (4,785 | ) | (4,749 | ) |
| Total operating expenses | (61,933 | ) | (80,354 | ) | (62,532 | ) | (73,920 | ) | (83,940 | ) |
| Other operating income (expense) | (129 | ) | (124 | ) | 55 | | 131 | | 171 | |
| Depreciation,
depletion, amortization and impairments | (7,236 | ) | (9,815 | ) | (9,813 | ) | (9,579 | ) | (9,318 | ) |
| Operating profit | 18,739 | | 18,517 | | 12,055 | | 16,111 | | 17,435 | |
| Finance
(expense) income | 46 | | (640 | ) | (551 | ) | (727 | ) | (1,129 | ) |
| Net income from investments | 1,243 | | 1,373 | | 569 | | 1,156 | | 2,171 | |
| Profit before income taxes | 20,028 | | 19,250 | | 12,073 | | 16,540 | | 18,477 | |
| Income taxes | (9,219 | ) | (9,692 | ) | (6,756 | ) | (9,157 | ) | (10,674 | ) |
| Tax
rate (%) | 46.0 | | 50.3 | | 56.0 | | 55.4 | | 57.8 | |
| Net profit | 10,809 | | 9,558 | | 5,317 | | 7,383 | | 7,803 | |
| Attributable
to: | | | | | | | | | | |
| - Enis shareholders | 10,011 | | 8,825 | | 4,367 | | 6,318 | | 6,860 | |
| -
Non-controlling interest | 798 | | 733 | | 950 | | 1,065 | | 943 | |
| Net profit attributable to
Enis shareholders | 10,011 | | 8,825 | | 4,367 | | 6,318 | | 6,860 | |
| Exclusion
of inventory holding (gains) losses | (499 | ) | 723 | | (191 | ) | (610 | ) | (724 | ) |
| Exclusion of special items | 57 | | 616 | | 1,031 | | 1,161 | | 833 | |
| of
which: | | | | | | | | | | |
| - non-recurring items | 35 | | (21 | ) | 250 | | (246 | ) | 69 | |
| - other
special items | 22 | | 637 | | 781 | | 1,407 | | 764 | |
| Adjusted net profit
attributable to Enis shareholders | 9,569 | | 10,164 | | 5,207 | | 6,869 | | 6,969 | |

Summarized Group Balance Sheet (euro million) 2007 2008 2009 2010 2011

| Fixed assets — Property,
plant and equipment | 50,137 | | 55,933 | | 59,765 | | 67,404 | | 73,578 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Other assets | 563 | | | | | | | | | |
| Inventories
- Compulsory stock | 2,171 | | 1,196 | | 1,736 | | 2,024 | | 2,433 | |
| Intangible assets | 4,333 | | 11,019 | | 11,469 | | 11,172 | | 10,950 | |
| Equity-accounted
investments and other investments | 6,111 | | 5,881 | | 6,244 | | 6,090 | | 6,242 | |
| Receivables and securities held for operating
purposes | 725 | | 1,219 | | 1,261 | | 1,743 | | 1,740 | |
| Net
payables related to capital expenditures | (1,191 | ) | (787 | ) | (749 | ) | (970 | ) | (1,576 | ) |
| | 62,849 | | 74,461 | | 79,726 | | 87,463 | | 93,367 | |
| Net working capital | | | | | | | | | | |
| Inventories | 5,499 | | 6,082 | | 5,495 | | 6,589 | | 7,575 | |
| Trade
receivables | 15,609 | | 16,444 | | 14,916 | | 17,221 | | 17,709 | |
| Trade payables | (11,092 | ) | (12,590 | ) | (10,078 | ) | (13,111 | ) | (13,436 | ) |
| Tax
payables and provision for net deferred tax liabilities | (4,412 | ) | (5,323 | ) | (1,988 | ) | (2,684 | ) | (3,503 | ) |
| Provisions | (8,433 | ) | (9,506 | ) | (10,319 | ) | (11,792 | ) | (12,735 | ) |
| Other
current assets and liabilities | (2,653 | ) | (4,544 | ) | (3,968 | ) | (1,286 | ) | 281 | |
| | (5,482 | ) | (9,437 | ) | (5,942 | ) | (5,063 | ) | (4,109 | ) |
| Equity instruments | 2,476 | | 2,741 | | | | | | | |
| Provisions for employee
post-retirement benefits | (935 | ) | (947 | ) | (944 | ) | (1,032 | ) | (1,039 | ) |
| Net assets held for sale including related
net borrowings | 286 | | 68 | | 266 | | 479 | | 206 | |
| CAPITAL EMPLOYED, NET | 59,194 | | 66,886 | | 73,106 | | 81,847 | | 88,425 | |
| Shareholders equity: | | | | | | | | | | |
| attributable to: - Enis
shareholders (a) | 40,428 | | 44,436 | | 46,073 | | 51,206 | | 55,472 | |
| -
Non-controlling interest | 2,439 | | 4,074 | | 3,978 | | 4,522 | | 4,921 | |
| | 42,867 | | 48,510 | | 50,051 | | 55,728 | | 60,393 | |
| Net borrowings | 16,327 | | 18,376 | | 23,055 | | 26,119 | | 28,032 | |
| TOTAL LIABILITIES AND
SHAREHOLDERS EQUITY | 59,194 | | 66,886 | | 73,106 | | 81,847 | | 88,425 | |

(a) Net of own shares in portfolio.

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Eni Fact Book Financial Data

Summarized Group Cash Flow Statement (euro million) 2007 2008 2009 2010 2011

Net profit	10,809		9,558		5,317		7,383		7,803
Adjustments
to reconcile to cash generated from operating profit
before changes in working capital:
- amortization and depreciation and other non
monetary items	6,320		8,792		9,117		9,024		9,095
- net
gains on disposal of assets	(309	)	(219	)	(226	)	(552	)	(1,170	)
- dividends, interest, taxes and other changes	8,850		9,399		6,843		9,368		10,651
Changes in
working capital related to operations	(1,641	)	4,489		(1,195	)	(1,720	)	(2,176	)
Dividends received, taxes paid, interest (paid)
received during the period	(8,512	)	(10,218	)	(8,720	)	(8,809	)	(9,821	)
Net cash provided by operating activities	15,517		21,801		11,136		14,694		14,382
Capital expenditures	(10,593	)	(14,562	)	(13,695	)	(13,870	)	(13,438	)
Investments
and purchase of consolidated subsidiaries and businesses	(9,665	)	(4,019	)	(2,323	)	(410	)	(360	)
Disposals	659		979		3,595		1,113		1,912
Other cash
flow related to capital expenditures, investments and
disposals	(35	)	(267	)	(295	)	228		627
Free cash flow	(4,117	)	3,932		(1,582	)	1,755		3,123
Borrowings
(repayment) of debt related to financing activities	(479	)	911		396		(26	)	41
Changes in short and long-term financial debt	8,761		980		3,841		2,272		1,104
Dividends
paid and changes in non-controlling interest and reserves	(5,836	)	(6,005	)	(2,956	)	(4,099	)	(4,327	)
Effect of changes in consolidation and exchange
differences	(200	)	7		(30	)	39		10
NET CASH FLOW FOR THE PERIOD	(1,871	)	(175	)	(331	)	(59	)	(49	)

Change in net borrowings (euro million) 2007 2008 2009 2010 2011

Free cash flow	(4,117	)	3,932		(1,582	)	1,755		3,123
Net
borrowings of acquired companies	(244	)	(286	)			(33	)
Net borrowings of divested companies			181						(192	)
Exchange
differences on net borrowings and other changes	637		129		(141	)	(687	)	(517	)
Dividends paid and changes in non-controlling
interest and reserves	(5,836	)	(6,005	)	(2,956	)	(4,099	)	(4,327	)
CHANGE IN NET BORROWINGS	(9,560	)	(2,049	)	(4,679	)	(3,064	)	(1,913	)

Net sales from operations (euro million) 2007 2008 2009 2010 2011

| Exploration & Production — Gas &
Power | 26,920 — 27,793 | | 33,042 — 37,062 | | 23,801 — 30,447 | | 29,497 — 29,576 | | 29,121 — 34,731 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Refining & Marketing | 36,349 | | 45,017 | | 31,769 | | 43,190 | | 51,219 | |
| Petrochemicals | 6,934 | | 6,303 | | 4,203 | | 6,141 | | 6,491 | |
| Engineering & Construction | 8,678 | | 9,176 | | 9,664 | | 10,581 | | 11,834 | |
| Other
activities | 205 | | 185 | | 88 | | 105 | | 85 | |
| Corporate and financial companies | 1,313 | | 1,331 | | 1,280 | | 1,386 | | 1,365 | |
| Impact of
unrealized intragroup profit elimination (a) | | | 75 | | (66 | ) | 100 | | (54 | ) |
| Consolidation adjustment | (20,988 | ) | (24,109 | ) | (17,959 | ) | (22,053 | ) | (25,203 | ) |
| | 87,204 | | 108,082 | | 83,227 | | 98,523 | | 109,589 | |

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

Net sales to customers (euro million) 2007 2008 2009 2010 2011

Exploration & Production	10,640	14,125	10,171		12,947	10,677
Gas &
Power	27,036	36,189	29,812		28,743	33,648
Refining & Marketing	35,073	43,521	30,804		41,845	48,428
Petrochemicals	6,571	5,905	3,965		5,898	6,202
Engineering & Construction	7,496	7,957	8,349		8,779	10,510
Other
activities	174	156	64		80	62
Corporate and financial companies	214	154	128		131	116
Impact of
unrealized intragroup profit elimination		75	(66	)	100	(54	)
	87,204	108,082	83,227		98,523	109,589

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Eni Fact Book Financial Data

Net sales by geographic area of destination (euro million) 2007 2008 2009 2010 2011

Italy	37,294	42,843	27,950	47,802	33,805
Other EU
Countries	23,074	29,341	24,331	21,125	35,536
Rest of Europe	5,507	7,125	5,213	4,172	7,537
Africa	8,010	12,331	10,174	13,068	11,333
Americas	6,447	7,218	7,080	6,282	9,612
Asia	5,840	8,916	8,208	5,785	10,258
Other areas	1,032	308	271	289	1,508
Total outside Italy	49,910	65,239	55,277	50,721	75,784
	87,204	108,082	83,227	98,523	109,589

Purchases, services and other (euro million) 2007 2008 2009 2010 2011

| Production costs - raw, ancillary and consumable
materials and goods — Production
costs - services | 44,850 — 10,828 | | 58,662 — 13,355 | | 40,311 — 13,520 | | 48,261 — 15,400 | | 60,724 — 14,034 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Operating leases and other | 2,276 | | 2,558 | | 2,567 | | 3,066 | | 3,113 | |
| Net
provisions | 573 | | 884 | | 1,055 | | 1,407 | | 551 | |
| Other expenses | 1,101 | | 1,660 | | 1,527 | | 1,309 | | 1,214 | |
| less: | | | | | | | | | | |
| capitalized direct costs associated with
self-constructed tangible and intangible assets | (1,495 | ) | (769 | ) | (629 | ) | (308 | ) | (445 | ) |
| | 58,133 | | 76,350 | | 58,351 | | 69,135 | | 79,191 | |

Principal accountant fees and services (euro million) 2007 2008 2009 2010 2011

Audit fees	26,383	27,962	30,748	21,114	22,407
Audit-related
fees	169	152	276	183	1,034
Tax fees	81	46	51	166	26
All other
fees	120	1
	26,753	28,161	31,075	21,463	23,467

Payroll and related costs (euro million) 2007 2008 2009 2010 2011

| Wages and salaries — Social
security contributions | 2,906 — 690 | | 3,204 — 694 | | 3,330 — 706 | | 3,565 — 714 | | 3,704 — 760 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Cost related to defined benefit plans and
defined contribution plans | 161 | | 107 | | 137 | | 164 | | 158 | |
| Other
costs | 275 | | 282 | | 342 | | 600 | | 360 | |
| less: | | | | | | | | | | |
| capitalized
direct costs associated with self-constructed tangible
and intangible assets | (232 | ) | (283 | ) | (334 | ) | (258 | ) | (233 | ) |
| | 3,800 | | 4,004 | | 4,181 | | 4,785 | | 4,749 | |

Depreciation, depletion, amortization and impairments (euro million) 2007 2008 2009 2010 2011

| Exploration & Production — Gas &
Power | 5,431 — 739 | | 6,678 — 797 | | 6,789 — 981 | | 6,928 — 963 | | 6,251 — 955 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Refining & Marketing | 433 | | 430 | | 408 | | 333 | | 351 | |
| Petrochemicals | 116 | | 116 | | 83 | | 83 | | 90 | |
| Engineering & Construction | 248 | | 335 | | 433 | | 513 | | 596 | |
| Other
activities | 4 | | 4 | | 2 | | 2 | | 2 | |
| Corporate and financial companies | 68 | | 76 | | 83 | | 79 | | 75 | |
| Impact of
unrealized intragroup profit elimination | (10 | ) | (14 | ) | (17 | ) | (20 | ) | (23 | ) |
| Total depreciation, depletion
and amortization | 7,029 | | 8,422 | | 8,762 | | 8,881 | | 8,297 | |
| Impairments | 207 | | 1,393 | | 1,051 | | 698 | | 1,021 | |
| | 7,236 | | 9,815 | | 9,813 | | 9,579 | | 9,318 | |

Operating profit by Division (a) (euro million) 2007 2008 2009 2010 2011

| Exploration & Production — Gas &
Power | 13,433 — 4,465 | | 16,239 — 4,030 | | 9,120 — 3,687 | | 13,866 — 2,896 | | 15,887 — 1,758 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Refining & Marketing | 686 | | (988 | ) | (102 | ) | 149 | | (273 | ) |
| Petrochemicals | 100 | | (845 | ) | (675 | ) | (86 | ) | (424 | ) |
| Engineering & Construction | 837 | | 1,045 | | 881 | | 1,302 | | 1,422 | |
| Other
activities | (444 | ) | (466 | ) | (436 | ) | (1,384 | ) | (427 | ) |
| Corporate and financial companies | (312 | ) | (623 | ) | (420 | ) | (361 | ) | (319 | ) |
| Impact of
unrealized intragroup profit elimination | (26 | ) | 125 | | | | (271 | ) | (189 | ) |
| | 18,739 | | 18,517 | | 12,055 | | 16,111 | | 17,435 | |

(a) Environmental provisions incurred by the Parent Company Eni SpA due to inter-company guarantees on behalf of Syndial have been reported within the segment reporting unit "Other Activities".

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Eni Fact Book Financial Data

NON-GAAP measures

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

Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses and special items. Furthermore, finance charges on finance debt, interest income, gains or losses deriving from the evaluation of certain derivative financial instruments at fair value through profit or loss (as they do not meet the formal criteria to be assessed as hedges under IFRS, excluding commodity derivatives), and exchange rate differences are all excluded when determining adjusted net profit of each business segment. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (38% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Enis trading performance on the basis of their forecasting models. In addition, management uses segmental adjusted net profit when calculating return on average capital employed (ROACE) by each business segment. The following is a description of items that are excluded from the calculation of adjusted results. Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting. Special items include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; or (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (Consob), non recurring material income or charges are to be clearly reported in the managements discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives, including the ineffective portion of cash flow hedges and certain derivatives financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production Division. Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. In addition, gains or losses on the fair value evaluation of the aforementioned derivative financial instruments, excluding commodity derivatives and exchange rate differences are excluded from the adjusted net profit of business segments. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment-operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production Division). Finance charges or interest income and related taxation effects excluded from the adjusted net profit of the business segments are allocated on the aggregate Corporate and financial companies. For a reconciliation of adjusted operating profit and adjusted net profit to reported operating profit and reported net profit see tables below.

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Eni Fact Book Financial Data

2007 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	13,433		4,465		686		100		837		(444	)	(312	)	(26	)	18,739
Exclusion
of inventory holding (gains) losses			44		(658	)	(6	)									(620	)
Exclusion of special items
of
which:
Non-recurring (income)
charges	(11	)	(61	)	35		(2	)	(4	)	61		(10	)			8
Other special (income) charges:	348		(34	)	229		24		7		176		127				877
- environmental charges			15		128						210		12				365
- asset
impairments	226				58						6						290
- risk provisions					9						13						22
-
provision for redundancy incentives	6		38		31		24		7		18		32				156
- re-measurement gains/losses on commodity
derivatives	74		(16	)	6								83				147
- other	42		(71	)	(3	)					(71	)					(103	)
Special items of operating
profit	337		(95	)	264		22		3		237		117				885
Adjusted operating profit	13,770		4,414		292		116		840		(207	)	(195	)	(26	)	19,004
Net finance (expense) income (a)	60		(5	)			1				(8	)	(25	)			23
Net income
from investments (a)	176		420		126		1		80		5		4				812
Income taxes (a)	(7,678	)	(1,702	)	(124	)	(44	)	(262	)			154		10		(9,646	)
Tax
rate (%)	54.8		35.2		29.7				28.5								48.6
Adjusted net profit	6,328		3,127		294		74		658		(210	)	(62	)	(16	)	10,193
of
which attributable to:
- Non-controlling interest																	624
- Enis shareholders																	9,569
Reported net profit
attributable to Eni's shareholders																	10,011
Exclusion
of inventory holding (gains) losses (b)																	(499	)
Exclusion of special items:																	57
-
non-recurring (income) charges																	35
- other special (income) charges																	22
Adjusted net profit attributable to
Enis shareholders																	9,569

| (a) | Excluding
special items. |
| --- | --- |
| (b) | Including
euro 110 million related to equity-accounted entities. |

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Eni Fact Book Financial Data

2008 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	16,239		4,030		(988	)	(845	)	1,045		(466	)	(623	)	125		18,517
Exclusion
of inventory holding (gains) losses			(429	)	1,199		166										936
Exclusion of special items
of
which:
Non-recurring (income)
charges					(21	)											(21	)
Other special (income) charges:	983		(37	)	390		281		(4	)	222		341				2,176
- environmental charges			12		76						221		120				309
- asset
impairments	989		1		299		278				5						1,572
- gains on disposals of assets	4		7		13		(5	)	(4	)	(14	)	(9	)			(8	)
- risk
provisions											4						4
- provision for redundancy incentives	8		20		23		8				4		28				91
-
re-measurement gains/losses on commodity derivatives	(18	)	(74	)	(21	)							52				(61	)
- other			(3	)							2		270				269
Special items of operating profit	983		(37	)	369		281		(4	)	222		341				2,155
Adjusted operating profit	17,222		3,564		580		(398	)	1,041		(244	)	(282	)	125		21,608
Net
finance (expense) income (a)	70		(13	)	1		1		1		(39	)	(661	)			(640	)
Net income from investments (a)	609		420		174		(9	)	49		4		5				1,252
Income
taxes (a)	(10,001	)	(1,323	)	(234	)	83		(307	)			406		(49	)	(11,425	)
Tax rate (%)	55.9		33.3		31.0				28.1								51.4
Adjusted net profit	7,900		2,648		521		(323	)	784		(279	)	(532	)	76		10,795
of which attributable to:
-
Non-controlling interest																	631
- Enis shareholders																	10,164
Reported net profit attributable to Eni's
shareholders																	8,825
Exclusion of inventory holding (gains) losses (b)																	723
Exclusion
of special items:																	616
- non-recurring (income) charges																	(21	)
- other
special (income) charges																	637
Adjusted net profit
attributable to Enis shareholders																	10,164

| (a) | Excluding
special items. |
| --- | --- |
| (b) | Including
euro 118 million related to equity-accounted entities. |

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Eni Fact Book Financial Data

2009 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	9,120		3,687		(102	)	(675	)	881		(436	)	(420	)			12,055
Exclusion
of inventory holding (gains) losses			326		(792	)	121										(345	)
Exclusion of special items
of
which:
Non-recurring (income)
charges									250								250
Other special (income) charges:	364		(112	)	537		128		(11	)	178		78				1,162
- environmental charges			19		72						207						298
- asset
impairments	618		27		389		121		2		5						1,162
- gains on disposals of assets	(270	)	(6	)	(2	)			3		(2	)					(277	)
- risk
provisions			115		17						(4	)					128
- provision for redundancy incentives	31		25		22		10				8		38				134
-
re-measurement gains/losses on commodity derivatives	(15	)	(292	)	39		(3	)	(16	)							(287	)
- other											(36	)					4
Special items of operating profit	364		(112	)	537		128		239		178		78				1,412
Adjusted operating profit	9,484		3,901		(357	)	(426	)	1,120		(258	)	(342	)			13,122
Net
finance (expense) income (a)	(23	)	(15	)							12		(525	)			(551	)
Net income from investments (a)	243		332		75				49		1						700
Income
taxes (a)	(5,826	)	(1,302	)	85		86		(277	)			123		(3	)	(7,114	)
Tax rate (%)	60.0		30.9		..				23.7								53.6
Adjusted net profit	3,878		2,916		(197	)	(340	)	892		(245	)	(744	)	(3	)	6,157
of which attributable to:
-
Non-controlling interest																	950
- Enis shareholders																	5,207
Reported net profit attributable to Eni's
shareholders																	4,367
Exclusion of inventory holding (gains) losses (b)																	(191	)
Exclusion
of special items:																	1,031
- non-recurring (income) charges																	250
- other
special (income) charges																	781
Adjusted net profit
attributable to Enis shareholders																	5,207

| (a) | Excluding
special items. |
| --- | --- |
| (b) | Including
euro 48 million related to equity-accounted entities. |

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Eni Fact Book Financial Data

2010 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	13,866		2,896		149		(86	)	1,302		)	(361	)	(271	)	16,111
Exclusion
of inventory holding (gains) losses			(117	)	(659	)	(105	)								(881	)
Exclusion of special items
of
which:
Non-recurring (income)
charges			(270	)					24							(246	)
Other special (income) charges:	18		610		339		78			1,179		96				2,320
- environmental charges	30		25		169					1,145						1,369
- asset
impairments	127		436		76		52		3	8						702
- gains on disposal of assets	(241	)	4		(16	)			5							(248	)
- risk
provisions			78		2					7		8				95
- provision for redundancy incentives	97		75		113		26		14	10		88				423
-
re-measurement gains/losses on commodity derivatives			30		(10	)			(22	)						(2	)
- other	5		(38	)	5					9						(19	)
Special items of operating profit	18		340		339		78		24	1,179		96				2,074
Adjusted operating profit	13,884		3,119		(171	)	(113	)	1,326	(205	)	(265	)	(271	)	17,304
Net
finance (expense) income (a)	(205	)	19						33	(9	)	(530	)			(692	)
Net income from investments (a)	274		406		92		1		10	(2	)					781
Income
taxes (a)	(8,353	)	(986	)	30		27		(375	)		96		102		(9,459	)
Tax rate (%)	59.9		27.8		..				27.4							54.4
Adjusted net profit	5,600		2,558		(49	)	(85	)	994	(216	)	(699	)	(169	)	7,934
of which attributable to:
-
Non-controlling interest																1,065
- Enis shareholders																6,869
Reported net profit attributable to
Enis shareholders																6,318
Exclusion of inventory holding (gains) losses (b)																(610	)
Exclusion
of special items:																1,161
- non-recurring (income) charges																(246	)
- other
special (income) charges																1,407
Adjusted net profit
attributable to Enis shareholders																6,869

| (a) | Excluding
special items. |
| --- | --- |
| (b) | Including
euro 51 million related to equity-accounted entities. |

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Eni Fact Book Financial Data

2011 (euro million)

E&P G&P R&M Petrochemicals E&C Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	15,887		1,758		(273	)	(424	)	1,422		(427	)	(319	)	(189	)	17,435
Exclusion
of inventory holding (gains) losses			(166	)	(907	)	(40	)									(1,113	)
Exclusion of special items
of
which:
Non-recurring (income)
charges							10				59						69
Other special (income) charges:	190		354		645		178		21		142		53				1,583
- environmental charges			10		34		1				141						186
- asset
impairments	190		145		488		160		35		4						1,022
- gains on disposal of assets	(63	)	(4	)	10				4		(7	)	(1	)			(61	)
- risk
provisions			77		8						9		(6	)			88
- provision for redundancy incentives	44		40		81		17		10		8		9				209
-
re-measurement gains/losses on commodity derivatives	1		45		(3	)			(28	)							15
- other	18		41		27						(13	)	51				124
Special items of operating profit	190		354		645		188		21		201		53				1,652
Adjusted operating profit	16,077		1,946		(535	)	(276	)	1,443		(226	)	(266	)	(189	)	17,974
Net
finance (expense) income (a)	(231	)	33								5		(932	)			(1,125	)
Net income from investments (a)	624		407		99				95		(3	)	1				1,223
Income
taxes (a)	(9,604	)	(845	)	174		68		(440	)	(1	)	410		78		(10,160	)
Tax rate (%)	58.3		35.4		..				28.6								56.2
Adjusted net profit	6,866		1,541		(262	)	(208	)	1,098		(225	)	(787	)	(111	)	7,912
of which attributable to:
-
Non-controlling interest																	943
- Enis shareholders																	6,969
Reported net profit attributable to
Enis shareholders																	6,860
Exclusion of inventory holding (gains) losses (b)																	(724	)
Exclusion
of special items:																	833
- non-recurring (income) charges																	69
- other
special (income) charges																	764
Adjusted net profit
attributable to Enis shareholders																	6,969

| (a) | Excluding
special items. |
| --- | --- |
| (b) | Including
euro 65 million related to equity-accounted entities. |

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Eni Fact Book Financial Data

Breakdown of special items (euro million) 2007 2008 2009 2010 2011

| Non-recurring charges
(income) | 8 | | (21 | ) | 250 | | (246 | ) | 69 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of
which: | | | | | | | | | | |
| estimated
charge of the possible resolution of the TSKJ matter | | | | | 250 | | | | | |
| curtailment
recognized of the reserve for post-retirement benefits
for Italian employees | (83 | ) | | | | | | | | |
| provisions and
utilizations against antitrust proceedings and
regulations | 91 | | | | | | | | | |
| settlement/payments
on antitrust and other Authorities proceedings | | | (21 | ) | | | (246 | ) | 69 | |
| Other special charges
(income): | 877 | | 2,176 | | 1,162 | | 2,320 | | 1,583 | |
| -
environmental charges | 365 | | 309 | | 298 | | 1,369 | | 186 | |
| - asset
impairments | 290 | | 1,572 | | 1,162 | | 702 | | 1,022 | |
| -
gains on disposal of assets | | | (8 | ) | (277 | ) | (248 | ) | (61 | ) |
| - risk provisions | 22 | | 4 | | 128 | | 95 | | 88 | |
| -
provision for redundancy incentives | 156 | | 91 | | 134 | | 423 | | 209 | |
| - re-measurement
gains/losses on commodity derivatives | 147 | | (61 | ) | (287 | ) | (2 | ) | 15 | |
| -
other | (103 | ) | 269 | | 4 | | (19 | ) | 124 | |
| Special items of operating
profit | 885 | | 2,155 | | 1,412 | | 2,074 | | 1,652 | |
| Net finance (expense) income | (23 | ) | | | | | 35 | | 4 | |
| Net income from investments | (321 | ) | (239 | ) | 179 | | (324 | ) | (883 | ) |
| of
which: | | | | | | | | | | |
| gain from the
sale of stakes in Haldor Topsøe AS and Camom SA | (290 | ) | | | | | | | | |
| gain
on divestment of GTT (Gaztransport et Technigaz SAS) | | | (185 | ) | | | | | | |
| gains from
disposal of International Transport assets | | | | | | | | | 1,044 | |
| gains
from disposal of assets | | | | | | | (332 | ) | (78 | ) |
| impairments | | | | | | | 28 | | 191 | |
| Income taxes | (658 | ) | (1,402 | ) | (560 | ) | (624 | ) | 60 | |
| of which: | | | | | | | | | | |
| taxes
on special items of operating profit | (214 | ) | (623 | ) | (413 | ) | (653 | ) | (521 | ) |
| tax impact
pursuant to Law Decree No. 112 of June 25, 2008 for
Italian subsidiaries: | | | (270 | ) | (27 | ) | | | | |
| -
on inventories | | | (176 | ) | | | | | | |
| - on deferred
taxes | | | (94 | ) | (27 | ) | | | | |
| tax
impact pursuant Budget Law 2008 for Italian subsidiaries | | | (290 | ) | | | | | | |
| adjustment to
deferred tax for Italian subsidiaries | (394 | ) | | | | | | | | |
| adjustment
to deferred tax for Libyan assets | | | (173 | ) | | | | | | |
| deferred tax
adjustment in a Production Sharing Agreement | | | | | | | | | 552 | |
| impairment
on deferred tax assets E&P | | | | | 72 | | | | | |
| other tax items | (50 | ) | (46 | ) | (192 | ) | 29 | | 29 | |
| Total special items of net
profit | (117 | ) | 514 | | 1,031 | | 1,161 | | 833 | |
| attributable to: | | | | | | | | | | |
| -
Non-controlling interest | (174 | ) | (102 | ) | | | | | | |
| - Eni's shareholders | 57 | | 616 | | 1,031 | | 1,161 | | 833 | |

Adjusted operating profit by Division (euro million) 2007 2008 2009 2010 2011

| Exploration & Production — Gas &
Power | 13,770 — 4,414 | | 17,222 — 3,564 | | 9,484 — 3,901 | | 13,884 — 3,119 | | 16,077 — 1,946 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Refining & Marketing | 292 | | 580 | | (357 | ) | (171 | ) | (535 | ) |
| Petrochemicals | 116 | | (398 | ) | (426 | ) | (113 | ) | (276 | ) |
| Engineering & Construction | 840 | | 1,041 | | 1,120 | | 1,326 | | 1,443 | |
| Other
activities | (207 | ) | (244 | ) | (258 | ) | (205 | ) | (226 | ) |
| Corporate and financial companies | (195 | ) | (282 | ) | (342 | ) | (265 | ) | (266 | ) |
| Impact of
unrealized intragroup profit elimination | (26 | ) | 125 | | | | (271 | ) | (189 | ) |
| | 19,004 | | 21,608 | | 13,122 | | 17,304 | | 17,974 | |

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Eni Fact Book Financial Data

Adjusted net profit by Division (euro million) 2007 2008 2009 2010 2011

| Exploration & Production — Gas &
Power | 6,328 — 3,127 | | 7,900 — 2,648 | | 3,878 — 2,916 | | 5,600 — 2,558 | | 6,866 — 1,541 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Refining & Marketing | 294 | | 521 | | (197 | ) | (49 | ) | (262 | ) |
| Petrochemicals | 74 | | (323 | ) | (340 | ) | (85 | ) | (208 | ) |
| Engineering & Construction | 658 | | 784 | | 892 | | 994 | | 1,098 | |
| Other
activities | (210 | ) | (279 | ) | (245 | ) | (216 | ) | (225 | ) |
| Corporate and financial companies | (62 | ) | (532 | ) | (744 | ) | (699 | ) | (787 | ) |
| Impact of
unrealized intragroup profit elimination | (16 | ) | 76 | | (3 | ) | (169 | ) | (111 | ) |
| | 10,193 | | 10,795 | | 6,157 | | 7,934 | | 7,912 | |
| of
which attributable to: | | | | | | | | | | |
| Non-controlling
interest | 624 | | 631 | | 950 | | 1,065 | | 943 | |
| Enis shareholders | 9,569 | | 10,164 | | 5,207 | | 6,869 | | 6,969 | |

Finance income (expense) (euro million) 2007 2008 2009 2010 2011

| Income from equity instruments — Exchange
differences, net | 188 — (51 | ) | 241 — 206 | | 163 — (106 | ) | 92 | | (111 | ) |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Finance income (expense) related to net
borrowings and other | (279 | ) | (668 | ) | (612 | ) | (634 | ) | (817 | ) |
| Net income
from securities | 39 | | 21 | | 3 | | 10 | | 9 | |
| Financial expense due to the passage of time
(accretion discount) | (186 | ) | (249 | ) | (218 | ) | (251 | ) | (247 | ) |
| Income
(expense) on derivatives | 155 | | (427 | ) | (4 | ) | (131 | ) | (112 | ) |
| less: | | | | | | | | | | |
| Finance
expense capitalized | 180 | | 236 | | 223 | | 187 | | 149 | |
| | 46 | | (640 | ) | (551 | ) | (727 | ) | (1,129 | ) |
| of which,
net income from receivables and securities held for
financing operating activities and interest on tax
credits | 96 | | 78 | | 40 | | 65 | | 68 | |

Income (expense on) from investments (euro million) 2007 2008 2009 2010 2011

| Share of profit of equity-accounted investments — Share of
loss of equity-accounted investments | 906 — (135 | ) | 761 — (105 | ) | 693 — (241 | ) | 717 — (149 | ) | 678 — (106 | ) |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Gains on disposals | 301 | | 218 | | 16 | | 332 | | 1,125 | |
| Losses on
disposals | (1 | ) | (1 | ) | | | | | | |
| Dividends | 170 | | 510 | | 164 | | 264 | | 659 | |
| Decreases
(increases) in the provision for losses on investments | 2 | | (16 | ) | (59 | ) | (31 | ) | (28 | ) |
| Other income (expense), net | | | 6 | | (4 | ) | 23 | | (157 | ) |
| | 1,243 | | 1,373 | | 569 | | 1,156 | | 2,171 | |

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Eni Fact Book Financial Data

Property, plant and equipment by Division (at year end) (euro million) 2007 2008 2009 2010 2011

| Property, plant and equipment
by segment, gross — Exploration
& Production | 52,780 | | 64,338 | | 71,189 | | 85,494 | | 96,561 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Gas & Power | 24,641 | | 20,729 | | 22,040 | | 22,510 | | 23,655 | |
| Refining
& Marketing | 12,421 | | 12,899 | | 13,378 | | 14,177 | | 14,884 | |
| Petrochemicals | 4,918 | | 5,036 | | 5,174 | | 5,226 | | 5,438 | |
| Engineering
& Construction | 5,823 | | 7,702 | | 9,163 | | 10,714 | | 11,809 | |
| Other activities | 1,543 | | 1,550 | | 1,592 | | 1,614 | | 1,617 | |
| Corporate
and financial companies | 344 | | 391 | | 373 | | 372 | | 422 | |
| Impact of unrealized intragroup profit
elimination | (227 | ) | (355 | ) | (343 | ) | (495 | ) | (523 | ) |
| | 102,243 | | 112,290 | | 122,566 | | 139,612 | | 153,863 | |
| Property, plant and equipment
by segment, net | | | | | | | | | | |
| Exploration
& Production | 25,751 | | 32,355 | | 34,462 | | 40,521 | | 45,527 | |
| Gas & Power | 15,204 | | 13,038 | | 13,778 | | 13,876 | | 14,517 | |
| Refining
& Marketing | 4,495 | | 4,496 | | 4,397 | | 4,766 | | 4,758 | |
| Petrochemicals | 1,099 | | 912 | | 853 | | 990 | | 960 | |
| Engineering
& Construction | 3,513 | | 5,154 | | 6,305 | | 7,422 | | 7,969 | |
| Other activities | 82 | | 83 | | 79 | | 78 | | 76 | |
| Corporate
and financial companies | 196 | | 212 | | 179 | | 171 | | 196 | |
| Impact of unrealized intragroup profit
elimination | (203 | ) | (317 | ) | (288 | ) | (420 | ) | (425 | ) |
| | 50,137 | | 55,933 | | 59,765 | | 67,404 | | 73,578 | |

Capital expenditures by Division (euro million) 2007 2008 2009 2010 2011

Exploration & Production	6,480		9,281		9,486	9,690		9,435
Gas &
Power	1,511		2,058		1,686	1,685		1,721
Refining & Marketing	979		965		635	711		866
Petrochemicals	145		212		145	251		216
Engineering & Construction	1,410		2,027		1,630	1,552		1,090
Other
activities	59		52		44	22		10
Corporate and financial companies	108		95		57	109		128
Impact of
unrealized intragroup profit elimination	(99	)	(128	)	12	(150	)	(28	)
	10,593		14,562		13,695	13,870		13,438

Capital expenditures by geographic area of origin (euro million) 2007 2008 2009 2010 2011

Italy	3,246	3,674	3,198	3,044	3,587
Other
European Union Countries	1,246	1,660	1,454	1,710	1,337
Rest of Europe	469	582	574	724	1,174
Africa	3,152	5,153	4,645	5,083	4,369
Americas	1,004	1,240	1,207	1,156	978
Asia	1,253	1,777	2,033	1,941	1,608
Other areas	223	476	584	212	385
Total outside Italy	7,347	10,888	10,497	10,826	9,851
	10,593	14,562	13,695	13,870	13,438

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Eni Fact Book Financial Data

Net borrowings (euro million)

Debt and bonds Cash and cash equivalents Securities held for non-operating purposes Financing receivables held for non-operating purposes Total

| 2007 — Short-term
debt | 8,500 | (2,114 | ) | (174 | ) | (990 | ) | 5,222 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Long-term debt | 11,330 | | | | | (225 | ) | 11,105 |
| | 19,830 | (2,114 | ) | (174 | ) | (1,215 | ) | 16,327 |
| 2008 | | | | | | | | |
| Short-term
debt | 6,908 | (1,939 | ) | (185 | ) | (337 | ) | 4,447 |
| Long-term debt | 13,929 | | | | | | | 13,929 |
| | 20,837 | (1,939 | ) | (185 | ) | (337 | ) | 18,376 |
| 2009 | | | | | | | | |
| Short-term
debt | 6,736 | (1,608 | ) | (64 | ) | (73 | ) | 4,991 |
| Long-term debt | 18,064 | | | | | | | 18,064 |
| | 24,800 | (1,608 | ) | (64 | ) | (73 | ) | 23,055 |

| 2010 — Short-term
debt | 7,478 | (1,549 | ) | (109 | ) | (6 | ) | 5,814 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Long-term debt | 20,305 | | | | | | | 20,305 |
| | 27,783 | (1,549 | ) | (109 | ) | (6 | ) | 26,119 |
| 2011 | | | | | | | | |
| Short-term
debt | 6,495 | (1,500 | ) | (37 | ) | (28 | ) | 4,930 |
| Long-term debt | 23,102 | | | | | | | 23,102 |
| | 29,597 | (1,500 | ) | (37 | ) | (28 | ) | 28,032 |

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Eni Fact Book Employees

Employees

Employees at year end (a) (units) 2007 2008 2009 2010 2011

	Italy	3,930	4,054	3,883	3,906	3,797
Exploration
& Production	Outside Italy	4,446	6,182	6,388	6,370	6,628
		8,376	10,236	10,271	10,276	10,425
	Italy	9,362	9,029	8,842	8,652	8,422
Gas & Power	Outside Italy	2,531	2,663	2,562	2,593	2,485
		11,893	11,692	11,404	11,245	10,907
	Italy	7,079	6,609	6,467	6,162	5,790
Refining
& Marketing	Outside Italy	2,349	1,718	1,699	1,860	1,801
		9,428	8,327	8,166	8,022	7,591
	Italy	5,469	5,224	5,045	4,903	4,750
Petrochemicals	Outside Italy	1,065	1,050	1,023	1,069	1,054
		6,534	6,274	6,068	5,972	5,804
	Italy	4,994	5,420	5,174	4,915	5,197
Engineering
& Construction	Outside Italy	28,117	30,209	30,795	33,911	33,364
		33,111	35,629	35,969	38,826	38,561
	Italy	1,172	1,070	968	939	880
Other activities	Outside Italy	-	-	-	-	-
		1,172	1,070	968	939	880
	Italy	4,485	4,717	4,706	4,497	4,334
Corporate
and financial companies	Outside Italy	126	149	166	164	184
		4,611	4,866	4,872	4,661	4,518
	Italy	36,491	36,123	35,085	33,974	33,170
Total employees at year end	Outside Italy	38,634	41,971	42,633	45,967	45,516
		75,125	78,094	77,718	79,941	78,686
of which: senior managers		1,532	1,594	1,562	1,574	1,586

(a) 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.

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Eni Fact Book Supplemental oil and gas information

Supplemental oil and gas information

Oil and natural gas reserves Enis criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the US Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932). Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2011, the marker price for Brent was $111 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation 1 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report 2 . In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2011, Ryder Scott Company and DeGolyer and MacNaughton 2 provided an independent evaluation of almost 32% of Enis total proved reserves as of December 31, 2011 3 , confirming, as in previous years, the reasonableness of Enis internal evaluations. In the three year period from 2009 to 2011, 85% of Enis total proved reserves were subject to independent evaluation. As of December 31, 2011, the principal property not subjected to independent evaluation in the last three years is Kashagan (Kazakhstan). Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Enis economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Enis share of production and Enis net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 57%, 55% and 49% of total proved reserves as of December 31, 2009, 2010 and 2011, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 2%, 3% and 1% of total proved reserves on an oil-equivalent basis as of December 31, 2009, 2010 and 2011, respectively. Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 0.3%, 0.6% and 0.8% of total proved reserves as of December 31, 2009, 2010 and 2011, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant; and (iv) volumes of natural gas held in certain Eni storage fields in Italy. Proved reserves attributable to these fields include: (a) the residual natural gas volumes of the reservoirs; and (b) natural gas volumes from other Eni fields input into these reservoirs in subsequent periods. Proved reserves do not include volumes owned by or acquired from third parties. Gas withdrawn from storage is produced and thereby removed from proved reserves when sold. Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation.

| (1) | i | From 1991 to
2002, DeGolyer and MacNaughton, from 2003 also Ryder
Scott. |
| --- | --- | --- |
| (2) | i | The reports
of independent engineers are available on Eni website
eni.com, section Publications/Annual Report 2011. |
| (3) | i | Including
reserves of equity-accounted entities. |

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The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Enis proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced. The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2009, 2010 and 2011.

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Movements in net proved hydrocarbons reserves (mmboe)

2009 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia (b) America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2008 | 681 | | 525 | | 1,922 | | 1,146 | | 1,336 | | 265 | | 235 | | 132 | | 6,242 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 465 | | 417 | | 1,229 | | 827 | | 647 | | 168 | | 133 | | 62 | | 3,948 | |
| undeveloped | 216 | | 108 | | 693 | | 319 | | 689 | | 97 | | 102 | | 70 | | 2,294 | |
| Purchase of minerals in place | | | | | | | 2 | | | | | | 24 | | | | 26 | |
| Revisions
of previous estimates | 74 | | 65 | | 76 | | 102 | | (72 | ) | (26 | ) | 44 | | (2 | ) | 261 | |
| Improved recovery | | | 13 | | 10 | | 14 | | | | | | | | | | 37 | |
| Extensions
and discoveries | 10 | | 79 | | 121 | | 6 | | | | 44 | | 13 | | 9 | | 282 | |
| Production | (62 | ) | (91 | ) | (207 | ) | (129 | ) | (43 | ) | (47 | ) | (53 | ) | (6 | ) | (638 | ) |
| Sales of
minerals in place | | | (1 | ) | | | | | | | | | | | | | (1 | ) |
| Reserves at December 31, 2009 | 703 | | 590 | | 1,922 | | 1,141 | | 1,221 | | 236 | | 263 | | 133 | | 6,209 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2008 | | | | | 17 | | 8 | | | | 622 | | 19 | | | | 666 | |
| of
which: developed | | | | | 13 | | 4 | | | | 83 | | 7 | | | | 107 | |
| undeveloped | | | | | 4 | | 4 | | | | 539 | | 12 | | | | 559 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | | | 1 | | | | 2 | | | | | | 3 | |
| Improved
recovery | | | | | | | | | | | | | | | | | | |
| Extensions and discoveries | | | | | 1 | | 14 | | | | | | | | | | 15 | |
| Production | | | | | (3 | ) | (1 | ) | | | (1 | ) | (3 | ) | | | (8 | ) |
| Sales of minerals in place | | | | | | | | | | | (314 | ) | | | | | (314 | ) |
| Reserves at December 31, 2009 | | | | | 15 | | 22 | | | | 309 | | 16 | | | | 362 | |
| Reserves at December 31, 2009 | 703 | | 590 | | 1,937 | | 1,163 | | 1,221 | | 545 | | 279 | | 133 | | 6,571 | |
| Developed | 490 | | 432 | | 1,278 | | 804 | | 614 | | 183 | | 181 | | 122 | | 4,104 | |
| Consolidated subsidiaries | 490 | | 432 | | 1,266 | | 799 | | 614 | | 139 | | 168 | | 122 | | 4,030 | |
| Equity-accounted entities | | | | | 12 | | 5 | | | | 44 | | 13 | | | | 74 | |
| Undeveloped | 213 | | 158 | | 659 | | 359 | | 607 | | 362 | | 98 | | 11 | | 2,467 | |
| Consolidated subsidiaries | 213 | | 158 | | 656 | | 342 | | 607 | | 97 | | 95 | | 11 | | 2,179 | |
| Equity-accounted entities | | | | | 3 | | 17 | | | | 265 | | 3 | | | | 288 | |

i	i	i
(a)	i	Including
approximately 746 and 769 bcf of natural gas held in
storage at December 31, 2008 and 2009, respectively.
(b)	i	Proved
reserves of equity-accounted entities at year end 2008
include 60% of the three former Yukos companies. From
2009, after the 51% call option exercised by Gazprom,
values are reported at 29.4%.

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Movements in net proved hydrocarbons reserves (mmboe)

2010 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2009 | 703 | | 590 | | 1,922 | | 1,141 | | 1,221 | | 236 | | 263 | | 133 | | 6,209 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 490 | | 432 | | 1,266 | | 799 | | 614 | | 139 | | 168 | | 122 | | 4,030 | |
| of which: undeveloped | 213 | | 158 | | 656 | | 342 | | 607 | | 97 | | 95 | | 11 | | 2,179 | |
| Purchase of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions
of previous estimates | 97 | | 34 | | 353 | | 116 | | (56 | ) | 104 | | 13 | | | | 661 | |
| Improved recovery | | | | | 1 | | 1 | | | | | | | | | | 2 | |
| Extensions
and discoveries | | | 57 | | 39 | | 22 | | | | 1 | | 2 | | 4 | | 125 | |
| Production | (67 | ) | (80 | ) | (218 | ) | (145 | ) | (39 | ) | (46 | ) | (48 | ) | (10 | ) | (653 | ) |
| Sales of
minerals in place | (9 | ) | | | (1 | ) | (2 | ) | | | | | | | | | (12 | ) |
| Reserves at December 31, 2010 | 724 | | 601 | | 2,096 | | 1,133 | | 1,126 | | 295 | | 230 | | 127 | | 6,332 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2009 | | | | | 15 | | 22 | | | | 309 | | 16 | | | | 362 | |
| of
which: developed | | | | | 12 | | 5 | | | | 44 | | 13 | | | | 74 | |
| of which: undeveloped | | | | | 3 | | 17 | | | | 265 | | 3 | | | | 288 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | 9 | | 1 | | | | 10 | | (1 | ) | | | 19 | |
| Improved
recovery | | | | | | | | | | | | | 12 | | | | 12 | |
| Extensions and discoveries | | | | | 1 | | 6 | | | | | | 120 | | | | 127 | |
| Production | | | | | (2 | ) | (1 | ) | | | (2 | ) | (4 | ) | | | (9 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 23 | | 28 | | | | 317 | | 143 | | | | 511 | |
| Reserves at December 31, 2010 | 724 | | 601 | | 2,119 | | 1,161 | | 1,126 | | 612 | | 373 | | 127 | | 6,843 | |
| Developed | 554 | | 405 | | 1,237 | | 817 | | 543 | | 182 | | 167 | | 117 | | 4,022 | |
| Consolidated subsidiaries | 554 | | 405 | | 1,215 | | 812 | | 543 | | 139 | | 141 | | 117 | | 3,926 | |
| Equity-accounted entities | | | | | 22 | | 5 | | | | 43 | | 26 | | | | 96 | |
| Undeveloped | 170 | | 196 | | 882 | | 344 | | 583 | | 430 | | 206 | | 10 | | 2,821 | |
| Consolidated subsidiaries | 170 | | 196 | | 881 | | 321 | | 583 | | 156 | | 89 | | 10 | | 2,406 | |
| Equity-accounted entities | | | | | 1 | | 23 | | | | 274 | | 117 | | | | 415 | |

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

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Movements in net proved hydrocarbons reserves (mmboe)

2011 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2010 | 724 | | 601 | | 2,096 | | 1,133 | | 1,126 | | 295 | | 230 | | 127 | | 6,332 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 554 | | 405 | | 1,215 | | 812 | | 543 | | 139 | | 141 | | 117 | | 3,926 | |
| of which: undeveloped | 170 | | 196 | | 881 | | 321 | | 583 | | 156 | | 89 | | 10 | | 2,406 | |
| Purchase of minerals in place | 2 | | | | | | | | | | | | | | | | 2 | |
| Revisions
of previous estimates | 48 | | 94 | | 88 | | 12 | | (137 | ) | (26 | ) | 10 | | 17 | | 106 | |
| Improved recovery | | | 2 | | 2 | | 2 | | | | | | | | | | 6 | |
| Extensions
and discoveries | 1 | | 13 | | 3 | | 14 | | | | | | 40 | | | | 71 | |
| Production | (68 | ) | (78 | ) | (158 | ) | (133 | ) | (39 | ) | (39 | ) | (42 | ) | (11 | ) | (568 | ) |
| Sales of
minerals in place | | | (2 | ) | | | (7 | ) | | | | | | | | | (9 | ) |
| Reserves at December 31, 2011 | 707 | | 630 | | 2,031 | | 1,021 | | 950 | | 230 | | 238 | | 133 | | 5,940 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 23 | | 28 | | | | 317 | | 143 | | | | 511 | |
| of
which: developed | | | | | 22 | | 5 | | | | 43 | | 26 | | | | 96 | |
| of which: undeveloped | | | | | 1 | | 23 | | | | 274 | | 117 | | | | 415 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | | | 37 | | | | 73 | | 13 | | | | 123 | |
| Improved
recovery | | | | | | | | | | | | | 1 | | | | 1 | |
| Extensions and discoveries | | | | | | | 19 | | | | 268 | | 233 | | | | 520 | |
| Production | | | | | (2 | ) | (1 | ) | | | (2 | ) | (4 | ) | | | (9 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2011 | | | | | 21 | | 83 | | | | 656 | | 386 | | | | 1,146 | |
| Reserves at December 31, 2011 | 707 | | 630 | | 2,052 | | 1,104 | | 950 | | 886 | | 624 | | 133 | | 7,086 | |
| Developed | 540 | | 374 | | 1,194 | | 746 | | 482 | | 134 | | 188 | | 112 | | 3,770 | |
| Consolidated subsidiaries | 540 | | 374 | | 1,175 | | 742 | | 482 | | 129 | | 162 | | 112 | | 3,716 | |
| Equity-accounted entities | | | | | 19 | | 4 | | | | 5 | | 26 | | | | 54 | |
| Undeveloped | 167 | | 256 | | 858 | | 358 | | 468 | | 752 | | 436 | | 21 | | 3,316 | |
| Consolidated subsidiaries | 167 | | 256 | | 856 | | 279 | | 468 | | 101 | | 76 | | 21 | | 2,224 | |
| Equity-accounted entities | | | | | 2 | | 79 | | | | 651 | | 360 | | | | 1,092 | |

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

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Movements in net proved liquids reserves (mmbbl)

2009 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia (a) America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2008 | 186 | | 277 | | 823 | | 783 | | 911 | | 106 | | 131 | | 26 | | 3,243 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 111 | | 222 | | 613 | | 576 | | 298 | | 92 | | 74 | | 23 | | 2,009 | |
| of which: undeveloped | 75 | | 55 | | 210 | | 207 | | 613 | | 14 | | 57 | | 3 | | 1,234 | |
| Purchase of minerals in place | | | | | | | 2 | | | | | | | | | | 2 | |
| Revisions
of previous estimates | 57 | | 40 | | 129 | | 78 | | (36 | ) | (35 | ) | 36 | | 1 | | 270 | |
| Improved recovery | | | 8 | | 10 | | 15 | | | | | | | | | | 33 | |
| Extensions
and discoveries | 10 | | 74 | | 38 | | 5 | | | | 44 | | 12 | | 8 | | 191 | |
| Production | (20 | ) | (48 | ) | (105 | ) | (113 | ) | (26 | ) | (21 | ) | (26 | ) | (3 | ) | (362 | ) |
| Sales of
minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2009 | 233 | | 351 | | 895 | | 770 | | 849 | | 94 | | 153 | | 32 | | 3,377 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2008 | | | | | 14 | | 8 | | | | 101 | | 19 | | | | 142 | |
| of
which: developed | | | | | 11 | | 4 | | | | 11 | | 7 | | | | 33 | |
| of which: undeveloped | | | | | 3 | | 4 | | | | 90 | | 12 | | | | 109 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | | | | | | | | | | | | | | |
| Improved
recovery | | | | | | | | | | | | | | | | | | |
| Extensions and discoveries | | | | | 1 | | | | | | | | | | | | 1 | |
| Production | | | | | (2 | ) | (1 | ) | | | | | (3 | ) | | | (6 | ) |
| Sales of minerals in place | | | | | | | | | | | (51 | ) | | | | | (51 | ) |
| Reserves at December 31, 2009 | | | | | 13 | | 7 | | | | 50 | | 16 | | | | 86 | |
| Reserves at December 31, 2009 | 233 | | 351 | | 908 | | 777 | | 849 | | 144 | | 169 | | 32 | | 3,463 | |
| Developed | 141 | | 218 | | 669 | | 548 | | 291 | | 52 | | 93 | | 23 | | 2,035 | |
| Consolidated subsidiaries | 141 | | 218 | | 659 | | 544 | | 291 | | 45 | | 80 | | 23 | | 2,001 | |
| Equity-accounted entities | | | | | 10 | | 4 | | | | 7 | | 13 | | | | 34 | |
| Undeveloped | 92 | | 133 | | 239 | | 229 | | 558 | | 92 | | 76 | | 9 | | 1,428 | |
| Consolidated subsidiaries | 92 | | 133 | | 236 | | 226 | | 558 | | 49 | | 73 | | 9 | | 1,376 | |
| Equity-accounted entities | | | | | 3 | | 3 | | | | 43 | | 3 | | | | 52 | |

i	i	i
(a)	i	Proved
reserves of equity-accounted entities at year end 2008
include 60% of the three former Yukos companies. From
2009, after the 51% call option exercised by Gazprom,
values are reported at 29.4%.

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Movements in net proved liquids reserves (mmbbl)

2010 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2009 | 233 | | 351 | | 895 | | 770 | | 849 | | 94 | | 153 | | 32 | | 3,377 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 141 | | 218 | | 659 | | 544 | | 291 | | 45 | | 80 | | 23 | | 2,001 | |
| of which: undeveloped | 92 | | 133 | | 236 | | 226 | | 558 | | 49 | | 73 | | 9 | | 1,376 | |
| Purchase of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions
of previous estimates | 38 | | 17 | | 178 | | 75 | | (37 | ) | 62 | | 2 | | | | 335 | |
| Improved recovery | | | | | 1 | | 1 | | | | | | | | | | 2 | |
| Extensions
and discoveries | | | 25 | | 13 | | 22 | | | | | | 1 | | | | 61 | |
| Production | (23 | ) | (44 | ) | (108 | ) | (116 | ) | (24 | ) | (17 | ) | (22 | ) | (3 | ) | (357 | ) |
| Sales of
minerals in place | | | | | (1 | ) | (2 | ) | | | | | | | | | (3 | ) |
| Reserves at December 31, 2010 | 248 | | 349 | | 978 | | 750 | | 788 | | 139 | | 134 | | 29 | | 3,415 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2009 | | | | | 13 | | 7 | | | | 50 | | 16 | | | | 86 | |
| of
which: developed | | | | | 10 | | 4 | | | | 7 | | 13 | | | | 34 | |
| of which: undeveloped | | | | | 3 | | 3 | | | | 43 | | 3 | | | | 52 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | 8 | | | | | | (6 | ) | (2 | ) | | | | |
| Improved
recovery | | | | | | | | | | | | | 12 | | | | 12 | |
| Extensions and discoveries | | | | | | | | | | | | | 117 | | | | 117 | |
| Production | | | | | (2 | ) | (1 | ) | | | | | (4 | ) | | | (7 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 19 | | 6 | | | | 44 | | 139 | | | | 208 | |
| Reserves at December 31, 2010 | 248 | | 349 | | 997 | | 756 | | 788 | | 183 | | 273 | | 29 | | 3,623 | |
| Developed | 183 | | 207 | | 674 | | 537 | | 251 | | 44 | | 87 | | 20 | | 2,003 | |
| Consolidated subsidiaries | 183 | | 207 | | 656 | | 533 | | 251 | | 39 | | 62 | | 20 | | 1,951 | |
| Equity-accounted entities | | | | | 18 | | 4 | | | | 5 | | 25 | | | | 52 | |
| Undeveloped | 65 | | 142 | | 323 | | 219 | | 537 | | 139 | | 186 | | 9 | | 1,620 | |
| Consolidated subsidiaries | 65 | | 142 | | 322 | | 217 | | 537 | | 100 | | 72 | | 9 | | 1,464 | |
| Equity-accounted entities | | | | | 1 | | 2 | | | | 39 | | 114 | | | | 156 | |

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Movements in net proved liquids reserves (mmbbl)

2011 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2010 | 248 | | 349 | | 978 | | 750 | | 788 | | 139 | | 134 | | 29 | | 3,415 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 183 | | 207 | | 656 | | 533 | | 251 | | 39 | | 62 | | 20 | | 1,951 | |
| of which: undeveloped | 65 | | 142 | | 322 | | 217 | | 537 | | 100 | | 72 | | 9 | | 1,464 | |
| Purchase of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions
of previous estimates | 34 | | 58 | | 10 | | 14 | | (112 | ) | (20 | ) | 1 | | | | (15 | ) |
| Improved recovery | | | 2 | | 2 | | 2 | | | | | | | | | | 6 | |
| Extensions
and discoveries | | | 9 | | 2 | | 11 | | | | | | 17 | | | | 39 | |
| Production | (23 | ) | (44 | ) | (75 | ) | (100 | ) | (23 | ) | (13 | ) | (20 | ) | (4 | ) | (302 | ) |
| Sales of
minerals in place | | | (2 | ) | | | (7 | ) | | | | | | | | | (9 | ) |
| Reserves at December 31, 2011 | 259 | | 372 | | 917 | | 670 | | 653 | | 106 | | 132 | | 25 | | 3,134 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 19 | | 6 | | | | 44 | | 139 | | | | 208 | |
| of
which: developed | | | | | 18 | | 4 | | | | 5 | | 25 | | | | 52 | |
| of which: undeveloped | | | | | 1 | | 2 | | | | 39 | | 114 | | | | 156 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | | | 11 | | | | 6 | | 11 | | | | 28 | |
| Improved
recovery | | | | | | | | | | | | | 1 | | | | 1 | |
| Extensions and discoveries | | | | | | | 6 | | | | 60 | | 4 | | | | 70 | |
| Production | | | | | (2 | ) | (1 | ) | | | | | (4 | ) | | | (7 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2011 | | | | | 17 | | 22 | | | | 110 | | 151 | | | | 300 | |
| Reserves at December 31, 2011 | 259 | | 372 | | 934 | | 692 | | 653 | | 216 | | 283 | | 25 | | 3,434 | |
| Developed | 184 | | 195 | | 638 | | 487 | | 215 | | 34 | | 117 | | 25 | | 1,895 | |
| Consolidated subsidiaries | 184 | | 195 | | 622 | | 483 | | 215 | | 34 | | 92 | | 25 | | 1,850 | |
| Equity-accounted entities | | | | | 16 | | 4 | | | | | | 25 | | | | 45 | |
| Undeveloped | 75 | | 177 | | 296 | | 205 | | 438 | | 182 | | 166 | | | | 1,539 | |
| Consolidated subsidiaries | 75 | | 177 | | 295 | | 187 | | 438 | | 72 | | 40 | | | | 1,284 | |
| Equity-accounted entities | | | | | 1 | | 18 | | | | 110 | | 126 | | | | 255 | |

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Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves (bcf)

2009 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia (b) America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2008 | 2,844 | | 1,421 | | 6,311 | | 2,084 | | 2,437 | | 911 | | 600 | | 606 | | 17,214 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 2,031 | | 1,122 | | 3,537 | | 1,443 | | 2,005 | | 439 | | 340 | | 221 | | 11,138 | |
| of which: undeveloped | 813 | | 299 | | 2,774 | | 641 | | 432 | | 472 | | 260 | | 385 | | 6,076 | |
| Purchase of minerals in place | | | | | | | 1 | | | | | | 136 | | | | 137 | |
| Revisions
of previous estimates | 97 | | 149 | | (309 | ) | 142 | | (204 | ) | 52 | | 43 | | (17 | ) | (47 | ) |
| Improved recovery | | | 25 | | | | | | | | | | | | | | 25 | |
| Extensions
and discoveries | 1 | | 26 | | 479 | | | | | | 2 | | 7 | | 4 | | 519 | |
| Production | (238 | ) | (239 | ) | (587 | ) | (100 | ) | (94 | ) | (151 | ) | (155 | ) | (18 | ) | (1,582 | ) |
| Sales of
minerals in place | | | (2 | ) | | | | | | | | | (2 | ) | | | (4 | ) |
| Reserves at December 31, 2009 | 2,704 | | 1,380 | | 5,894 | | 2,127 | | 2,139 | | 814 | | 629 | | 575 | | 16,262 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2008 | | | | | 13 | | 2 | | | | 3,000 | | | | | | 3,015 | |
| of
which: developed | | | | | 11 | | 1 | | | | 408 | | | | | | 420 | |
| of which: undeveloped | | | | | 2 | | 1 | | | | 2,592 | | | | | | 2,595 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | 3 | | 3 | | | | 10 | | 2 | | | | 18 | |
| Improved
recovery | | | | | | | | | | | | | | | | | | |
| Extensions and discoveries | | | | | | | 80 | | | | | | | | | | 80 | |
| Production | | | | | (2 | ) | | | | | (12 | ) | | | | | (14 | ) |
| Sales of minerals in place | | | | | | | | | | | (1,511 | ) | | | | | (1,511 | ) |
| Reserves at December 31, 2009 | | | | | 14 | | 85 | | | | 1,487 | | 2 | | | | 1,588 | |
| Reserves at December 31, 2009 | 2,704 | | 1,380 | | 5,908 | | 2,212 | | 2,139 | | 2,301 | | 631 | | 575 | | 17,850 | |
| Developed | 2,001 | | 1,231 | | 3,498 | | 1,468 | | 1,859 | | 756 | | 506 | | 565 | | 11,884 | |
| Consolidated subsidiaries | 2,001 | | 1,231 | | 3,486 | | 1,463 | | 1,859 | | 539 | | 506 | | 565 | | 11,650 | |
| Equity-accounted entities | | | | | 12 | | 5 | | | | 217 | | | | | | 234 | |
| Undeveloped | 703 | | 149 | | 2,410 | | 744 | | 280 | | 1,545 | | 125 | | 10 | | 5,966 | |
| Consolidated subsidiaries | 703 | | 149 | | 2,408 | | 664 | | 280 | | 275 | | 123 | | 10 | | 4,612 | |
| Equity-accounted entities | | | | | 2 | | 80 | | | | 1,270 | | 2 | | | | 1,354 | |

i	i	i
(a)	i	Including
approximately 746 and 769 bcf of natural gas held in
storage at December 31, 2008 and 2009, respectively.
(b)	i	Proved
reserves of equity-accounted entities at year end 2008
include 60% of the three former Yukos companies. From
2009, after the 51% call option exercised by Gazprom,
values are reported at 29.4%.

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Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves (bcf)

2010 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2009 | 2,704 | | 1,380 | | 5,894 | | 2,127 | | 2,139 | | 814 | | 629 | | 575 | | 16,262 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 2,001 | | 1,231 | | 3,486 | | 1,463 | | 1,859 | | 539 | | 506 | | 565 | | 11,650 | |
| of which: undeveloped | 703 | | 149 | | 2,408 | | 664 | | 280 | | 275 | | 123 | | 10 | | 4,612 | |
| Purchase of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions
of previous estimates | 234 | | 48 | | 778 | | 161 | | (179 | ) | 211 | | 41 | | (18 | ) | 1,276 | |
| Improved recovery | | | | | | | | | | | | | | | | | | |
| Extensions
and discoveries | | | 177 | | 146 | | | | | | 4 | | 5 | | 22 | | 354 | |
| Production | (246 | ) | (204 | ) | (609 | ) | (161 | ) | (86 | ) | (158 | ) | (145 | ) | (35 | ) | (1,644 | ) |
| Sales of
minerals in place | (48 | ) | | | (2 | ) | | | | | | | | | | | (50 | ) |
| Reserves at December 31, 2010 | 2,644 | | 1,401 | | 6,207 | | 2,127 | | 1,874 | | 871 | | 530 | | 544 | | 16,198 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2009 | | | | | 14 | | 85 | | | | 1,487 | | 2 | | | | 1,588 | |
| of
which: developed | | | | | 12 | | 5 | | | | 217 | | | | | | 234 | |
| of which: undeveloped | | | | | 2 | | 80 | | | | 1,270 | | 2 | | | | 1,354 | |
| Purchase
of minerals in place | | | | | | | | | | | | | | | | | | |
| Revisions of previous estimates | | | | | 6 | | (1 | ) | | | 44 | | 2 | | | | 51 | |
| Improved
recovery | | | | | | | | | | | | | | | | | | |
| Extensions and discoveries | | | | | 6 | | 34 | | | | | | 18 | | | | 58 | |
| Production | | | | | (2 | ) | | | | | (11 | ) | | | | | (13 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 24 | | 118 | | | | 1,520 | | 22 | | | | 1,684 | |
| Reserves at December 31, 2010 | 2,644 | | 1,401 | | 6,231 | | 2,245 | | 1,874 | | 2,391 | | 552 | | 544 | | 17,882 | |
| Developed | 2,061 | | 1,103 | | 3,122 | | 1,554 | | 1,621 | | 774 | | 437 | | 539 | | 11,211 | |
| Consolidated subsidiaries | 2,061 | | 1,103 | | 3,100 | | 1,550 | | 1,621 | | 560 | | 431 | | 539 | | 10,965 | |
| Equity-accounted entities | | | | | 22 | | 4 | | | | 214 | | 6 | | | | 246 | |
| Undeveloped | 583 | | 298 | | 3,109 | | 691 | | 253 | | 1,617 | | 115 | | 5 | | 6,671 | |
| Consolidated subsidiaries | 583 | | 298 | | 3,107 | | 577 | | 253 | | 311 | | 99 | | 5 | | 5,233 | |
| Equity-accounted entities | | | | | 2 | | 114 | | | | 1,306 | | 16 | | | | 1,438 | |

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

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Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves (bcf)

2011 Italy (a) Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Reserves
at December 31, 2010 | 2,644 | | 1,401 | | 6,207 | | 2,127 | | 1,874 | | 871 | | 530 | | 544 | | 16,198 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| of which: developed | 2,061 | | 1,103 | | 3,100 | | 1,550 | | 1,621 | | 560 | | 431 | | 539 | | 10,965 | |
| of which: undeveloped | 583 | | 298 | | 3,107 | | 577 | | 253 | | 311 | | 99 | | 5 | | 5,233 | |
| Purchase of minerals in place | 9 | | | | | | | | | | | | | | | | 9 | |
| Revisions
of previous estimates | 80 | | 199 | | 436 | | (11 | ) | (142 | ) | (38 | ) | 51 | | 96 | | 671 | |
| Improved recovery | | | 3 | | | | | | | | | | | | | | 3 | |
| Extensions
and discoveries | 4 | | 18 | | 9 | | 18 | | | | | | 131 | | | | 180 | |
| Production | (246 | ) | (196 | ) | (462 | ) | (185 | ) | (84 | ) | (148 | ) | (122 | ) | (36 | ) | (1,479 | ) |
| Sales of
minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2011 | 2,491 | | 1,425 | | 6,190 | | 1,949 | | 1,648 | | 685 | | 590 | | 604 | | 15,582 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2010 | | | | | 24 | | 118 | | | | 1,520 | | 22 | | | | 1,684 | |
| of
which: developed | | | | | 22 | | 4 | | | | 214 | | 6 | | | | 246 | |
| of which: undeveloped | | | | | 2 | | 114 | | | | 1,306 | | 16 | | | | 1,438 | |
| Purchase
of minerals in place | | | 2 | | | | | | | | | | | | | | 2 | |
| Revisions of previous estimates | | | | | (2 | ) | 147 | | | | 372 | | 11 | | | | 528 | |
| Improved
recovery | | | | | | | | | | | | | | | | | | |
| Extensions and discoveries | | | | | | | 74 | | | | 1,150 | | 1,274 | | | | 2,498 | |
| Production | | | | | (2 | ) | (1 | ) | | | (9 | ) | | | | | (12 | ) |
| Sales of minerals in place | | | | | | | | | | | | | | | | | | |
| Reserves at December 31, 2011 | | | 2 | | 20 | | 338 | | | | 3,033 | | 1,307 | | | | 4,700 | |
| Reserves at December 31, 2011 | 2,491 | | 1,427 | | 6,210 | | 2,287 | | 1,648 | | 3,718 | | 1,897 | | 604 | | 20,282 | |
| Developed | 1,977 | | 995 | | 3,087 | | 1,441 | | 1,480 | | 552 | | 393 | | 491 | | 10,416 | |
| Consolidated subsidiaries | 1,977 | | 995 | | 3,070 | | 1,437 | | 1,480 | | 528 | | 385 | | 491 | | 10,363 | |
| Equity-accounted entities | | | | | 17 | | 4 | | | | 24 | | 8 | | | | 53 | |
| Undeveloped | 514 | | 432 | | 3,123 | | 846 | | 168 | | 3,166 | | 1,504 | | 113 | | 9,866 | |
| Consolidated subsidiaries | 514 | | 430 | | 3,120 | | 512 | | 168 | | 157 | | 205 | | 113 | | 5,219 | |
| Equity-accounted entities | | | 2 | | 3 | | 334 | | | | 3,009 | | 1,299 | | | | 4,647 | |

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

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Results of operations from oil & gas producing activities (a) (euro million)

2009 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

Consolidated subsidiaries
Revenues:
- sales to consolidated entities	2,274		2,583		1,738		4,386		245		41		808		29		12,104
- sales to
third parties			540		5,037		586		739		1,208		639		181		8,930
Total revenues	2,274		3,123		6,775		4,972		984		1,249		1,447		210		21,034
Operations
costs	(271	)	(517	)	(553	)	(749	)	(153	)	(78	)	(273	)	(41	)	(2,635	)
Production taxes	(148	)			(20	)	(445	)			(34	)					(647	)
Exploration
expenses	(40	)	(114	)	(319	)	(451	)	(20	)	(204	)	(341	)	(62	)	(1,551	)
D.D. & A. and Provision for abandonment (b)	(463	)	(921	)	(956	)	(1,502	)	(78	)	(535	)	(1,108	)	(186	)	(5,749	)
Other
income (expenses)	(125	)	(134	)	(471	)	(467	)	(186	)	(17	)	170		(47	)	(1,277	)
Pretax income from producing
activities	1,227		1,437		4,456		1,358		547		381		(105	)	(126	)	9,175
Income
taxes	(467	)	(833	)	(3,010	)	(1,042	)	(180	)	(67	)	(2	)	23		(5,578	)
Results of operations from
E&P activities of consolidated subsidiaries (c)	760		604		1,446		316		367		314		(107	)	(103	)	3,597
Equity-accounted entities
Revenues:
- sales to
consolidated entities
- sales to third parties					15		45				49		123				232
Total revenues					15		45				49		123				232
Operations costs					(11	)	(7	)			(7	)	(9	)			(34	)
Production
taxes					(3	)							(41	)			(44	)
Exploration expenses					(6	)	(1	)			(8	)	(26	)			(41	)
D.D. &
A. and Provision for abandonment					(1	)	(15	)			(35	)	(25	)			(76	)
Other income (expenses)					1		6				(11	)	(37	)			(41	)
Pretax income from producing activities					(5	)	28				(12	)	(15	)			(4	)
Income taxes					4		(14	)			(10	)	(20	)			(40	)
Results of operations from
E&P activities of equity-accounted entities (c)					(1	)	14				(22	)	(35	)			(44	)

i	i	i
(a)	i	Results of
operations from oil and gas producing activities,
represent only those revenues and expenses directly
associated with such activities, including operating
overheads. These amounts do not include any allocation of
interest expense or general corporate overhead and,
therefore, are not necessarily indicative of the
contributions to consolidated net earnings of Eni.
Related income taxes are computed by applying the local
income tax rates to the pre-tax income from producing
activities. Eni is a party to certain Production Sharing
Agreements (PSAs), whereby a portion of Enis share
of oil and gas production is withheld and sold by its
joint venture partners which are state-owned entities,
with proceeds being remitted to the state in satisfaction
of Enis PSA related tax liabilities. Revenue and
income taxes include such taxes owed by Eni but paid by
state-owned entities out of Enis share of oil and
gas production.
(b)	i	Includes
asset impairments amounting to euro 576 million in 2009.
(c)	i	The
"Successful Effort Method" application would
have led to an increase of result of operations of euro
320 million for the consolidated subsidiaries and an
increase of euro 26 million for equity-accounted
entities.

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Eni Fact Book Supplemental oil and gas information

Results of operations from oil & gas producing activities (euro million)

2010 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

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

i	i	i
(a)	i	Includes
asset impairments amounting to euro 123 million.
(b)	i	The
"Successful Effort Method" application would
have led to a decrease of euro 385 million for the
consolidated subsidiaries and a decrease of euro 5
million for equity-accounted entities.

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Results of operations from oil & gas producing activities (euro million)

2011 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

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

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

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Capitalized costs (a) (euro million)

2010 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Proved
mineral interests | 10,576 | | 10,616 | | 14,051 | | 17,057 | | 1,989 | | 5,552 | | 6,617 | | 1,674 | | 68,132 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Unproved mineral interests | 32 | | 320 | | 570 | | 2,006 | | 39 | | 1,561 | | 1,979 | | 42 | | 6,549 | |
| Support
equipment and facilities | 270 | | 33 | | 1,391 | | 716 | | 70 | | 21 | | 53 | | 6 | | 2,560 | |
| Incomplete wells and other | 909 | | 584 | | 2,069 | | 1,089 | | 4,644 | | 107 | | 1,444 | | 84 | | 10,930 | |
| Gross capitalized costs | 11,787 | | 11,553 | | 18,081 | | 20,868 | | 6,742 | | 7,241 | | 10,093 | | 1,806 | | 88,171 | |
| Accumulated depreciation, depletion and
amortization | (8,020 | ) | (7,771 | ) | (8,558 | ) | (11,067 | ) | (756 | ) | (4,699 | ) | (5,591 | ) | (522 | ) | (46,984 | ) |
| Net capitalized costs
consolidated subsidiaries (b) (c) | 3,767 | | 3,782 | | 9,523 | | 9,801 | | 5,986 | | 2,542 | | 4,502 | | 1,284 | | 41,187 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Proved mineral interests | | | | | 79 | | 191 | | | | 479 | | 178 | | | | 927 | |
| Unproved
mineral interests | | | | | | | | | | | 469 | | | | | | 469 | |
| Support equipment and facilities | | | | | 7 | | | | | | 6 | | 3 | | | | 16 | |
| Incomplete
wells and other | | | | | | | 332 | | | | 139 | | 197 | | | | 668 | |
| Gross capitalized costs | | | | | 86 | | 523 | | | | 1,093 | | 378 | | | | 2,080 | |
| Accumulated
depreciation, depletion and amortization | | | | | (73 | ) | (103 | ) | | | (350 | ) | (66 | ) | | | (592 | ) |
| Net capitalized costs
equity-accounted entities (b) (c) | | | | | 13 | | 420 | | | | 743 | | 312 | | | | 1,488 | |
| 2011 | | | | | | | | | | | | | | | | | | |
| Consolidated subsidiaries | | | | | | | | | | | | | | | | | | |
| Proved
mineral interests | 11,356 | | 11,481 | | 15,519 | | 19,539 | | 2,523 | | 6,136 | | 8,976 | | 1,889 | | 77,419 | |
| Unproved mineral interests | 31 | | 325 | | 582 | | 2,893 | | 40 | | 1,543 | | 1,409 | | 204 | | 7,027 | |
| Support
equipment and facilities | 285 | | 34 | | 1,442 | | 923 | | 85 | | 41 | | 61 | | 13 | | 2,884 | |
| Incomplete wells and other | 956 | | 1,778 | | 2,755 | | 898 | | 5,333 | | 136 | | 1,029 | | | | 12,885 | |
| Gross capitalized costs | 12,628 | | 13,618 | | 20,298 | | 24,253 | | 7,981 | | 7,856 | | 11,475 | | 2,106 | | 100,215 | |
| Accumulated depreciation, depletion and
amortization | (8,633 | ) | (8,582 | ) | (9,750 | ) | (13,069 | ) | (906 | ) | (5,411 | ) | (6,806 | ) | (650 | ) | (53,807 | ) |
| Net capitalized costs
consolidated subsidiaries (b) (c) | 3,995 | | 5,036 | | 10,548 | | 11,184 | | 7,075 | | 2,445 | | 4,669 | | 1,456 | | 46,408 | |
| Equity-accounted entities | | | | | | | | | | | | | | | | | | |
| Proved mineral interests | | | 2 | | 80 | | 240 | | | | 698 | | 330 | | | | 1,350 | |
| Unproved
mineral interests | | | 44 | | | | | | | | 271 | | | | | | 315 | |
| Support equipment and facilities | | | | | 8 | | | | | | 6 | | 3 | | | | 17 | |
| Incomplete
wells and other | | | 2 | | 1 | | 1,011 | | | | 185 | | 223 | | | | 1,422 | |
| Gross capitalized costs | | | 48 | | 89 | | 1,251 | | | | 1,160 | | 556 | | | | 3,104 | |
| Accumulated
depreciation, depletion and amortization | | | (2 | ) | (74 | ) | (131 | ) | | | (388 | ) | (89 | ) | | | (684 | ) |
| Net capitalized costs
equity-accounted entities (b) (c) | | | 46 | | 15 | | 1,120 | | | | 772 | | 467 | | | | 2,420 | |

i	i	i
(a)	i	Capitalized
costs represent the total expenditures for proved and
unproved mineral interests and related support equipment
and facilities utilized in oil and gas exploration and
production activities, together with related accumulated
depreciation, depletion and amortization.
(b)	i	The amounts
include net capitalized financial charges totaling euro
591 million in 2010 and euro 614 million in 2011 for the
consolidated subsidiaries and euro 6 million in 2010 and
euro 11 million in 2011 for equity-accounted entities.
(c)	i	The amounts
do not include costs associated with exploration
activities which are capitalized in order to reflect
their investment nature and amortized in full when
incurred. The "Successful Effort Method"
application would have led to an increase in net
capitalized costs of euro 3,410 million in 2010 and euro
3,608 million in 2011 for the consolidated subsidiaries
and of euro 76 million in 2010 and euro 101 million in
2011 for equity-accounted entities.

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Eni Fact Book Supplemental oil and gas information

Costs incurred (a) (euro million)

2009 Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

| Consolidated subsidiaries — Proved
property acquisitions | | | 298 | 27 | | 11 | 131 | | 467 |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Unproved property acquisitions | | | 54 | 42 | | 83 | 43 | | 222 |
| Exploration | 40 | 114 | 317 | 284 | 20 | 159 | 242 | 52 | 1,228 |
| Development (b) | 742 | 727 | 1,401 | 2,121 | 1,086 | 423 | 858 | 462 | 7,820 |
| Total costs incurred
consolidated subsidiaries | 782 | 841 | 2,070 | 2,474 | 1,106 | 676 | 1,274 | 514 | 9,737 |
| Equity-accounted entities | | | | | | | | | |
| Proved property acquisitions | | | | | | | | | |
| Unproved
property acquisitions | | | | | | | | | |
| Exploration | | | 6 | 1 | | 9 | 25 | | 41 |
| Development (c) | | | 3 | 62 | | 94 | 47 | | 206 |
| Total costs incurred
equity-accounted entities | | | 9 | 63 | | 103 | 72 | | 247 |
| 2010 | | | | | | | | | |
| Consolidated subsidiaries | | | | | | | | | |
| Proved
property acquisitions | | | | | | | | | |
| Unproved property acquisitions | | | | | | | | | |
| Exploration | 34 | 114 | 84 | 406 | 6 | 223 | 119 | 26 | 1,012 |
| Development (b) | 579 | 890 | 2,674 | 1,909 | 1,031 | 359 | 1,309 | 160 | 8,911 |
| Total costs incurred
consolidated subsidiaries | 613 | 1,004 | 2,758 | 2,315 | 1,037 | 582 | 1,428 | 186 | 9,923 |
| Equity-accounted entities | | | | | | | | | |
| Proved property acquisitions | | | | | | | | | |
| Unproved
property acquisitions | | | | | | | | | |
| Exploration | | | 4 | 2 | | 4 | 35 | | 45 |
| Development (c) | | | 7 | 200 | | 46 | 114 | | 367 |
| Total costs incurred
equity-accounted entities | | | 11 | 202 | | 50 | 149 | | 412 |
| 2011 | | | | | | | | | |
| Consolidated subsidiaries | | | | | | | | | |
| Proved
property acquisitions | | | | | | | | | |
| Unproved property acquisitions | | | 57 | 697 | | | | | 754 |
| Exploration | 38 | 100 | 128 | 482 | 6 | 156 | 60 | 240 | 1,210 |
| Development (b) | 815 | 1,921 | 1,487 | 1,698 | 935 | 385 | 971 | 70 | 8,282 |
| Total costs incurred
consolidated subsidiaries | 853 | 2,021 | 1,672 | 2,877 | 941 | 541 | 1,031 | 310 | 10,246 |
| Equity-accounted entities | | | | | | | | | |
| Proved property acquisitions | | | | | | | | | |
| Unproved
property acquisitions | | | | | | | | | |
| Exploration | | 5 | | 5 | | 8 | 9 | | 27 |
| Development (c) | | 2 | 3 | 659 | | 68 | 154 | | 886 |
| Total costs incurred
equity-accounted entities | | 7 | 3 | 664 | | 76 | 163 | | 913 |

i	i	i
(a)	i	Costs
incurred represent amounts both capitalized and expensed
in connection with oil and gas producing activities.
(b)	i	Includes the
abandonment costs of the assets for euro 301 million in
2009, euro 269 million in 2010 and euro 918 million in
2011.
(c)	i	Includes the
abandonment costs of the assets for euro -6 million in
2009, euro -3 million in 2010 and euro 15 million in
2011.

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Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and are determined by applying year-end prices of oil and gas for the year ended December 31, 2008, and the average prices during the years ended December 31, 2009, 2010 and 2011 to estimated future production of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - oil&gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Enis proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

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Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows (euro million)

Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

December 31, 2009
Consolidated subsidiaries
Future
cash inflows	26,243		22,057		59,413		33,676		30,273		5,680		7,088		2,973		187,403
Future production costs	(4,732	)	(6,215	)	(7,771	)	(9,737	)	(6,545	)	(1,427	)	(1,797	)	(529	)	(38,753	)
Future
development and abandonment costs	(5,143	)	(5,375	)	(8,618	)	(5,134	)	(4,345	)	(1,409	)	(1,897	)	(214	)	(32,135	)
Future net inflow before
income tax	16,368		10,467		43,024		18,805		19,383		2,844		3,394		2,230		116,515
Future
income tax	(5,263	)	(6,621	)	(24,230	)	(9,894	)	(4,827	)	(636	)	(694	)	(563	)	(52,728	)
Future net cash flows	11,105		3,846		18,794		8,911		14,556		2,208		2,700		1,667		63,787
10%
discount factor	(5,868	)	(1,455	)	(9,160	)	(3,102	)	(10,249	)	(520	)	(1,162	)	(771	)	(32,287	)
Standardized measure of
discounted future net cash flows	5,237		2,391		9,634		5,809		4,307		1,688		1,538		896		31,500
Equity-accounted entities
Future cash inflows					250		427				2,389		652				3,718
Future
production costs					(147	)	(70	)			(773	)	(261	)			(1,251	)
Future development and abandonment costs					(21	)	(137	)			(970	)	(40	)			(1,168	)
Future net inflow before income tax					82		220				646		351				1,299
Future income tax					(1	)	(45	)			(260	)	(126	)			(432	)
Future net cash flows					81		175				386		225				867
10% discount factor					(28	)	(80	)			(420	)	(82	)			(610	)
Standardized measure of
discounted future net cash flows					53		95				(34	)	143				257
Total	5,237		2,391		9,687		5,904		4,307		1,654		1,681		896		31,757
December 31, 2010
Consolidated subsidiaries
Future
cash inflows	30,047		27,973		86,728		45,790		41,053		9,701		8,546		3,846		253,684
Future production costs	(4,865	)	(7,201	)	(12,896	)	(13,605	)	(6,686	)	(3,201	)	(2,250	)	(611	)	(51,315	)
Future
development and abandonment costs	(4,499	)	(6,491	)	(8,827	)	(5,310	)	(5,192	)	(3,489	)	(1,713	)	(221	)	(35,742	)
Future net inflow before
income tax	20,683		14,281		65,005		26,875		29,175		3,011		4,583		3,014		166,627
Future
income tax	(6,289	)	(9,562	)	(37,108	)	(14,468	)	(7,213	)	(872	)	(910	)	(805	)	(77,227	)
Future net cash flows	14,394		4,719		27,897		12,407		21,962		2,139		3,673		2,209		89,400
10%
discount factor	(7,224	)	(1,608	)	(13,117	)	(3,884	)	(14,829	)	(419	)	(1,392	)	(850	)	(43,323	)
Standardized measure of
discounted future net cash flows	7,170		3,111		14,780		8,523		7,133		1,720		2,281		1,359		46,077
Equity-accounted entities
Future cash inflows					498		750				2,893		7,363				11,504
Future
production costs					(251	)	(98	)			(972	)	(2,676	)			(3,997	)
Future development and abandonment costs					(35	)	(128	)			(879	)	(1,188	)			(2,230	)
Future net inflow before income tax					212		524				1,042		3,499				5,277
Future income tax					(2	)	(69	)			(338	)	(2,145	)			(2,554	)
Future net cash flows					210		455				704		1,354				2,723
10% discount factor					(113	)	(160	)			(515	)	(852	)			(1,640	)
Standardized measure of
discounted future net cash flows					97		295				189		502				1,083
Total	7,170		3,111		14,877		8,818		7,133		1,909		2,783		1,359		47,160

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Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows (euro million)

Italy Rest of Europe North Africa Sub-Saharan Africa Kazakhstan Rest of Asia America Australia and Oceania Total

December 31, 2011
Consolidated subsidiaries
Future
cash inflows	38,200		37,974		109,825		59,263		50,443		10,403		11,980		5,185		323,273
Future production costs	(5,740	)	(7,666	)	(17,627	)	(15,191	)	(7,845	)	(3,852	)	(2,687	)	(813	)	(61,421	)
Future
development and abandonment costs	(4,712	)	(7,059	)	(9,639	)	(5,734	)	(3,705	)	(2,842	)	(1,836	)	(224	)	(35,751	)
Future net inflow before
income tax	27,748		23,249		82,559		38,338		38,893		3,709		7,457		4,148		226,101
Future
income tax	(9,000	)	(15,912	)	(46,676	)	(23,075	)	(9,866	)	(1,124	)	(2,474	)	(1,254	)	(109,381	)
Future net cash flows	18,748		7,337		35,883		15,263		29,027		2,585		4,983		2,894		116,720
10%
discount factor	(9,692	)	(2,572	)	(16,191	)	(4,833	)	(17,599	)	(559	)	(1,914	)	(1,122	)	(54,482	)
Standardized measure of
discounted future net cash flows	9,056		4,765		19,692		10,430		11,428		2,026		3,069		1,772		62,238
Equity-accounted entities
Future cash inflows			21		649		1,866				6,141		15,067				23,744
Future
production costs			(5	)	(259	)	(471	)			(1,540	)	(4,598	)			(6,873	)
Future development and abandonment costs			(2	)	(36	)	(147	)			(1,247	)	(1,754	)			(3,186	)
Future net inflow before income tax			14		354		1,248				3,354		8,715				13,685
Future income tax			(3	)	(3	)	(189	)			(824	)	(5,368	)			(6,387	)
Future net cash flows			11		351		1,059				2,530		3,347				7,298
10% discount factor					(183	)	(475	)			(1,825	)	(2,155	)			(4,638	)
Standardized measure of
discounted future net cash flows			11		168		584				705		1,192				2,660
Total	9,056		4,776		19,860		11,014		11,428		2,731		4,261		1,772		64,898

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Eni Fact Book Supplemental oil and gas information

Changes in standardized measure of discounted future net cash flows (euro million)

Total consolidated subsidiaries Total equity- accounted entities Total

| Standardized measure of discounted future net
cash flows at December 31, 2008 | 31,452 | | 38 | | 31,490 | |
| --- | --- | --- | --- | --- | --- | --- |
| Increase (Decrease): | | | | | | |
| - sales,
net of production costs | (17,752 | ) | (154 | ) | (17,906 | ) |
| - net changes in sales and transfer prices, net
of production costs | 4,515 | | 286 | | 4,801 | |
| -
extensions, discoveries and improved recovery, net of
future production and development costs | 3,587 | | 22 | | 3,609 | |
| - changes in estimated future development and
abandonment costs | (9,915 | ) | (157 | ) | (10,072 | ) |
| -
development costs incurred during the period that reduced
future development costs | 7,401 | | 208 | | 7,609 | |
| - revisions of quantity estimates | 4,686 | | (113 | ) | 4,573 | |
| -
accretion of discount | 6,112 | | 29 | | 6,141 | |
| - net change in income taxes | 674 | | (67 | ) | 607 | |
| - purchase
of reserves in-place | 161 | | | | 161 | |
| - sale of reserves in-place | (7 | ) | 81 | | 74 | |
| - changes
in production rates (timing) and other | 586 | | 84 | | 670 | |
| Net increase (decrease) | 48 | | 219 | | 267 | |
| Standardized measure of discounted future net
cash flows at December 31, 2009 | 31,500 | | 257 | | 31,757 | |
| Increase (Decrease): | | | | | | |
| - sales,
net of production costs | (22,194 | ) | (243 | ) | (22,437 | ) |
| - net changes in sales and transfer prices, net
of production costs | 24,415 | | 406 | | 24,821 | |
| -
extensions, discoveries and improved recovery, net of
future production and development costs | 1,926 | | 1,409 | | 3,335 | |
| - changes in estimated future development and
abandonment costs | (6,464 | ) | (386 | ) | (6,850 | ) |
| -
development costs incurred during the period that reduced
future development costs | 8,520 | | 368 | | 8,888 | |
| - revisions of quantity estimates | 12,600 | | 143 | | 12,743 | |
| -
accretion of discount | 6,519 | | 53 | | 6,572 | |
| - net change in income taxes | (11,802 | ) | (1,115 | ) | (12,917 | ) |
| - purchase
of reserves in-place | | | | | | |
| - sale of reserves in-place | (177 | ) | | | (177 | ) |
| - changes
in production rates (timing) and other | 1,234 | | 191 | | 1,425 | |
| Net increase (decrease) | 14,577 | | 826 | | 15,403 | |
| Standardized measure of discounted future net
cash flows at December 31, 2010 | 46,077 | | 1,083 | | 47,160 | |
| Increase (Decrease): | | | | | | |
| - sales,
net of production costs | (23,744 | ) | (300 | ) | (24,044 | ) |
| - net changes in sales and transfer prices, net
of production costs | 40,961 | | 442 | | 41,403 | |
| -
extensions, discoveries and improved recovery, net of
future production and development costs | 1,580 | | 2,457 | | 4,037 | |
| - changes in estimated future development and
abandonment costs | (3,890 | ) | (392 | ) | (4,282 | ) |
| -
development costs incurred during the period that reduced
future development costs | 7,301 | | 866 | | 8,167 | |
| - revisions of quantity estimates | 1,337 | | (87 | ) | 1,250 | |
| -
accretion of discount | 8,640 | | 235 | | 8,875 | |
| - net change in income taxes | (17,067 | ) | (1,678 | ) | (18,745 | ) |
| - purchase
of reserves in-place | 37 | | 10 | | 47 | |
| - sale of reserves in-place | (146 | ) | | | (146 | ) |
| - changes
in production rates (timing) and other | 1,152 | | 24 | | 1,176 | |
| Net increase (decrease) | 16,161 | | 1,577 | | 17,738 | |
| Standardized measure of discounted future net
cash flows at December 31, 2011 | 62,238 | | 2,660 | | 64,898 | |

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Eni Fact Book Quarterly information

Quarterly information

Main financial data (a) (euro million)

2009 2010 2011

I Q II Q III Q IV Q I Q II Q III Q IV Q I Q II Q III Q IV Q

| Net sales from operations — Operating
income: | 23,741 — 3,967 | | 18,267 — 2,405 | | 19,142 — 3,217 | | 22,077 — 2,466 | | 83,227 — 12,055 | | 24,804 — 4,847 | | 22,902 — 4,305 | | 22,704 — 4,084 | | 28,113 — 2,875 | | 98,523 — 16,111 | | 28,779 — 5,638 | | 24,596 — 3,810 | | 26,112 — 4,504 | | 30,102 — 3,483 | | 109,589 — 17,435 | |
| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
| Exploration & Production | 2,374 | | 1,778 | | 2,557 | | 2,411 | | 9,120 | | 3,297 | | 3,401 | | 3,369 | | 3,799 | | 13,866 | | 4,106 | | 3,693 | | 3,919 | | 4,169 | | 15,887 | |
| Gas
& Power | 1,253 | | 863 | | 567 | | 1,004 | | 3,687 | | 1,316 | | 592 | | 438 | | 550 | | 2,896 | | 910 | | 184 | | 338 | | 326 | | 1,758 | |
| Refining & Marketing | 240 | | 47 | | 34 | | (423 | ) | (102 | ) | 105 | | 255 | | (65 | ) | (146 | ) | 149 | | 303 | | 73 | | 32 | | (681 | ) | (273 | ) |
| Petrochemicals | (167 | ) | (287 | ) | (60 | ) | (161 | ) | (675 | ) | 36 | | 17 | | 24 | | (163 | ) | (86 | ) | 108 | | (113 | ) | (122 | ) | (297 | ) | (424 | ) |
| Engineering & Construction | 270 | | 310 | | 274 | | 27 | | 881 | | 291 | | 334 | | 327 | | 350 | | 1,302 | | 354 | | 366 | | 304 | | 398 | | 1,422 | |
| Other
activities (b) | (55 | ) | (122 | ) | (28 | ) | (231 | ) | (436 | ) | (60 | ) | (115 | ) | (58 | ) | (1,151 | ) | (1,384 | ) | (27 | ) | (138 | ) | (79 | ) | (183 | ) | (427 | ) |
| Corporate and financial companies (b) | (63 | ) | (124 | ) | (134 | ) | (99 | ) | (420 | ) | (70 | ) | (82 | ) | (47 | ) | (162 | ) | (361 | ) | (112 | ) | (76 | ) | (85 | ) | (46 | ) | (319 | ) |
| Unrealized
profit intragroup elimination | 115 | | (60 | ) | 7 | | (62 | ) | | | (68 | ) | (97 | ) | 96 | | (202 | ) | (271 | ) | (4 | ) | (179 | ) | 197 | | (203 | ) | (189 | ) |
| Net income | 1,904 | | 832 | | 1,240 | | 391 | | 4,367 | | 2,222 | | 1,824 | | 1,724 | | 548 | | 6,318 | | 2,547 | | 1,254 | | 1,770 | | 1,289 | | 6,860 | |
| Capital
expenditures | 3,147 | | 3,697 | | 2,957 | | 3,894 | | 13,695 | | 2,779 | | 4,328 | | 2,851 | | 3,912 | | 13,870 | | 2,875 | | 3,740 | | 2,929 | | 3,894 | | 13,438 | |
| Investments | 2,039 | | 175 | | 63 | | 46 | | 2,323 | | 39 | | 76 | | 186 | | 109 | | 410 | | 41 | | 87 | | 92 | | 140 | | 360 | |
| Net
borrowings at period end | 16,528 | | 18,355 | | 20,540 | | 23,055 | | 23,055 | | 21,052 | | 23,342 | | 25,261 | | 26,119 | | 26,119 | | 24,951 | | 25,978 | | 28,273 | | 28,032 | | 28,032 | |

i	i	i
(a)	i	Quarterly
data are unaudited.
(b)	i	From 2010
certain environmental provisions incurred by the Parent
Company Eni SpA due to inter-company guarantees on behalf
of Syndial have been reported within the segment
reporting unit "Other Activities". Prior-year
data have been reclassified to allow result
comparability.

Key market indicator

2009 2010 2011

I Q II Q III Q IV Q I Q II Q III Q IV Q I Q II Q III Q IV Q

Average price of Brent dated crude oil (a)	44.40	58.79	68.28	74.57	61.51	76.24	78.30	76.86	86.48	79.47	104.97	117.36	113.46	109.31	111.27
Average
EUR/USD exchange rate	1.302	1.362	1.431	1.478	1.393	1.384	1.273	1.291	1.359	1.327	1.367	1.439	1.413	1.348	1.392
Average price in euro of Brent dated crude oil (b)	34.10	43.16	47.71	50.45	44.16	55.09	61.51	59.54	63.64	59.89	76.79	81.56	80.30	81.09	79.94
Average
European refining margin (c)	5.34	3.61	2.34	1.24	3.13	2.40	3.39	2.09	2.74	2.66	1.74	1.09	2.87	2.52	2.06
Average European refining margins Brent/Ural (c)	6.28	3.90	2.26	1.80	3.56	3.20	4.56	2.48	3.78	3.47	3.35	2.20	2.92	3.13	2.90
Average
European refining margins in euro	4.10	2.65	1.64	0.84	2.25	1.74	2.66	1.62	2.02	2.00	1.27	0.75	2.03	1.87	1.48
Price of NBP gas	6.76	4.26	3.55	4.54	4.78	5.61	5.68	6.68	8.29	6.56	9.09	9.36	8.74	8.92	9.03
Euribor -
three-month euro rate (%)	2.0	1.3	0.8	0.7	1.2	0.6	0.7	0.9	1.0	0.8	1.1	1.4	1.6	1.5	1.4
Libor - three-month dollar rate (%)	1.2	0.9	0.4	0.3	0.7	0.3	0.4	0.4	0.3	0.3	0.3	0.3	0.3	0.5	0.3

i	i	i
(a)	i	In US$ per
barrel. Source: Platts Oilgram.
(b)	i	Eni
calculation.
(c)	i	In US$ per
barrel FOB Mediterranean Brent dated crude oil. Eni
elaborations on Platts Oilgram data.

110 -

Contents

Eni Fact Book Quarterly information

Main operating data

2009 2010 2011

I Q II Q III Q IV Q I Q II Q III Q IV Q I Q II Q III Q IV Q

Liquids production	(kbbl/d)	1,013	986	957	1,073	1,007	1,011	980	948	1,049	997	899	793	793	896	845
Natural
gas production	(mmcf/d)	4,398	4,290	4,139	4,668	4,374	4,615	4,319	4,203	5,021	4,540	4,356	3,867	3,773	4,345	4,085
Hydrocarbons production	(kboe/d)	1,779	1,733	1,678	1,886	1,769	1,842	1,758	1,705	1,954	1,815	1,684	1,489	1,473	1,678	1,581
Italy		174	169	161	173	169	182	185	182	182	183	186	172	193	191	186
Rest of Europe		256	246	230	255	247	243	208	200	236	222	224	221	203	217	216
North
Africa		595	567	567	565	573	589	583	549	688	602	505	384	367	497	438
Sub-Saharan
Africa		330	343	344	421	360	402	388	407	403	400	375	356	364	381	369
Kazakhstan		119	121	106	117	115	121	107	85	117	108	117	106	96	105	106
Rest of Asia		150	138	122	130	135	122	123	125	155	131	120	104	103	121	112
America		135	133	132	209	153	159	139	128	145	143	131	122	121	128	126
Australia and
Oceania		20	16	16	16	17	24	25	29	28	26	26	24	26	38	28
Production
sold	(mmboe)	154.2	154.2	147.6	166.8	622.8	158.6	154.1	151.7	173.6	638.0	145.7	129.1	130.0	143.7	548.5
Sales of natural gas to third parties	(bcm)	28.34	17.54	19.45	24.63	89.96	26.51	15.62	14.95	24.38	81.46	27.87	17.33	14.59	21.23	81.02
Own
consumption of natural gas		1.51	1.25	1.55	1.50	5.81	1.54	1.53	1.56	1.56	6.19	1.65	1.53	1.41	1.62	6.21
Sales to third parties and own consumption		29.85	18.79	21.00	26.13	95.77	28.05	17.15	16.51	25.94	87.65	29.52	18.86	16.00	22.85	87.23
Sales of
natural gas of Enis affiliates (net to Eni)		2.50	1.67	1.52	2.26	7.95	2.46	2.04	2.09	2.82	9.41	2.81	2.14	1.96	2.62	9.53
Total sales and own consumption of natural gas		32.35	20.46	22.52	28.39	103.72	30.51	19.19	18.60	28.76	97.06	32.33	21.00	17.96	25.47	96.76
Volumes
transported on behalf of third parties in Italy		7.78	7.57	9.19	9.42	33.96	9.00	9.61	10.70	10.23	39.54	9.68	9.66	9.55	11.39	40.28
Electricity sales	(TWh)	10.97	11.16	11.34	12.12	45.59	10.87	11.77	12.01	12.15	46.80	10.34	11.03	13.16	10.49	45.02
Sales of
refined products:	(mmtonnes)	2.10	2.31	2.36	2.26	9.03	2.01	2.17	2.28	2.17	8.63	1.94	2.14	2.23	2.05	8.36
Retail sales in
Italy		2.41	2.25	2.43	2.47	9.56	2.04	2.33	2.50	2.58	9.45	2.19	2.22	2.47	2.48	9.36
Wholesale
sales in Italy		0.69	0.76	0.80	0.74	2.99	0.67	0.77	0.91	0.75	3.10	0.70	0.76	0.80	0.75	3.01
Retail sales
Rest of Europe		0.91	0.85	0.94	0.96	3.66	0.86	0.97	1.06	0.99	3.88	0.81	0.97	1.08	0.98	3.84
Wholesale
sales outside Italy		0.09	0.12	0.10	0.10	0.41	0.09	0.11	0.11	0.11	0.42	0.10	0.11	0.11	0.11	0.43
Other sales		4.77	4.87	4.71	5.59	19.94	5.20	5.42	5.15	5.55	21.32	4.60	4.83	6.47	4.12	20.02

111 -

Contents

Table of Contents

Ordinary and Extraordinary Shareholders Meeting resolutions

Eni S.p.A. Ordinary and Extraordinary Shareholders Meeting held on May 8, 2012 resolved: to approve Eni Financial statements at December 31, 2011, which report net profit amounting to 4,212,687,003.27 euro; to allocate euro 2,328,880,900.91 of Eni 2011 profit of euro 4,212,687,003.27 left after the payment of an interim dividend of euro 0.52 per share resolved by the Board of Directors on September 8, 2011, as follows: - to pay a dividend of 0.52 euro for each share owned and outstanding on the coupon detachment date, excluding treasury shares in the portfolio on that date. Therefore, in consideration of the payment of the 2011 interim dividend of 0.52 euro per share, the 2011 dividend per share amounts to 1.04 euro; - to the legal Reserve the amount remaining following the distribution of the proposed dividend; to pay the balance of the 2011 dividend beginning on May 24, 2012, with coupon detachment set for May 21, 2012; in favor of the first section of the Remuneration report regarding the companys policy on the remuneration of board directors, general managers and executives with strategic responsibilities and the procedures used to adopt and implement this policy; to approve the amendments to Articles 17.3, 17.5 and 28.2 of the By-laws of Eni S.p.A. and the addition of the new article 34. Documents to be distributed Enis Annual Report 2011 (Italian Edition) including the financial statements of Eni, approved by the Shareholders Meeting, the consolidated financial statements, the reports of the Directors, the certification pursuant to article 154- bis , paragraph 5, of legislative Decree 58/1998, the report of the statutory auditors, the report of the external auditors, the 2011 sustainability reporting and the related Independent Assurance Report is available at Eni S.p.A. Registered Office and Borsa Italiana S.p.A. (Italian Stock Exchange: www.borsaitaliana.it). The minutes of the Meeting will be available under law provisions at Eni S.p.A. Registered Office and Borsa Italiana S.p.A. (Italian Stock Exchange: www.borsaitaliana.it). The Report on corporate governance and shareholding structure and the Remuneration report are also available at Eni S.p.A. Registered Office and Borsa Italiana S.p.A. (Italian Stock Exchange: www.borsaitaliana.it). The above-mentioned documents are also available free of charge on the Company website (www.eni.com) and may be requested by e-mail at [email protected] or by calling the Toll-Free number 800 940 924 for calls from Italy and 800 11 22 34 56 for calls from outside Italy, after dialing the international access code (+). Payment of year 2011 final dividend Eni S.p.A. Shareholders Meeting resolved to pay final dividends as from May 24, 2012, coupon No. 18, being the ex-dividend date May 21, 2012. Therefore, as of this last date, Eni shares will be traded without the right to the payment of 2011 final dividend. In order to exercise the rights incorporated in the shares owned, Shareholders whose shares are not yet in uncertificated form shall previously deliver said shares to a financial intermediary for their deposit with Monte Titoli S.p.A. (Italian Securities Register Centre) and their subsequent dematerialization. The payment of dividends to Beneficial Owners of ADRs, each of them representing two Eni shares, listed on the New York Stock Exchange, will be executed through The Bank of New York Mellon.

Table of Contents

Eni: important new discovery in Mozambique

The discovery made at Coral 1 exploration prospect is estimated to range between 7 and 10 trillion cubic feet (tcf) of gas in place The overall potential for Area 4 is now estimated to range between 47 and 52 tcf of gas in place

San Donato Milanese (Milan), May 16, 2012 - Eni announces a new giant natural gas discovery in Area 4, offshore Mozambique, at the Coral 1 exploration prospect.

The results for this well, drilled in the southern part of Area 4, are of particular significance. The Coral discovery is estimated to contain between 7 and 10 tcf of gas in place, exclusively located in Area 4. With these new results at Coral 1, Eni estimates that the resources exclusively located in Area 4 range between 15 and 20 tcf of gas in place. The new discovery further increases the total potential of the Mamba complex discovered so far in Area 4 Offshore Rovuma, which is now estimated to hold between 47 and 52 tcf of gas in place.

Coral 1 is located 65 kilometers off the Capo Delgado coast in a water depth of 2,261 meters and reaches a total depth of 4,869 meters. The well was drilled approximately 26 kilometers south east of the Mamba South 1 discovery.

The discovery well encountered a total of 75 meters of gas pay in single high-quality Eocene sand. This discovery is particularly significant since it confirms a new exploration play, which is independent of those drilled so far in previous Mamba wells. Eni will run a production test on the Coral 1 discovery.

Eni plans to drill at least another five wells to fully establish the upside potential of Area 4. Eni is the operator of Area 4 with a 70-percent participating interest. Co-owners in the area are Galp Energia (10 percent), KOGAS (10 percent) and ENH (10 percent, carried through the exploration phase).

Company Contacts:

Press Office Tel.: +39.0252031875 - +39.06598232030 Freephone for shareholders (from Italy): 800940924 Freephone for shareholders (from abroad): +39. 800 11 22 34 56 Switchboard: +39-0659821

[email protected] [email protected] [email protected]

Web site : www.eni.com

Table of Contents

Eni to implement Decree of the President of the Council of Ministers shortly

San Donato Milanese (Milan), May 25, 2012 - Eni notes the Decree of the President of the Council of Ministers issued today which sets out the guidelines for the divestment of its stake in Snam and identifies Cassa Depositi e Prestiti as the appropriate entity to continue to provide stability to Snams shareholder base.

Eni is committed to defining the terms of the divestment of its stake shortly, and expects to submit them to its Board of Directors on May 30.

Company Contacts:

Press Office Tel.: +39.0252031875 - +39.06598232030 Freephone for shareholders (from Italy): 800940924 Freephone for shareholders (from abroad): +39. 800 11 22 34 56 Switchboard: +39-0659821

[email protected] [email protected] [email protected]

Web site : www.eni.com

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Eni Regulatory Filings 2012

4348_ffr_2012-06-04_3bb213ae-ee8b-4460-831e-00126f6e32e2.zip

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Eni — Regulatory Filings 2012

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