Eni S.p.A. (E) 6-K Current report (foreign)

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 6-K

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

For the month of April 2010

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

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

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

Form 20-F x                    Form 40-F o

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

Yes o                    No x

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

TABLE OF CONTENTS

Annual Report 2009 (including the opinion of the external Auditors)

SIGNATURES

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

Eni S.p.A.
	Name: Antonio Cristodoro
	Title:	Deputy Corporate Secretary

Date: April 30, 2010

Table of Contents
Contents

 

Table of Contents
Contents

   

Table of Contents
Contents

Table of Contents
Contents

Ordinary Shareholders’ Meeting of April 27 and 29, 2010

The notice convening the meeting was published on the
Gazzetta Ufficiale of the Republic of Italy
No. 35, section II of March 23, 2010 page 1

This annual report includes the report of Eni’s Board of Directors and
Eni’s consolidated financial statements for the year ended December 31,
2009, which have been prepared under the International Financial
Reporting Standards (IFRS), as adopted by the European Union.

Disclaimer

This annual report contains certain forward-looking statements in particular under the section “Outlook” regarding capital expenditures, development and management of oil and gas resources, dividends, share repurchases, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sale growth, new markets, and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document.

Operating and financial review
	4	Profile of the year
	9	Letter to Shareholders
		Operating Review
	13	Exploration & Production
	32	Gas & Power
	45	Refining & Marketing
	51	Petrochemicals
	53	Engineering & Construction
		Financial Review and other information
	56	Financial Review
	56	Profit and loss account
	77	Summarized Group Balance Sheet
	82	Cash Flow Statements
	89	Risk factors and uncertainties
	98	Outlook
	99	Other information
	100	Corporate Governance and Shareholding Structure Report
	144	Commitment to sustainable development
	165	Glossary
Consolidated Financial Statements
	169	Consolidated Financial Statements
	180	Basis of presentation and principles of consolidation
	181	Summary of significant accounting policies
	195	Notes to the Consolidated Financial Statements
	277	Supplemental oil and gas information (unaudited)
	288	Management’s certification
	289	Report of Independent Auditors

“Eni” means the parent company Eni SpA and its consolidated subsidiaries

ENI ANNUAL REPORT / PROFILE OF THE YEAR

Results
Eni reported net profit of euro 4.37 billion for the full year 2009. Adjusted basis net profit was euro 5.21 billion, down 48.8% from a year ago. The reduction reflected lower results mainly reported by the Exploration & Production division due to an unfavorable trading environment for oil prices in the first nine months of the year and by the Refining & Marketing division driven by sharply lower refining margins. The Gas & Power division and the Engineering & Construction business segment showed a resilient performance.

Cash inflows for the year mainly comprised cash flow from operations of euro 11.14 billion, proceeds of euro 3.6 billion from divesting certain interests and non strategic assets, and euro 1.54 billion from a share capital increase subscribed by minorities following the restructuring of Eni’s regulated gas businesses in Italy. These inflows enabled the Company to partially fund capital expenditures of euro 13.69 billion to support organic growth and exploration activities, the completion of the Distrigas acquisition of euro 2.04 billion and the payment of dividends to Eni shareholders amounting to euro 4.17 billion. Ratio of net borrowings to total equity was 0.46 (0.38 at December 31, 2008).

Dividends
Based on 2009 results and taking into account the Company’s sound fundamentals, a dividend of euro 1.00 per share (euro 1.30 in 2008) will be distributed to shareholders. Included in this annual payment is euro 0.50 per share already distributed as interim
dividend in September 2009. Management reaffirms its commitment to create value for Eni’s investors.

Oil and natural gas production
In 2009 oil and natural gas production amounted to 1,769 kboe/d, down 1.6% from 2008. When excluding OPEC cuts amounting to approximately 28 kbbl/d, it was substantially unchanged. Continuing production ramp-up and the start-up of new fields helped make for lower production uplifts associated with weak European gas demand, the impact of unplanned facility downtime in Nigeria and mature field declines.
The company targets a production level in excess of 2 mmboe/d by 2013, with an average annual growth rate higher than 2.5%, based on a 65 $/bbl price scenario.

Proved oil and natural gas reserves
Eni’s estimated net proved reserves at December 31, 2009 amounted to 6.57 bboe, at a reference Brent price of 59.9 $/bbl. The all-sources reserve replacement ratio was 96%, corresponding to an average reserve life index of 10.2 years. Excluding price effects on PSAs’ entitlements, the replacement ratio was 109%.

Natural gas sales
Worldwide natural gas sales were 103.72 bcm, representing a small decline from 2008 (down 0.5%). Sharply lower volumes were recorded on the Italian market (down 24.3%) as a result of the economic downturn and rising competitive pressures. This negative trend was partly offset by full contribution of the Distrigas

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ENI ANNUAL REPORT / PROFILE OF THE YEAR

acquisition (up 12.02 bcm) and organic growth achieved in a number of European markets.
In a challenging outlook for the gas market, Eni expects to achieve gas sales of 118 bcm by 2013, implying an annual growth rate higher than 3%. To achieve this target, Eni will leverage on extracting synergies from integrating Distrigas commercial operations and its excellent strategic positioning in the European gas market.

Distrigas
In 2009 Eni completed the acquisition of Distrigas by means of a tender offer on Distrigas minorities. After the completion of the acquisition, Distrigas shares were delisted from Euronext Brussels. This transaction represented a milestone in strengthening Eni’s leadership in the European gas market as a result of relevant integration synergies.

Reorganization of the regulated businesses
in the Italian gas sector
In 2009 Eni reorganized its regulated businesses in Italy through the sale of its natural gas distribution and storage activities performed by Italgas and Stoccaggi Gas Italia to Eni’s subsidiary Snam Rete Gas. This transaction allowed Eni to unlock value by achieving significant structural synergies in the regulated business segment and to strengthen its consolidated balance sheet.

Strategic partnership between Eni and Gazprom
In 2009 the strategic partnership between Eni and Gazprom, the world-leading gas producer, celebrated its 40th anniversary. Both partners intend to continue pursuing the joint development of projects in upstream and gas markets. In 2009 the following transactions were completed: (i) Eni divested its 20% stake in OAO Gazprom Neft to Gazprom upon exercise of a call option at the contractual price of euro 3.07 billion; (ii) Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia divested a 51% stake in the venture to Gazprom following exercise of a call option by the Russian company. Eni’s share of this transaction is worth $940 million (25% of which had been collected at the balance sheet date and the remaining 75% collected on March 31, 2010); (iii) Eni and Gazprom agreed to widen the original scope of work of the project for building the South Stream pipeline by increasing its transport capacity from 31 to 63 bcm/y.

Portfolio developments
In January 2010, Eni leading with a 32.8% stake a consortium of international companies signed a contract with Iraq’s state-owned South Oil Company (SOC) and
Missan Oil Company to redevelop the Zubair giant oil field. The development plan of the field targets a production of 1.2 bbbl/d to be achieved in the next six years.

In January 2010, Eni and the Venezuelan national company PDVSA signed a preliminary agreement for the joint development of the Junin 5 giant heavy oil field, located in the Orinoco Faja, which has 35 bbbl of certified oil in place.

In June 2009, Eni purchased from Quicksilver Resources Inc a 27.5% interest in the Alliance area, in Northern Texas, with gas shale reserves. The price of the transaction was $280 million. In 2009 production from the acquired assets amounted to 4,000 boe/d, and is expected to ramp up to approximately 10,000 boe/d by 2011.

In November 2009, Eni has been awarded a 37.8% stake in the Sanga Sanga license for the production of coal-bed methane in Indonesia. Preliminary studies in the block show a resource potential of about 4 trillion cubic feet (111 bcm) of gas to be better defined through an appraisal program that will commence in 2010.

In May 2009, Eni and the Egypt’s Ministry of Petroleum signed a cooperation agreement to extend by 10 years the concession on the Belayim giant field. Eni plans to invest $1.5 billion over the next 5 years in developing expenditures, operating costs and interventions aimed at optimizing production.

In January 2010, Eni signed an agreement to acquire oil downstream activities in Austria. This includes a retail network with 135 service stations, wholesale activities and commercial assets in the aviation business as well as logistics and storage activities.

In October 2009, Eni and its Turkish and Russian partners in the construction of the Samsun-Ceyhan pipeline signed a Memorandum of Understanding whereby parties will define certain economic and contractual conditions in order to enable Russian companies to participate in the project. This will ensure the necessary volumes of crude in order to support the project profitability. The project is designed to build a by-pass for oil incoming from the East, avoiding transport by sea through the Dardanelles and Bosporus, thus enhancing safety and environmental protection.

As part of the optimization process of its upstream portfolio, management approved a plan for rationalizing

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ENI ANNUAL REPORT / PROFILE OF THE YEAR

Eni mineral activities in Italy that entails the sale of three Newcos, entirely controlled by Eni. The assets are divided into three groups, depending on their geographical location, which will each be transferred into a single newco: the first lies in northern Italy (Po Valley and Emilia Romagna), the second in central Italy (Marche, Abruzzo, Molise) and the third in southern Italy (Crotone area). Negotiations are well underway for the sale of two companies, Società Padana Energia SpA and Società Adriatica Idrocarburi SpA, holding the assets located in northern and central Italy.

Partnership agreements
In 2009, leveraging its established co-operation model with oil host countries, Eni finalized a number of strategic partnerships pursuing new ventures.
The framework of these ventures provides integration between the traditional oil business and sustainable development initiatives designed to support the host countries population in achieving high social and economic standards. These agreements concerned mainly Angola, Egypt, Kazakhstan and Turkmenistan and represent opportunities to access new reserves.

Exploration activities
In 2009 exploration activities (euro 1,228 million) achieved a number of successes, in particular with the giant Perla discovery (Eni 50%) in Venezuela and with the high potential Cabaça Norte discovery (Eni operator with a 35% interest) in Angola. Further exploration success was achieved in Ghana, the Gulf of Mexico, Indonesia, the North Sea and Pakistan.
In 2009, 69 net exploration wells were completed, in addition to 10 wells in progress at year end with a success rate of 43.6% net to Eni.
The exploration portfolio was strengthened through acquisitions in Angola, China, Ghana, the Gulf of Mexico and Norway in line with Eni’s strategy of consolidating its presence in selected areas.

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ENI ANNUAL REPORT / PROFILE OF THE YEAR

Financial highlights	2007	2008	2009
(euro million)

Net sales from operations		87,204	108,082	83,227
Operating profit		18,739	18,517	12,055
Adjusted operating profit (a)		19,004	21,608	13,122
Net profit (b)		10,011	8,825	4,367
Adjusted net profit (a) (b)		9,569	10,164	5,207
Net cash provided by operating activities		15,517	21,801	11,136
Capital expenditures		10,593	14,562	13,695
Acquisition of investments and businesses (c)		9,909	4,305	2,323
Dividends pertaining to the period (d)		4,750	4,714	3,622
Cash dividends		4,583	4,910	4,166
R&D expenditures		208	217	207
Total assets at period end		101,460	116,673	117,529
Debts and bonds at period end		19,830	20,837	24,800
Shareholders' equity including minority interests at period end		42,867	48,510	50,051
Net borrowings at period end		16,327	18,376	23,055
Net capital employed at period end		59,194	66,886	73,106
Shares price at period end	(euro)	25.05	16.74	17.80
Number of shares outstanding at period end	(million)	3,656.8	3,622.4	3,622.4
Market capitalization (e)	(euro billion)	91.6	60.6	64.5

(a)	For a detailed explanation of adjusted profits (net and operating), that do not include inventory gain/loss and special items, see paragraph "Reconciliation of reported operating profit and reported net profit to results on an adjusted basis".
(b)	Profit attributable to Eni shareholders.
(c)	Net of acquired cash.
(d)	2009 amount (relating to dividend’s payment) is estimated.
(e)	Number of outstanding shares by reference price at period end.

  Summary financial data 2007 2008 2009

Net profit:
- per ordinary share (a)	(euro)	2.73	2.43		1.21
- per ADR (a) (b)	(USD)	7.49	7.15		3.36
Adjusted net profit:
- per ordinary share (a)	(euro)	2.61	2.79		1.44
- per ADR (a) (b)	(USD)	7.16	8.21		4.01
Return On Average Capital Employed (ROACE):
- reported	(%)	20.5	15.7		8.0
- adjusted	(%)	19.4	17.6		9.2
Leverage		0.38	0.38		0.46
Dividends pertaining to the year	(euro per share)	1.30	1.30		1.00
Pay-out (c)	(%)	47	53		83
Total Shareholder Return (TSR)	(%)	3.2	(29.1	)	13.7
Dividend yield (d)	(%)	5.3	7.6		5.8

(a)	Fully diluted. Ratio of net profit and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by ECB for the period presented.
(b)	One American Depositary Receipt (ADR) is equal to two Eni ordinary shares.
(c)	2009 pay-out ratio is estimated with reference to the amounts due on the payment of the dividend balance of 2009.
(d)	Ratio of dividend for the period and average price of Eni shares in December.

  Key market indicators 2007 2008 2009

Average price of Brent dated crude oil (a)		72.52	96.99	61.51
Average EUR/USD exchange rate (b)		1.371	1.471	1.393
Average price in euro of Brent dated crude oil		52.90	65.93	44.16
Average European refining margin (c)		4.52	6.49	3.13
Average European refining margin Brent/Ural (c)		6.45	8.85	3.56
Average Europe refining margin in euro		3.30	4.41	2.25
Euribor - three-month euro rate	(%)	4.3	4.6	1.2
Libor - three-month dollar rate	(%)	5.3	2.9	0.7

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

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ENI ANNUAL REPORT / PROFILE OF THE YEAR

Summary operating data 2007 2008 2009

Exploration & Production
Estimated net proved reserves of hydrocarbons (at period end)	(mmboe)	6,370	6,600	6,571
- Liquids	(mmbbl)	3,219	3,335	3,463
- Natural gas	(bcf)	18,090	18,748	17,850
Average reserve life index	(year)	10.0	10.0	10.2
Production of hydrocarbons	(kboe/d)	1,736	1,797	1,769
- Liquids	(kbbl/d)	1,020	1,026	1,007
- Natural gas	(mmcf/d)	4,114	4,424	4,374
Gas & Power
Worldwide gas sales (a)	(bcm)	98.96	104.23	103.72
LNG sales (b)	(bcm)	11.7	12.0	12.9
Customers in Italy	(million)	6.61	6.63	6.88
Gas volumes transported in Italy	(bcm)	83.28	85.64	76.90
Electricity sold	(TWh)	33.19	29.93	33.96
Refining & Marketing
Refining throughputs on own account	(mmtonnes)	37.15	35.84	34.55
Retail sales of petroleum products in Europe	(mmtonnes)	11.80	12.03	12.02
Service stations in Europe at period end (c)	(units)	6,440	5,956	5,986
Average throughput of service stations in Europe (c)	(kliters)	2,486	2,502	2,477
Petrochemicals
Production	(ktonnes)	8,795	7,372	6,521
Sales of petrochemical products	(ktonnes)	5,513	4,684	4,265
Engineering & Construction
Orders acquired	(euro million)	11,845	13,860	9,917
Order backlog at period end	(euro million)	15,390	19,105	18,730
Employees at period end	(units)	75,862	78,880	78,417

(a)	Include E&P sales volumes of 6.17 bcm (5.39 and 6.00 bcm in 2007 and 2008, respectively) marketed by the Exploration & Production division in Europe (3.59, 3.36 and 2.57 bcm for 2007, 2008 and 2009, respectively) and in the Gulf of Mexico (1.80, 2.64 and 3.60 bcm for 2007, 2008 and 2009, respectively).
(b)	Refer to LNG sales of G&P division (included in worldwide gas sales) and E&P division.
(c)	Full year 2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

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ENI ANNUAL REPORT / TO OUR SHAREHOLDERS

To our shareholders



In 2009, Eni delivered better results than expected, amongst the best in our industry, against the backdrop of the worst economic recessions over the past 60 years. Our integrated business portfolio has again proved its resilience, and we managed to mitigate the impact of the downturn on the company.

We delivered on our targets, positioning the Company for future growth. In E&P, we are strategically focusing on giant projects in the world’s fastest-growing oil-producing areas, namely Iraq and Venezuela. We entered new, high-potential areas like Ghana, and signed a number of framework agreements in our core regions of Russia, the Caspian Sea (Kazakhstan and Turkmenistan) and Africa. In G&P, we completed the acquisition of Distrigas and the reorganization of our regulated businesses in Italy.
We strengthened our long-standing strategic partnership with Gazprom, celebrating its 40^th year of activity in 2009. We plan to continue developing joint projects in the sectors of upstream and natural gas markets.
On January 22, 2010, we signed a Technical Service Contract for the development of the Zubair field in Iraq, under a 20-year term with an option for a further 5 years, targeting a production plateau of 1.2 mmboe/d by 2016.
On January 26, 2010 we signed an agreement with the Venezuelan state-owned company PDVSA for the joint development of the giant field Junin 5, with 35 bbbls of certified heavy oil in place.
In 2009, Eni has been acknowledged as one of the best oil and gas companies in the Dow Jones Sustainability Index. We have continued to focus on improving efficiency in all our businesses. The cost reduction program we launched in 2006 has delivered euro 0.4 billion of savings in 2009 and euro 1.3 billion to date.

Despite an ongoing recovery in oil prices, the outlook for 2010 points to significant challenges. However, our strategy remains unchanged. We continue to target superior production growth over the long-term and to strengthen our leadership position in the European gas market, while maintaining a strong financial position and creating value for our shareholders. Financial performance Eni’s 2009 net profit was euro 4.37 billion.
Adjusted net profit was euro 5.21 billion, a decrease of 49% compared to 2008, driven by the sharp decline in oil prices recorded in the first nine months of the year. The result was also affected by weak refining margins and a higher adjusted tax rate. On the positive side, the Gas & Power and Engineering & Construction segments both reported improved results.
Adjusted return on average capital employed was 9.2%.
Net cash generated by operating activities amounted to euro 11.1 billion. Proceeds from disposals were euro 3.6 billion and further a euro 1.5 billion was provided by a share capital increase that was subscribed by Snam Rete Gas minorities as part of the restructuring plan of Eni’s regulated gas businesses in Italy. These inflows were used to fund part of the financing requirements associated with organic capital expenditures and exploration projects amounting to euro 13.7 billion, the completion of the Distrigas acquisition for euro 2.04 billion, and the payment of euro 4.17 billion to Eni’s shareholders via dividends.

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ENI ANNUAL REPORT / TO OUR SHAREHOLDERS

Our net debt to equity ratio at year end was 0.46.
The results achieved in 2009 enable us to propose at the Annual General Shareholders Meeting a dividend of euro 1.00 per share, of which euro 0.50 was paid as an interim dividend in September 2009. Sustaining growth and shareholder returns Our strategic direction has remained unchanged. Our strong pipeline of capital projects and investment opportunities will enable us to deliver on our growth targets.
Over the next four years, we plan to invest euro 52.8 billion to fuel continuing organic growth, including the strategic projects in Iraq and Venezuela. This is an increase of approximately 8% from the previous plan. The projected cash flows and planned divestments will enable us to service the financing requirements associated with capital expenditures and shareholders’ remuneration.

In EXPLORATION & PRODUCTION, we achieved adjusted net profit of euro 3.9 billion, down 50.9% compared to 2008, driven by an unfavorable trading environment for oil prices in the first nine months (Brent prices were down 37%), lower sales volumes and a higher tax rate.
Oil and gas production was 1,769 kboe/d, down 1.6% from 2008. When excluding OPEC restrictions amounting to approximately 28 kbbl/d, production remained substantially unchanged from a year ago.
Our all-sources reserve replacement ratio was 96%, resulting in a reserve life index of 10.2 years at December 31, 2009 (10 years in 2008).
Over the course of the year we increased our resource base by more than 1 billion boe thanks to successful exploration activities in Venezuela, with the giant Perla discovery, Angola, Ghana and the Gulf of Mexico. This was achieved amid a 30% reduction in exploration expenses year on year.
In 2009 a total of 27 new fields have been put into production, which will add 190 kboe/d to our production at plateau.
In addition to the above-mentioned agreements in Iraq and Venezuela, our upstream portfolio has been further strengthened by continuing exploration success in Angola, acquisition of new licenses in Ghana, the Barents Sea and Pakistan.

We entered the unconventional gas sector in the USA with the purchase of a stake in the Alliance Area containing shale gas, from Quicksilver Resources Inc, and in Indonesia by purchasing a 37.8% interest in the Sanga Sanga license for the production of coal bed methane.

We target an average annual production increase higher than 2.5% in the 2010-2013 plan. By 2013, our hydrocarbon production will hit 2.00 million bbl/d, based on our $65 per barrel Brent price scenario. Most of our projects are in the final investment decision stage or have already been sanctioned.
Three quarters of our 2013 production will come from fields already operating in 2009, and the rest from new start-ups, particularly the Zubair project in Iraq, Kashagan in the Caspian Region and Algeria with the fields acquired from First Calgary. Overall, new start-ups will add approximately 560 kbbl/d by 2013.

In GAS & POWER, we reported adjusted net profit of euro 2.92 billion, an increase of 10% from 2008, despite very weak market conditions, with gas consumption down

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ENI ANNUAL REPORT / TO OUR SHAREHOLDERS

by 7.4% in Europe and 10% in Italy. This result was largely due to stable performances in the regulated businesses, excellent results achieved by Distrigas and integration synergies. Sales volumes were stable at 104 bcm, as a result of expansion in European markets that made for declining sales in Italy (down 24%).
Leveraging on our strategic partnership with Gazprom, we renegotiated terms and conditions of our main long-term supply contracts, improving our operating flexibility.

Our strategy will focus on strengthening our leadership in the European gas market, as well as margins and market share in Italy, relying upon our commercial strength, long-term relationships with producing countries and access to international transport infrastructures.

This access will not be impaired by the possible divestment of our interests in three gas import pipelines from Russia and Northern Europe, which we have proposed to the relevant European authorities in order to settle an antitrust procedure.

In 2010 we expect a weak recovery in gas demand, particularly in Italy. Commercial integration with Distrigas and the advantages granted to us by renegotiating supply contracts with international suppliers will enable us to make for any declines in domestic markets, targeting sales volumes at the same level as in 2009. By 2013, we expect to grow our gas sales by an average growth rate higher than 3% a year, targeting a volume of 118 bcm.
Our regulated businesses in Italy are expected to deliver stable returns, independent of trends in the gas market. They will be supported by guaranteed returns on planned capital expenditures and the cost synergies deriving from integrating gas transport, distribution and storage activities.

In REFINING & MARKETING we reported adjusted net loss of euro 197 million due to an extremely weak refining scenario (down by 52% the TRC Brent margin). Refining throughputs were reduced by one million tonnes. These impacts were partly offset by the good performance in marketing as a result of effective marketing initiatives.
In 2010, we expect a challenging refining environment and we will react accordingly by selectively strengthening our refineries, improving conversion capacity and increasing energy efficiency.
In marketing, we aim to reinforce our leadership in the Italian market through continuing improvements in quality standards, loyalty programs and enhanced non-oil services, along with the re-branding of our service stations to the Eni brand. Abroad, we will focus on growth in three countries: Germany, Switzerland and Austria. On January 21, 2010 we purchased 135 service stations, wholesale activities and logistics and storage assets from Exxon in Austria.

In ENGINEERING & CONSTRUCTION, we reported an improved adjusted net profit of euro 892 million (14% higher than in 2008) thanks to a better operating performance driven by a strong order backlog and increased efficiency. Saipem is completing the expansion of its world-class fleet of construction and drilling vessels, consolidating its leading position in the project management, engineering and construction activities within the oilfield services industry.

In PETROCHEMICALS we reported adjusted losses at both operating and net profit levels (down euro 426 million

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ENI ANNUAL REPORT / TO OUR SHAREHOLDERS

and euro 340 million, respectively) due to an unfavorable market environment that was dragged down by weak demand, excess capacity and strong competitive pressures on commodity products.
Our target is to improve efficiency, shifting our product mix to higher value added products and selectively investing in areas where we can count on competitive advantages (styrenics and elastomers), also leveraging on our proprietary technologies.
Sustainable development We intend to maintain our position: an oil and gas company with one of the highest sustainability ratings in the world.

We will strive to improve the sustainability of our activities through our commitment to research and innovation, the development of local communities, the protection of the environment, the endorsement of higher health and safety standards and people empowerment. In conducting operations and in our relations with partners we uphold the protection and promotion of human rights.
Eni reaffirms its commitment to Research and Innovation over the next four years by starting a new phase where our strategic priorities will be developing technologies for finding and producing hydrocarbons, the sustainable use of renewable energy and environmental restoration and clean-up of divested sites. We will pursue these objectives by forging strategic alliances with poles of international excellence and constant commitment of dedicated Eni resources.
Key to the Company’s success is our strong attention to our people. In managing human resources, we are committed to implementing programs to improve leadership skills, increase knowledge and promote international development.
We continue to strengthen important relationships
with our local partners as part of a cooperation model that aims at developing host countries, through the valorization of local resources, exploitation of specific skills, as well as the realization of projects and the definition of cooperation agreements.
In conclusion, in spite of an unfavorable energy and market environment, Eni delivered a good year. 2010 will pose further challenges but Eni’s strategic positioning will enable it to continue to deliver industry-leading results and create sustainable value for its shareholders in both the short and the long-term.

March 11, 2010

In representation of the Board of Directors

Chairman	Chief Executive Officer and General Manager

BOARD OF DIRECTORS (1)	BOARD OF STATUTORY AUDITORS (7)
Chairman	Chairman
Roberto Poli (2)	Ugo Marinelli
Chief Executive Officer and General Manager	Statutory Auditors
Paolo Scaroni (3)	Roberto Ferranti, Luigi Mandolesi,
Directors	Tiziano Onesti, Giorgio Silva
Alberto Clô, Paolo Andrea Colombo,	Alternate Auditors
Paolo Marchioni, Marco Reboa, Mario Resca,	Francesco Bilotti, Pietro Alberico Mazzola
Pierluigi Scibetta, Francesco Taranto
	MAGISTRATE OF THE COURT OF AUDITORS
CHIEF OPERATING OFFICERS	DELEGATED TO THE FINANCIAL CONTROL OF ENI SpA
Exploration & Production Division	Raffaele Squitieri (8)
Claudio Descalzi (4)	Alternate
Gas & Power Division	Amedeo Federici (9)
Domenico Dispenza (5)
Refining & Marketing Division	External Auditors (10)
Angelo Caridi (6)	PricewaterhouseCoopers SpA

(1) Appointed by the Shareholders’ Meeting held on June 10, 2008 for a three year period. The Board of Directors expires at the date of approval of the financial statements for the 2010 financial year.
(2) Appointed by the Shareholders’ Meeting held on June 10, 2008.
(3) Powers conferred by the Board of Directors on June 11, 2008.
(4) Appointed by the Board of Directors on July 30, 2008.
(5) Appointed by the Board of Directors on December 14, 2005, effective from January 1, 2006. (6) Appointed by the Board of Directors on August 3, 2007.
(7) Appointed by the Shareholders’ Meeting held on June 10, 2008 for a three year period, expiring at the date of the approval of the financial statements for the 2010 financial year.
(8) Duties conferred by the Governing Council of the Court of Auditors on October 28, 2009.
(9) Duties conferred by the Governing Council of the Court of Auditors on December 3-4, 2008.
(10) Appointment extended by the Shareholders’ Meeting held on May 24, 2007 for the 2007-2009 three year term.

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Key performance indicators ^(a) 2007 2008 2009

Net sales from operations (b)	(euro million)	26,920	33,042	23,801
Operating profit		13,433	16,239	9,120
Adjusted operating profit		13,770	17,222	9,484
Adjusted net profit		6,328	7,900	3,878
Capital expenditures		6,480	9,281	9,486
of which: exploratory expenditures (c)		1,659	1,918	1,228
Adjusted capital employed, net at year end (d)		23,826	30,362	32,455
Adjusted ROACE	(%)	30.4	29.2	12.3
Average realizations
- Liquids	($/bbl)	67.70	84.05	56.95
- Natural gas	($/mmcf)	5.42	8.01	5.62
- Total hydrocarbons	($/boe)	53.17	68.13	46.90
Production (e)
- Liquids	(kbbl/d)	1,020	1,026	1,007
- Natural gas	(mmcf/d)	4,114	4,424	4,374
- Total hydrocarbons	(kboe/d)	1,736	1,797	1,769
Estimated net proved reserves (e) (f) (g)
- Liquids	(mmbbl)	3,219	3,335	3,463
- Natural gas	(bcf)	18,090	18,748	17,850
- Total hydrocarbons	(mmboe)	6,370	6,600	6,571
Reserve life index	(years)	10.0	10.0	10.2
All sources reserve replacement ration (e) (g)	(%)	90	135	96
Employees at year end	(units)	9,023	10,891	10,870

(a)	From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit following restructuring of Eni's regulated gas businesses in Italy. Prior period results have been restated accordingly.
(b)	Before elimination of intragroup sales.
(c)	Includes exploration bonuses.
(d)	For a detailed explanation of adjusted capital employed and adjusted ROACE, see paragraph "Return On Average Capital Employed (ROACE)".
(e)	Includes Eni's share of equity-accounted entities.
(f)	The new US SEC rule has changed the pricing mechanism for oil&gas reserves estimation in 2009. It specifies that, in calculating economic producibility, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prior period results use the one day price measured on the last day of the company’s fiscal year.
(g)	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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Portfolio
› Signed a technical service contract, under a 20-year term with an option for further 5 years, with Iraqi National Oil Companies to develop the Zubair oil field (Eni’s interest 32.8%). The partners of the project expect to gradually increase production to a target plateau level of 1.2 mmbbl/d over the next six years.

› Signed an agreement with the Venezuelan National Oil Company PDVSA for the joint development of the Junin 5 giant field with 35 billion barrels of certified heavy oil in place, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 kbbl/d and a long term production plateau of 240 kbbl/d is targeted.

› Acquired from Quicksilver Resources Inc a 27.5% interest in the Alliance area, in Northern Texas with gas shale reserves. Quicksilver has retained the 72.5% of the property and operatorship. The cash consideration for the transaction amounted to $280 million. Production from the acquired assets amounted to 4 kboe/d net to Eni for the full year 2009, ramping up to approximately 10 kboe/d by 2011.

› Awarded a 37.8% stake in the Indonesian Sanga Sanga license for the production of coal bed methane. Recent preliminary studies in the block showed a resource potential of about 3,920 bcf of gas to be verified through an appraisal program that will commence in 2010.

› As part of the optimization process of its upstream portfolio, management approved a plan for rationalizing Eni mineral activities in Italy that entails the sale of three Newcos, entirely controlled by Eni. The assets are divided into three groups, depending on their geographical location, which will each be transferred into a single newco: the first lies in northern Italy (Pianura Padana and Emilia Romagna), the second in central Italy (Marche, Abruzzo, Molise) and the third in southern Italy (Crotone area). Negotiations are well underway for the sale of two companies, Società Padana Energia SpA and Società Adriatica Idrocarburi SpA, holding the assets located in northern and central Italy.

› Awarded new exploration leases in Angola, China, Ghana, the Gulf of Mexico, India, Norway and Yemen.

Divestment of Russian assets
› On April 7, 2009 Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni, based on the existing agreements between the two partners. The exercise price of the call option collected by Eni on April 24, 2009 amounting to euro 3,070 million is equal to the price ($3.7 billion) outlined in the bid procedure for the assets of bankrupt Russian company Yukos as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and financing collateral expenses. At the same time, Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest.

› On September 23, 2009, Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. The total cash consideration amounted to $940 million net to Eni. The three partners are committed to producing first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 kboe/d within two years from the start of production.

Partnership Agreements
In 2009, leveraging its established co-operation model with oil host countries, Eni finalized a number of strategic partnerships pursuing new ventures. The framework of these ventures provides for integration between the traditional oil business and sustainable development initiatives designed to support the host countries population in achieving high social and economic standards:

› In February 2009 three agreements were finalized as part of the Memorandum of Understanding signed in August 2008 with Angola’s national oil company Sonangol, providing for: (i) a feasibility study to assess the economics of the utilization of associated gas in feeding a grass-root onshore power plant; (ii) a joint study to evaluate and collect data on certain Angolan onshore basins in view of identifying upstream opportunities; (iii) the design of a number of educational and training projects targeting Angolan professionals in the development of energy resources.

› In March 2009 signed a Protocol for Cooperation with the government of Pakistan to develop a number of important upstream, midstream and downstream projects in the Country. Eni will provide its expertise as well as new technologies developed in the field of exploring for and developing hydrocarbon fields.

› In May 2009 signed a cooperation agreement with Egypt’s Ministry for Oil to increase and widen cooperation in development activities. The agreement provides for: (i) an extension of the concession of the giant Belayim field (Eni’s

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interest 100%) in the Gulf of Suez till 2030, with Eni’s commitment to spending $1.5 billion over the next five years to execute development expenditures, upgrading actions and operating costs; (ii) a joint study to evaluate a number of industrial initiatives to monetize the natural gas reserves at high depth; (iii) training and knowledge management.

› In August 2009 signed a strategic partnership with the Oil Ministry of the Democratic Republic of Congo to start cooperation in developing the host country’s conventional and unconventional oil reserves, upgrading industrial facilities and training projects.

› In November 2009 signed a co-operation agreement as part of the Memorandum of Understanding signed in July 2009 with the Kazakh National Oil Company KazMunaiGas. The agreement provides for: (i) joint exploration activities in the Isatay and Shangala areas located in the Caspian Sea; (ii) studies of initiatives to optimize gas usage in Kazakhstan; (iii) the evaluation of a number of industrial initiatives including the upgrading of the Pavlodar refinery, in which KMG holds a majority interest.

› In December 2009 signed a memorandum of understanding with Turkmenistan aimed at promoting and reinforcing the partnership in the development of the oil industry of the Country. Eni will co-operate with state bodies and the Agency for Hydrocarbons to carry out studies to ascertain the oil and gas potential of the country. Eni will contribute its expertise in technology and the sustainability field.

Financial results
› Adjusted net profit for the full year was euro 3,878 million, a decrease of euro 4,022 million from 2008 (down 50.9%) driven by lower oil realizations as a result of the negative price environment recorded in the first nine months of the year, lower gas realizations and lower sales volumes. These negatives were partly offset by the depreciation of the euro against the dollar.

› Return on average capital employed calculated on an adjusted basis was 12.3% in 2009 (29.2% in 2008).

› Full-year liquids and gas realizations in dollar terms declined by 31.2% on average reflecting market conditions (Brent dated was down 36.6%).

Production
› Oil and natural gas production for the full year 2009 amounted to 1,769 kboe/d, representing a decrease of 28 kboe/d from 2008 (down 1.6%). Excluding OPEC cuts (down 28 kboe/d) production was barely unchanged. Lower production uplifts associated with weak European gas demand, the impact of unplanned facility downtime, continuing security issues in Nigeria and mature field declines were partly offset by continuing production ramp-ups and field start-ups as well as positive price impacts in the Company’s PSAs and similar contractual schemes (up 35 kbbl/d).

› Leveraging on organic growth in Africa and Central Asia, Eni expects to deliver more than 2.5% compound average growth rate over the next four-year period, targeting a production level in excess of 2 mmboe/d by 2013 under Brent scenario at $65 per barrel.

Estimated net proved reserves
› Estimated net proved reserves at December 31, 2009 were 6.57 bboe (down 0.4% from 2008) based on a 12-month average Brent price of $59.9 per barrel. All sources reserve replacement ratio was 96%, with an average reserve life index of 10.2 years (10 years at December 31, 2008). Excluding the price effect resulting from higher liquids prices from a year ago (the Brent crude price was $36.5 per barrel in 2008) the replacement ratio would be 109%.

Exploration and development expenditures
› In 2009, capital expenditures amounted to euro 9,486 million to enhance assets in well established areas of Africa, the Gulf of Mexico and Central Asia. Exploration activities (euro 1,228 million) achieved a number of successes such as the large Perla gas discovery in the Venezuelan offshore and the Cabaça Norte oil discovery in the Angolan offshore basin. Further discoveries were made in Ghana, the North Sea, the Gulf of Mexico and the Indonesian offshore.

› A total of 69 new exploratory wells were drilled (37.6 of which represented Eni’s share), in addition to 10 exploratory wells in progress at year end (4.2 net to Eni). The overall commercial success rate was 41.9% (43.6% net to Eni).

› Development expenditures were euro 7,478 million (up 16.3% from 2008) to fuel the growth of major projects in Kazakhstan, the United States, Egypt, Congo, Italy and Angola.

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Reserves Overview
The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible form a given date forward, from know reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire.
Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices¹ are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as “proved”, the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under Production Sharing Agreements are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (cost oil) and on the profit oil set contractually (profit oil). A similar scheme applies to buy-back and service contracts. Reserves Governance
Eni has always exercised centralized rigorous control over the process of booking proved reserves.
The Reserves Department of the Exploration & Production Division is entrusted with the task of: (i) assuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) to provide training of staff involved in the process of reserves estimation.
Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has affirmed their compliance with the SEC rules²; D&M has also stated that the company formal guidelines whenever SEC rules may be less precise, provide a reasonable interpretation in line with the generally accepted practices in the industry. When participating in exploration and production activities operated by others entities, Eni also estimates its proved reserves on the basis of the above guidelines.

The process for evaluating reserves, as described in the internal procedure, involves: (i) business unit manager (geographic units) and Local Reserves Evaluators (LRE), who perform the evaluation and classification of reserves including estimates of production profiles, capital expenditures, operating costs and costs related to asset retirement obligations; (ii) geographic area managers at head offices checking evaluation carried out by business unit managers; (iii) the Planning and Control Department which provides the economic evaluation of reserves; (iv) the Reserve Department which, through Division Reserves Evaluators (DRE), provides independent reviews of the fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserve data.

The Head of the Reserve Department attended the “Politecnico di Torino” and received a Master of Science degree in Mining Engineering in 1985. She has more than 20 years of experience in the oil and gas industry and more than 10 years of experience directly in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and

(1)	In prior periods, year-end liquids and natural gas prices were used in the estimate of proved reserves.
(2)	The reports of independent engineers are available on Eni website www.eni.com section Documentation/Annual Report 2009.

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confidentiality respecting professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

Reserves independent evaluation
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent audit³ of its proved reserves on a rolling basis. The description of qualifications of the persons primarily responsible of the reserve audit is included in the third party audit report⁴. In the preparation of their reports, those independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.

In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided. In 2009 Ryder Scott Company and DeGolyer and MacNaughton provided an independent evaluation of 28% of Eni’s total proved reserves at December 31, 2009⁵, confirming, as in previous years, the reasonableness of Eni internal evaluations⁴.

In the 2007-2009 three year period, 86% of Eni total proved reserves were subject to independent evaluation. As at December 31, 2009 among the most important Eni properties, the only one was not subject to an independent review is Barbara (Italy).

Movements in estimated net proved reserves
Eni’s estimated proved reserves were determined taking into account Eni’s share of proved reserves of equity-accounted entities⁶. Movements in Eni’s 2009 estimated proved reserves were as follows:

(mmboe) Consolidated Subsidiaries Equity-accounted entities Total

Estimated net proved reserves at December 31, 2008				6,242				358				6,600
Extensions, discoveries and other additions, revisions of previous estimates, improved recovery and other factors, excluding price effect		680				15				695
Price effect		(100	)			(3	)			(103	)
Reserve additions, total				580				12				592
Proved property acquisitions				26								26
Sales of mineral-in-place				(1	)							(1	)
Production of the year				(638	)			(8	)			(646	)
Estimated net proved reserves pro-forma at December 31, 2009				6,209				362				6,571
Reserve replacement ratio, all sources	(%)			95				150				96
Reserve replacement ratio, all sources and excluding price effect	(%)			109				187				109

Additions to proved reserves booked in 2009 were 592 mmboe and derived from: (i) revisions of previous estimates were 361 mmboe mainly reported in Egypt, Italy, Congo, the United Kingdom and the United States partly offset by the unfavorable effect of higher oil prices on reserve entitlements in certain PSAs and buy-back contracts (down 103 mmboe) resulting from higher oil prices from a year ago (the Brent price used in the reserve estimation process was $59.9 per barrel in 2009 compared to $36.6 per barrel

(3)	From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott.
(4)	The reports of independent engineers are available on Eni website www.eni.com section Documentation/Annual Report 2009.
(5)	Includes Eni’s share of proved reserves of equity-accounted entities.
(6)	Proved reserves included a 29.4% stake of proved reserves owned by the three equity-accounted Russian companies participated by the joint-venture OOO SeverEnergia following the divestment of a 51% stake in the venture to Gazprom on September 23, 2009, in line with the call option arrangement.

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in 2008). Higher oil prices also resulted in upward revisions associated with improved economics of marginal productions; (ii) extensions, discoveries and other factors were 297 mmboe, with major increases booked in Norway, Algeria, Iraq and Libya; (iii) improved recovery were 37 mmboe mainly reported in Angola, Norway and Libya.
The largest additions were related to following fields/projects: Goliat in Norway, Belayim in Egypt, M’Boundi in Congo, Bahr Essalam in Libya, CAFC and MLE in Algeria and Zubair in Iraq.
Acquisitions related mainly to a 27.5% stake purchased from Quicksilver Resources Inc in the Alliance area, in Texas.
In 2009 Eni achieved an all sources reserve replacement ratio⁷ of 96% with a reserve life index of 10.2 years (10 years at December 31, 2008). Excluding the price effect, the replacement ratio would be 109%.

Estimated net proved hydrocarbon reserves

(mmboe) Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Equity-accounted entities Total

Year ended December 31, 2007 (a)	747	638	1,879	1,095	1,061	198	259	133	6,010	360	6,370
Developed	534	537	1,183	766	494	127	158	63	3,862	63	3,925
Undeveloped	213	101	696	329	567	71	101	70	2,148	297	2,445
Year ended December 31, 2008 (a)	681	525	1,922	1,146	1,336	265	235	132	6,242	358	6,600
Developed	465	417	1,229	827	647	168	133	62	3,948	68	4,016
Undeveloped	216	108	693	319	689	97	102	70	2,294	290	2,584
Year ended December 31, 2009 (a)	703	590	1,922	1,141	1,221	236	263	133	6,209	362	6,571
Developed	490	432	1,266	799	614	139	168	122	4,030	74	4,104
Undeveloped	213	158	656	342	607	97	95	11	2,179	288	2,467

Estimated net proved liquids reserves

(mmbbl) Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Equity-accounted entities Total

Year ended December 31, 2007 (a)	215	345	878	725	753	44	138	29	3,127	92	3,219
Developed	133	299	649	511	219	35	81	26	1,953	21	1,974
Undeveloped	82	46	229	214	534	9	57	3	1,174	71	1,245
Year ended December 31, 2008 (a)	186	277	823	783	911	106	131	26	3,243	92	3,335
Developed	111	222	613	576	298	92	74	23	2,009	27	2,036
Undeveloped	75	55	210	207	613	14	57	3	1,234	65	1,299
Year ended December 31, 2009 (a)	233	351	895	770	849	94	153	32	3,377	86	3,463
Developed	141	218	659	544	291	45	80	23	2,001	34	2,035
Undeveloped	92	133	236	226	558	49	73	9	1,376	52	1,428

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

(7) Ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions, discoveries and sales or purchases of minerals in place, to production for the year. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserve Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks.

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Estimated net proved natural gas reserves

(bcf) Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Equity-accounted entities Total

Year ended December 31, 2007 (a)	3,057	1,675	5,751	2,122	1,770	880	696	598	16,549	1,541	18,090
Developed	2,304	1,364	3,065	1,469	1,580	530	442	213	10,967	237	11,204
Undeveloped	753	311	2,686	653	190	350	254	385	5,582	1,304	6,886
Year ended December 31, 2008 (a)	2,844	1,421	6,311	2,084	2,437	911	600	606	17,214	1,534	18,748
Developed	2,031	1,122	3,537	1,443	2,005	439	340	221	11,138	230	11,368
Undeveloped	813	299	2,774	641	432	472	260	385	6,076	1,304	7,380
Year ended December 31, 2009 (a)	2,704	1,380	5,894	2,127	2,139	814	629	575	16,262	1,588	17,850
Developed	2,001	1,231	3,486	1,463	1,859	539	506	565	11,650	234	11,884
Undeveloped	703	149	2,408	664	280	275	123	10	4,612	1,354	5,966

The conversion rate of natural gas from cubic feet to boe is 1,000 cubic feet = 0.1742 barrels of oil.
(a)	Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009 completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.
(b)	As of December 31, 2009 and 2008 Eni’s proved reserves of the Kashagan field were determined based on Eni working interest of 16.81% and 18.52% as of December 31, 2007.

Oil and gas production

Liquids and gas production for the full year 2009 was 1,769 kboe/d, representing a decline of 28 kboe/d from 2008, or 1.6%. Excluding OPEC cuts (down 28 kboe/d) production was barely unchanged. Lower production uplifts associated with weak European gas demand, unplanned facility downtime, continuing security issues in Nigeria and mature field declines negatively affected full-year performance. Production increases were driven by continuing production ramp-ups/start-ups in Angola, Congo, Egypt, Kazakhstan, Venezuela and the Gulf of Mexico as well as the positive price impact reported in the Company’s PSAs and similar contractual schemes (up 35 kbbl/d). The share of oil and natural gas produced outside Italy was 90% (89% in 2008).

Liquids production (1,007 kbbl/d) declined by 19 kbbl/d from 2008 (down 1.9%) due to OPEC cuts. Excluding OPEC cuts, the unplanned facility downtime in Libya and mature field declines, mainly in Italy and the North Sea were offset by production increases achieved in: (i) Angola due to the start-up of the Tombua-Landana project (Eni’s interest 20%) and improved performance in Block 0 (Eni’s interest 9.8%); (ii) Congo due to the ramp-up of the Awa Paloukou project (Eni’s interest 90%); (iii) Kazakhstan due to a better performance; (iv) the Gulf of Mexico due to the start-up of the Thunderhawk (Eni’s interest 25%), Pegasus (Eni’s interest 58%) and Longhorn (Eni’s interest 75%) projects; (v) Venezuela due to the ramp-up of the Corocoro field (Eni’s interest 26%). Natural gas production (4,374 mmcf/d) slightly declined from 2008 (down 0.8%). Main increases were registered in the Gulf of Mexico, Congo due to the contribution of M’Boundi gas project (Eni’s interest 83%), and Croatia due to the start-up of Annamaria field (Eni’s interest 50%). Production decreased in Libya due to lower gas demand on the European market and the mentioned technical reasons, and for mature field declines, mainly in Italy.

Oil and gas production sold amounted to 622.8 mmboe. The 22.9 mmboe difference over production (645.7 mmboe) reflected volumes of natural gas consumed in operations (19.1 mmboe).
Approximately 60% of liquids production sold (365.2 mmbbl) was destined to Eni’s Refining & Marketing division (of which 17% was processed in Eni’s refinery); about 30% of natural gas production sold (1,479 bcf) was destined to Eni’s Gas & Power division.

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Production of oil and natural gas ^{(a) (b)}

Liquids	Natural gas	Hydrocarbons	Liquids	Natural gas	Hydrocarbons	Liquids	Natural gas	Hydrocarbons	Change
(kbbl/d)	(mmcf/d)	(kboe/d)	(kbbl/d)	(mmcf/d)	(kboe/d)	(kbbl/d)	(mmcf/d)	(kboe/d)	Ch.	%

2007 2008 2009 2009 vs 2008

Italy	75	789.7	212	68	749.9	199	56	652.6	169	(30	)	(15.1	)
Rest of Europe	157	647.2	270	140	626.7	249	133	655.5	247	(2	)	(0.8	)
Croatia		52.5	9		68.7	12		95.5	17	5		41.7
Norway	90	271.1	137	83	264.8	129	78	273.7	126	(3	)	(2.3	)
United Kingdom	67	323.6	124	57	293.2	108	55	286.3	104	(4	)	(3.7	)
North Africa	337	1,474.2	594	338	1,761.6	645	292	1,614.2	573	(72	)	(11.2	)
Algeria	85	18.8	88	80	18.5	83	80	19.7	83
Egypt	97	811.2	238	98	818.4	240	91	793.7	230	(10	)	(4.2	)
Libya	142	629.6	252	147	907.6	306	108	780.4	244	(62	)	(20.3	)
Tunisia	13	14.6	16	13	17.1	16	13	20.4	16
West Africa	280	274.2	327	289	260.7	335	312	274.3	360	25		7.5
Angola	132	25.1	136	121	28.1	126	125	29.3	130	4		3.2
Congo	67	11.4	69	84	12.7	87	97	27.3	102	15		17.2
Nigeria	81	237.7	122	84	219.9	122	90	217.7	128	6		4.9
Kazakhstan	70	237.9	112	69	244.7	111	70	259.0	115	4		3.6
Rest of Asia	37	408.9	108	49	426.2	124	57	444.8	135	11		8.9
China	6	11.0	8	6	10.9	8	7	8.2	8
India								3.7	1	1
Indonesia	2	105.4	20	2	99.7	20	2	104.8	21	1		5.0
Iran	26		26	28		28	35		35	7		25.0
Pakistan	1	292.5	52	1	315.6	56	1	328.1	58	2		3.6
Russia	2		2
Turkmenistan				12		12	12		12
America	53	240.3	95	63	311.5	117	79	424.7	153	36		30.8
Ecuador	16		16	16		16	14		14	(2	)	(12.5	)
Trinidad & Tobago		58.9	10		54.6	9		67.0	12	3		33.3
United States	37	181.4	69	42	256.9	87	57	357.7	119	32		36.8
Venezuela				5		5	8		8	3		60.0
Australia and Oceania	11	41.5	18	10	42.2	17	8	48.6	17
Australia	11	41.5	18	10	42.2	17	8	48.6	17
Total	1,020	4,113.9	1,736	1,026	4,423.5	1,797	1,007	4,373.7	1,769	(28	)	(1.6	)

(a)	Includes volumes of gas consumed in operations (300, 281 and 296 mmcf/d in 2009, 2008 and 2007, respectively).
(b)	Includes Eni's share of production of equity-accounted entities.

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ENI ANNUAL REPORT / OPERATING REVIEW

Drilling and other exploratory
and development activities Exploration
In 2009, a total of 69 new exploratory wells⁸ were drilled (37.6 of which represented Eni’s share), as compared to 111 exploratory wells drilled in 2008 (58.4 of which represented Eni’s share) and 81 exploratory wells drilled in 2007 (43.5 of which represented Eni’s share).
The following tables show the number of net productive, dry and in progress exploratory wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of the FASB Extractive-Oil & Gas (Topic 932).

Overall commercial success rate was 41.9% (43.6% net to Eni) as compared to 36.5% (43.4% net to Eni) and 40% (38% net to Eni) in 2008 and 2007, respectively. Development
In 2009 a total of 418 development wells were drilled (175.1 of which represented Eni’s share) as compared to 366 development wells drilled in 2008 (155.1 of which represented Eni’s share) and 349 development wells drilled in 2007 (156.7 of which represented Eni’s share).
The drilling of 116 development wells (41.2 of which represented Eni’s share) is currently underway. Oil and natural gas producing wells are 7,181 (2,417.2 of which represent Eni’s share).

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

Net exploration and development drilling activity

(units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2007
Exploratory	4.0	1.4	15.3	1.7	0.2	0.2	9.6	0.6	33.0
Productive	0.5		7.7	0.5		0.2	3.6		12.5
Dry (a)	3.5	1.4	7.6	1.2	0.2		6.0	0.6	20.5
Development	17.0	27.3	45.8	18.5	1.3	37.8	8.4	0.6	156.7
Productive	17.0	27.2	45.8	18.5	1.3	34.1	5.9	0.6	150.4
Dry (a)		0.1				3.7	2.5		6.3
2008
Exploratory	0.7	3.7	22.9	7.4		16.2	3.4	1.4	55.7
Productive		0.7	8.7	4.0		9.4	1.4		24.2
Dry (a)	0.7	3.0	14.2	3.4		6.8	2.0	1.4	31.5
Development	12.9	5.5	47.6	37.2	2.6	43.0	6.3		155.1
Productive	11.3	5.5	46.4	36.4	2.6	36.5	6.3		145.0
Dry	1.6		1.2	0.8		6.5			10.1
2009
Exploratory	1.0	4.3	8.6	2.7		6.2	4.8	2.2	29.8
Productive		4.1	4.8			2.3	1.0	0.8	13.0
Dry (a)	1.0	0.2	3.8	2.7		3.9	3.8	1.4	16.8
Development	18.3	12.5	41.1	37.7	3.8	42.9	16.6	2.2	175.1
Productive	18.3	12.5	40.7	35.8	3.8	38.6	15.6	2.2	167.5
Dry (a)			0.4	1.9		4.3	1.0		7.6

(a) 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.

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

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Present activities

Drilling activity in progress

(units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2009
Exploratory (a)
gross	6.0	25.0	26.0	60.0	13.0	19.0	22.0	1.0	172.0
net	4.4	6.6	18.6	15.4	2.3	8.8	8.4	1.0	65.5
Development
gross	6.0	8.0	16.0	23.0	2.0	13.0	47.0	1.0	116.0
net	5.8	1.2	6.9	8.2	0.7	6.2	12.1	0.1	41.2

(a) Includes temporary suspended wells pending further evaluation.

Oil and gas properties, wells, operations and acreage

Productive oil and gas wells ^(a)

(units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2009
Oil wells
gross	185.0	384.0	1,103.0	2,764.0	85.0	355.0	125.0	4.0	5,005.0
net	145.7	64.5	469.2	474.3	27.6	255.1	56.3	2.6	1,495.3
Gas wells
gross	481.0	198.0	120.0	501.0		658.0	207.0	11.0	2,176.0
net	421.1	75.2	49.1	36.6		264.3	72.6	3.0	921.9

(a) Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.

Acreage
As of December 31, 2009, Eni’s mineral right portfolio consisted of 1,246 exclusive or shared rights for exploration and development in 40 countries on five continents for a total acreage of 347,862 square kilometers net to Eni of which developed acreage of 41,794 square kilometers and undeveloped acreage of 306,068 square kilometers.
In 2009 total net acreage increased mainly due to: (i) the acquisition of a 27.5% interest in the Alliance area, in Northern Texas from Quicksilver Resources Inc and of a 37.8% interest in the Sanga Sanga license in Indonesia, both in the development of non-conventional gas resources; (ii) the signing of the technical service contract to develop the giant Zubair oil field (Eni 32.8%); (iii) new leases in Angola, China, Ghana, the Gulf of Mexico, India, Norway and Yemen for a total acreage of approximately 40,000 square kilometers net to Eni.
Main decreases were in Mali due to the release of exploration licenses covering an undeveloped acreage of 100,000 square kilometers. Other exploration licenses were released in Congo, Egypt, Italy, Morocco, Norway, Russia, the United Kingdom and the United States mainly related to undeveloped areas.

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Oil and natural gas interests

Dec. 31, 2008 December 31, 2009

Total net acreage ^(a) Number of interest Gross developed acreage ^{(a) (b)} Gross undeveloped acreage ^(a) Total gross acreage ^(a) Net developed acreage ^{(a) (b)} Net undeveloped acreage ^(a) Total net acreage ^(a)

EUROPE	30,511	315	17,918	33,643	51,561	11,794	19,813	31,607
Italy	20,409	167	11,641	15,537	27,178	9,692	12,346	22,038
Rest of Europe	10,102	148	6,277	18,106	24,383	2,102	7,467	9,569
Croatia	988	2	1,975		1,975	987		987
Norway	3,861	51	2,277	8,907	11,184	338	3,074	3,412
United Kingdom	1,450	89	2,025	3,140	5,165	777	692	1,469
Other countries	3,803	6		6,059	6,059		3,701	3,701
AFRICA	249,672	276	70,121	230,549	300,670	19,865	138,884	158,749
North Africa	31,088	119	30,820	54,725	85,545	13,431	32,580	46,011
Algeria	909	38	2,152	17,458	19,610	727	16,517	17,244
Egypt	9,741	57	4,445	18,652	23,097	1,571	6,757	8,328
Libya	18,164	13	17,947	18,427	36,374	8,951	9,214	18,165
Tunisia	2,274	11	6,276	188	6,464	2,182	92	2,274
West Africa	156,557	151	39,301	98,600	137,901	6,434	54,090	60,524
Angola	3,323	67	4,532	16,317	20,849	590	2,803	3,393
Congo	8,244	25	1,865	13,724	15,589	991	7,197	8,188
Gabon	7,615	6		7,615	7,615		7,615	7,615
Ghana		2		2,300	2,300		1,086	1,086
Mali	128,801	1		47,500	47,500		31,668	31,668
Nigeria	8,574	50	32,904	11,144	44,048	4,853	3,721	8,574
Other countries	62,027	6		77,224	77,224		52,214	52,214
ASIA	93,710	80	18,924	204,274	223,198	6,369	119,272	125,641
Kazakhstan	880	6	324	4,609	4,933	105	775	880
Rest of Asia	92,830	74	18,600	199,665	218,265	6,264	118,497	124,761
China	192	7	237	18,461	18,698	39	18,283	18,322
East Timor	9,779	5		9,999	9,999		7,999	7,999
India	9,091	14	303	27,861	28,164	143	9,946	10,089
Indonesia	17,316	12	1,735	25,940	27,675	656	15,863	16,519
Iraq		1	1,950		1,950	640		640
Iran	820	4	1,456		1,456	820		820
Pakistan	18,855	21	9,122	24,782	33,904	2,708	15,493	18,201
Russia	3,891	5	3,597	3,039	6,636	1,058	1,265	2,323
Saudi Arabia	25,844	1		51,687	51,687		25,844	25,844
Turkmenistan	200	1	200		200	200		200
Yemen	3,598	2		23,296	23,296		20,560	20,560
Other countries	3,244	1		14,600	14,600		3,244	3,244
AMERICA	12,043	558	4,737	17,234	21,971	3,090	8,433	11,523
Brazil	1,389	2		1,389	1,389		1,067	1,067
Ecuador	2,000	1	2,000		2,000	2,000		2,000
Trinidad & Tobago	66	1	382		382	66		66
United States	6,648	543	1,977	9,120	11,097	926	5,524	6,450
Venezuela	614	3	378	1,178	1,556	98	516	614
Other countries	1,326	8		5,547	5,547		1,326	1,326
AUSTRALIA AND OCEANIA	29,558	17	1,057	48,216	49,273	676	19,666	20,342
Australia	29,520	16	1,057	47,452	48,509	676	19,628	20,304
Other countries	38	1		764	764		38	38
Total	415,494	1,246	112,757	533,916	646,673	41,794	306,068	347,862

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

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ENI ANNUAL REPORT / OPERATING REVIEW

Main exploration and development projects ITALY
Full year development activities concerned mainly: (i) the completion of the first development phase in the Val d’Agri concession (Eni’s interest 60.77%) through the linkage to the oil treatment plant of the first wells located in the Cerro Falcone, with a production of 6 kboe/d;
(ii) the start-up of Tresauro oil field and the installation of the Annamaria B production platform; (iii) optimization of producing fields by means of sidetrack and work over activities (Annalisa, Antares, Barbara, Cervia, Giovanna, Gela, Luna and Trecate fields).
Offshore activities concerned the finalization of the joint development of three recent gas discoveries (Panda, Argo and Cassiopea), offshore Sicily. Start-up is expected in 2013.
REST OF EUROPE
Croatia Exploration activities yielded positive results with the Ika SW 2 appraisal well which confirmed the mineral potential of the area.
Full year production start-up was achieved in: (i) the Annamaria field (Eni’s interest 50%), with a production of approximately 13 mmcf/d net to Eni; (ii) the Irina (Eni’s interest 50%) and Vesna (Eni’s interest 50%) fields, with an overall production at approximately 3 mmcf/d net to Eni.

Norway Exploration activities yielded positive results in the Prospecting License 128 (Eni’s interest 11.5%) with the Dompap gas discovery. Appraisal activities are underway. In May 2009 following an international bid procedure Eni was awarded the operatorship of exploration licenses PL 533 (Eni’s interest 40%) and PL 529 (Eni’s interest 40%) in addition to a 30% stake in PL 532 in the Barents Sea.
Full year production start-up was achieved in: (i) the Yttergryta (Eni’s interest 9.8%) field, with a production of approximately 71 mmcf/d; (ii) the Tyrihans (Eni’s interest 6.23%) field, with a production of approximately 3 kbbl/d.
Development activities progressed on recent oil and gas discoveries near the Aasgard field (Eni’s interest 14.82%). In particular the development plan of the Morvin discovery (Eni’s interest 30%) provides linkage to existing production facilities that will be upgraded. Production start-up is expected in 2010 with peak production at 12 kboe/d net to Eni in 2014.
Other ongoing projects aim 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.
During the year the final investment decision of the Goliat project (Eni’s interest 65%) was sanctioned. Start-up is expected in 2013 with a production plateau at 100 kbbl/d.

United Kingdom Exploration activities yielded positive results in Block 22/25a (Eni’s interest 16.95%) with the Culzean gas discovery near the Elgin/Franklin producing field (Eni’s interest 21.87%). Study of development activities is underway.
Development activities concerned infilling actions at the Elgin/Franklin, Mac-Culloch (Eni’s interest 40%) and Jade (Eni’s interest 7%) fields to maintain production levels as well as upgrading the facilities in the Liverpool Bay area (Eni’s interest 53.9%).
Pre-development activities are underway at the following discoveries: (i) the Burghley field (Eni’s interest 21.92%) with expected start-up in 2010; (ii) the Kinnoul oil and gas field (Eni’s interest 16.67%) to be developed in synergy with the production facilities of the Andrew field (Eni’s interest 16.21%) and expected start-up in 2012; (iii) the Jasmine gas field (Eni’s interest 33%) with expected start-up in 2012; (iv) the Mariner field (Eni’s interest 8.89%) with expected start-up in 2015.

NORTH AFRICA
Algeria Relevant authorities confirmed the acquisition of the operatorship of the Kerzaz exploration area (Blocks 319a, 321a and 316b) covering a total acreage of 16,000 square kilometers. Exploration activities are underway.
Activities of the year regarded mainly: (i) the development of the Rom and satellites reserves

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ENI ANNUAL REPORT / OPERATING REVIEW

(Zea, Zek and Rec) following the mineral potential revaluation. Current production is collected at the Rom Central Production Facility (CPF) and delivered to the treatment plant in Bir Rebaa North. Drilling and work over activities were started in 2009. An export pipeline and a new multiphase pumping system are underway in compliance with applicable Country law to reduce gas flaring; (ii) the MLE and CAFC integrated project (Eni’s interest 75%) purchased in 2008 from Canadian company First Calgary. The project regards the construction of a treatment plant with a capacity of 350 mmcf/d of NGL and 35 kbbl/d of oil. Production start-up is expected in 2011 with a production plateau of approximately 33 kboe/d net to Eni by 2012. Drilling activities are underway. In 2009 the EPC contract for the construction of a gas treatment plant, gathering and exporting facilities has been awarded. The 11% of the project was completed at year-end.
In 2009 the final investment decision of El Merk was sanctioned. During the year all EPC contracts for the development of facilities were awarded. Drilling activity started. The 24% of the project was completed. Start-up is expected in 2012.

Egypt In 2009, in the offshore area of the Nile Delta, the North Bardawil (Eni operator with a 60% interest) and Thekah fields (Eni operator with a 50% interest) started-up by linking to El Gamil facilities with an overall production plateau at approximately 212 mmcf/d.
The basic engineering is ongoing at the Belayim field for the upgrading of water injection facilities to recover residual reserves.
Other development activities concerned the Tuna project, the second phase at the Denise field and upgrading of the El Gamil compression plant by adding new capacity to support production.
Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 bcf/y of feed gas. Eni is currently supplying 35 bcf/y for a twenty-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 kboe/d net to Eni of feed gas.

Libya Main development activities underway concerned the Western Libyan Gas project (Eni’s interest 50%) for the monetization of gas reserves ratified in the strategic agreements between Eni and NOC. In particular: (i) upgrading of plants and facilities in order to increase sale gas by 49 bcf/y was completed; (ii) additional 71 bcf/y will be on stream by 2015 through the installation of a new platform on
structure A, an upgrading of the Mellitah plant and of the GreenStream compression capacity; further 106 bcf/y will be achieved by means of another offshore field development; (iii) maintaining gas production profiles at the Wafa and Bahr Essalam fields is underway through increasing compression capacity at Wafa field and joint drilling additional wells.
In 2009 volumes delivered through the GreenStream pipeline were 309 bcf. In addition, 43 bcf were sold on the Libyan market for power generation and to fuel the GreenStream pipeline compression plant. Other projects underway regarded: (i) a plan to monetize flaring gas and associated condensates from the Bouri oil field (Eni’s interest 50%) that will be pre-treated in the area and then delivered at the Mellitah plant for the final treatment; (ii) ongoing activities aimed at maintaining the El Feel field (Eni’s interest 33.3%) production plateau through water injection.

Tunisia Exploration activities yielded positive results with four discovery wells among five drilled. In 2009 gas production was started in one well, while two more wells are expected to start-up in 2010.
The ongoing development projects mainly regarded the optimization of production at the Adam (Eni operator with a 25% interest), Djebel Grouz (Eni’s interest 50%), Oued Zar (Eni’s interest 50%) and El Borma (Eni’s interest 50%) fields.
The development plan of Maamoura concession (Eni’s interest 49%) has been almost completed: early production started-up in late 2009. The Baraka (Eni’s interest 49%) development project is in final stage: peaking production at 11 kboe/d is expected in 2010.

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ENI ANNUAL REPORT / OPERATING REVIEW

WEST AFRICA
Angola Exploration activities yielded positive results in: (i) Block 3 (Eni’s interest 12%), the Punja-4 appraisal well showed the presence of liquids and natural gas; (ii) the Development Areas of former Block 14 (Eni’s interest 20%) whit the Malange-2 appraisal well containing oil; (iii) the Development Areas of former Block 15 (Eni’s interest 20%) with the Mondo-4 appraisal well containing oil; (iv) Block 15/06 (Eni operator with a 35% interest) where the Cabaça Norte and Nzanza discoveries showed the presence of oil and yielded 6.5 kbbl/d and 1.5 kbbl/d in test production, respectively.
In 2009 production started-up at the Mafumeira field in Block 0 in the Cabinda-A area (Eni’s interest 9.8%) and the Landana-Tombua fields in the Development Areas of the former Block 14. Peak production at 33 kboe/d and 136 kboe/d is expected in 2010 and 2011, respectively.
Within the activities for reducing gas flaring, projects progressed at the Nemba field in Block 0. Start-up is expected in 2013 reducing flared gas by approximately 85%. In 2009 the development activity of Takula field was completed. Gas flared is re-injected in the field; condensates will be shipped to the Malongo treatment plant, nearing completion.
Main projects underway in the Development Areas of former Block 15 regarded: (i) the development activities started-up at the satellites of Kizomba project-phase 1. The project provides for the drilling of 18 producing wells linked to the FPSO vessels existing in the area. Associated gas will be initially re-injected in the reservoirs in the Kizomba area, and thereafter delivered to the A-LNG liquefaction plant. Start-up is expected in 2012. Peak production at 100 kboe/d (21 net to Eni) is expected in 2013. The second phase provides for production from nearby discoveries; (ii) the Gas Gathering project, entailing the construction of a pipeline collecting all gas from the Kizomba, Mondo and Saxi/Batuque areas, is underway. Completion is expected in 2011.
Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers north of Luanda. It will be designed with a processing capacity of 1 bcf/d of natural gas and to produce 5.2 mmtonnes/y of LNG. The project has been sanctioned by relevant Angolan authorities. It envisages the development of 10,594 bcf of associated gas reserves in 30 years. Start-up is expected in the first quarter of 2012. The LNG will be delivered to the United States market at the re-gasification plant in Pascagoula under construction (Eni’s capacity 45%, amounting to approximately 205 bcf/y), in Louisiana. Start-up is expected in late 2011.
In addition, Eni finalized with the national Angolan company and other partners another agreement to be part of a second gas consortium which will explore further potential gas discoveries to support the feasibility of a second LNG train. Eni is technical advisor with a 20% interest.

Congo Exploration activities yielded positive results in: (i) the Marine XII permit (Eni operator with a 90% interest) with two discoveries wells which confirmed the mineral potential of the area. The related PSA was signed; (ii) the Le Kouilou permit (Eni’s interest 85%) with the Zingali field, confirmed by subsequently long production test.
In 2009 the development plan of Awa-Paloukou field (Eni’s interest 90%) was completed. Production started-up at 12 kbbl/d.
Activities on the M’Boundi operated field (Eni’s interest 83%) moved forward with the revision of the production schemes and layout to plan application of advanced recovery techniques and a design to monetize associated gas. In 2009, Eni signed a long term agreement to supply associated gas from the M’Boundi field to feed three facilities in the Pointe Noire area: (i) the Koilou potassium plant, owned by Canadian Company MAG Industries and under construction; (ii) the CED (Centrale Electrique du Djeno) existing power plant; (iii) the new built CEC (Centrale Electrique du Congo - Eni’s interest 20%). These facilities will also receive gas in the future from the offshore discoveries of the Marine XII permit.
The development activities to build the CEC power plant moved forward in 2009 as scheduled in the Cooperation Agreement signed by Eni and the Republic of Congo in 2007, and the start-up of the first turbo-generator occurred by the end of march 2010.
Also the studies related to the possible exploitation of unconventional oil reserves from the Tchikatanga and Tchikatanga-Makola areas have progressed, according to the cooperation agreement signed in 2008, with the particular aim to identify areas where it would be possible to withstand the stringent Eni’s environmental and sustainability requirements for development.

Ghana On September 28, 2009, Eni acquired operatorship of the offshore exploration permits Cape Three Point South and Cape Three Point (Eni’s interest 47.2%). Exploration activities yielded positive results in the latter with the Sankofa discovery containing oil and natural gas.

Nigeria In 2009 production of the Oyo offshore field in Blocks OML 120/121 (Eni’s interest 40%) started-up at 25 kbbl/d.
In Blocks OML 60, 61, 62 and 63 (Eni operator

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ENI ANNUAL REPORT / OPERATING REVIEW

with a 20% interest), within the activities aimed at guaranteeing production to feed gas to the Bonny liquefaction plant (Eni’s interest 10.4%), the development of gas reserves continued for increasing capacity at the Obiafu/Obrikom plant as well as the installation of a new treatment plant and transport facilities for carrying 155 mmcf/d net to Eni of feed gas for 20 years. To the same end the development plan of the Tuomo gas field has been progressing along with its linkage to the Ogbainbiri treatment plant.
An integrated oil and gas project is underway in the Gbaran-Ubie area. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of about 1 bcf/d of gas and 120 kbbl/d of liquids, the drilling of producing wells and the construction of a pipeline to carry the gas to the Bonny liquefaction plant. First gas is expected in the third quarter of 2010.
Eni holds a 10.4% interest in Nigeria LNG Ltd responsible for the management of the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The seventh unit is being engineered as it is in the pre-fid phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 bcf/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 (Eni’s interest 20%). In 2009, total supplies were 1,798 mmcf/d (130 mmcf/d net to Eni corresponding to 23 kboe/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly-owned by Nigeria LNG Co.
Eni holds a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100 kilometers west of Bonny. This plant is expected to start operating in 2015 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 60 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity (corresponding to approximately 81 bcf/y). The LNG will be delivered to the United States market mainly at the re-gasification plant in Cameron, in Louisiana, USA. Eni’s capacity amounts to approximately 201 bcf/y. Front end engineering activities progressed. The final investment decision is expected at the end of 2010.

KAZAKHSTAN
Kashagan Eni holds a 16.81% working interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the Kashagan field which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. Kashagan is believed to be one of the most important oil discoveries in the world in the past thirtyfive years. Management estimates that the gross recoverable reserves of the field amount to 7-9 bbbl, extendible to 13 bbbl through partial gas re-injection.
A change in the working interest was effective as of January 1, 2008 according to the final agreement signed in 2008 with the Kazakh authorities following which the stake held by the partner KazMunaiGas increased to 16.81%. The other partners of this initiative are the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, ConocoPhillips with 8.40%, and Inpex with 7.56%.
The exploration and development activities of the Kashagan field and of the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The new North Caspian Operating Company (NCOC) BV participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni is confirmed to be the operator of phase-one of the project (the so-called “Experimental Program”) and in addition will retain operatorship of the onshore operations of phase 2 of the development plan.
The phased development plan of the Kashagan field provides for the drilling of about 240 wells and the construction of production plants located on artificial islands which will collect production from other satellite artificial islands. Oil production will be marketed. Natural gas will be mostly used (80%) for re-injection into the reservoir for maintaining pressure levels. The natural gas not re-injected will be treated for the removal of hydrogen sulphide and will be used

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as fuel in power generation for the production plants. The remaining amounts will be marketed.
In consideration of the magnitude of the reserve base, the results of the well tests conducted and the findings of subsurface studies completed so far support expectations for a full field production plateau of 1.5 mmbbl/d.
In conjunction with the final agreement signed in 2008, the Kazakh authorities reached a final approval of the revised expenditure budget of phase-one, amounting to $32.2 billion (excluding general and administrative expenses) of which $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. Eni will fund those investments in proportion to its participating interest of 16.81%.
On the basis of progress to completion (70% of phase 1 of the project) and expertise developed, Eni management expects to achieve first oil by the end of 2012. In the following 12-15 months the treatment and compression plant for gas re-injection will be completed reaching an installed production capacity of 370 kbbl/d in 2014. Subsequently, production capacity of phase-one is expected to step up to 450 kbbl/d, leveraging on availability of further compressor capacity for gas re-injection associated with the start-up of phase-two offshore facilities.
Phase 2 is actually in the stage of Front End Engineering Design (FEED).
However, taking into account that future development expenditures will be incurred over a long time horizon and subsequently to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures.
In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets.
As of December 31, 2009, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $4.5 billion (euro 3.1 billion at the EUR/USD exchange rate of December 31, 2009). This capitalized amount included: (i) $3.4 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $1.1 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years. As of December 31, 2009, Eni’s proved reserves booked for the Kashagan field amounted to 588 mmboe, recording a decrease of 6 mmboe with respect 2008.

Karachaganak In 2009 production of the Karachaganak field averaged 238 kbbl/d of liquids (70 net to Eni) and 883 mmcf/d of natural gas (259 net to Eni).
The fourth treatment unit has been progressing to completion and will enable to increase export of oil volumes to European markets. Currently non-stabilized oil production is delivered to the Orenburg terminal. The development activities of the Uralsk Gas Pipeline are ongoing. This new infrastructure, with a length of 150 kilometers, will link the Karachaganak field to the Kazakhstan gas network. Start-up is expected in 2010.
The engineering activities of Phase 3 of the Karachaganak project identified a new design to complete development activities in multiple phases. The project provides for the installation of gas producing and re-injection facilities to increase gas sales at the Orenburg plant up to 565 bcf/y, according to the General Supply Agreement signed in 2007, and the liquids production up to approximately 14 mmtonnes/y.
The sanction of relevant Authority to start-up with Phase 3 is currently in the phase of technical and marketing discussion.
As of December 31, 2009, Eni’s proved reserves booked for the Karachaganak field amounted to 633 mmboe, recording a decrease of 107 mmboe with respect to 2008 and derived from downward revisions due to lower prices and from production of the year.

REST OF ASIA
China In 2009 Eni signed the PSAs related to exploration Blocks 3/27 and 28/20 located in the South China Sea covering a total net acreage of 18,194 square kilometers. Eni was awarded a 100% stake in the exploration stage.

India In 2009 production started-up at the PY-1 gas field, part of the purchased assets from Hindustan Oil Exploration Company Ltd (Eni’s interest 47.18%), acquired in 2008 as part of Burren deal. Gas production is sold to the local national oil company.

Indonesia Exploration activity yielded positive results with the Jangkrik discovery located in the Muara Bakau Block (Eni’s interest 55%) offshore Borneo.
Eni is also involved in the ongoing joint development of the oil and gas discoveries in the Bukat permit

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(Eni operator with a 66.25% interest) and the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%).
In 2009 the development plan of the Jau field in the Krueng Mane Block (Eni’s interest 75%) located offshore Sumatra was completed. The project is subject to approval by the relevant Authority.
In November 2009, Eni was awarded a 37.8% stake in the Indonesian Sanga Sanga PSC for the production of coal bed methane. The contract refers to exploration, development and production of gas from superficial levels of coal from a contractual area that coincides with the one regulated by the Sanga Sanga PSC for the production of conventional oil. Exploration activity start-up is expected in 2010. In case of commercial discovery, the project will also benefit from synergies with existing production and treatment plants in addition to feeding the LNG plants of Bontang and Sanga Sanga.

Iraq On January 22, 2010, Eni leading a consortium of international companies and the Iraqi National Oil Companies, South Oil and Missan Oil signed a technical service contract, under a 20-year term with an option for further 5 years, to develop the Zubair oil field (Eni 32.8%). The field was awarded to the Eni-led consortium following a successful first bid round and was offered under a competitive bid starting on June 30, 2009. The partners of the project plan to gradually increase production to a target plateau level of 1.2 mmbbl/d over the next six years. The contract provides that the consortium will earn a remuneration fee on the incremental oil production once production has been raised by 10% from its current level of approximately 180 kbbl/d and will recover its expenditures through a cost recovery mechanism based on the revenues from the field’s production.

Iran In 2009 activities were executed at the Darquain project which related to plant commissioning and start-up in view of making formal hand over of operations to local partners. Darquain was the sole Eni-operated project in the Country.

Pakistan Exploration activity yielded positive results with discoveries in the Badhra (Eni operator with a 40% interest), Kadanwari (Eni operator with an 18% interest) and Miano (Eni’s interest 15%) areas. The production start-up of the recent discoveries benefited from the existing facilities.
Development activities concerned: (i) the Bhit field (Eni operator with a 40% interest) with the ongoing installation of a compressor plant aimed at maintaining current production plateau; (ii) the Sawan field (Eni’s interest 23.68%) with the ongoing construction activity of a compressor plant; (iii) the Zamzama permit (Eni’s interest 17.75%) with the construction of the third treatment plant for the production of HVC gas aimed at optimizing current production.
During the year other activities were targeted to optimize production from the Bhit, Sawan and Kadanwari fields by means of the drilling additional wells.

Russia In September 2009, Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. Eni collected the total cash consideration ($940 million), 25% of which had been collected at the transaction date and the remaining 75% on March 31, 2010.
A gain amounting to euro 100 million was recognized in the profit for the year. The gain was associated with interest income at an annual rate of 9.4% accruing on the initial investment in the venture when it was acquired on April 4, 2007 based on the contractual arrangements between Eni and Gazprom. The three partners are committed to producing first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 kboe/d within two years from the start of production.
In April 2009, Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni based on the existing agreements between the two partners. The exercise price of the call option collected by Eni on April 24, 2009 amounting to euro 3,070 million is equal to the price ($3.7 billion) outlined in the bid procedure for the assets of bankrupt Russian company Yukos as adjusted by subtracting dividends distributed and adding the contractual yearly remuneration of 9.4% on the capital employed and financing collateral expenses. Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest.

AMERICA
Trinidad & Tobago The main development project concerns the Poinsettia, Bougainvillea and Heliconia fields in the North Coast Marine Area 1 (Eni’s interest 17.4%). The project provides for the installation of a production platform on the Poinsettia field and the linkage to the Hibiscus treatment facility which was already upgraded. The drilling program on Heliconia and Bougainvillea fields is underway. Start-up is expected in 2010. In 2009 production started-up at the Poinsettia field.

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United States Offshore exploration activities yielded positive results in the following blocks: (i) Green Canyon 859 (Eni’s interest 12.5%) with the oil and gas Heidelberg-1 discovery; (ii) Keathley Canyon 919 (Eni’s interest 25%) with the oil and gas Hadrian West discovery.
In May 2009, Eni signed a strategic alliance with Quicksilver Resources Inc, an independent US natural gas producer, to acquire a 27.5% interest in the Alliance area, in the Fort Worth basin, in Texas. The acquisition for cash consideration amounting to $280 million includes gas shale⁹ production assets with 40 mmbbl of resources base. Production plateau at 10 kboe/d net to Eni is expected in 2011.
In 2009 production start-up was achieved in: (i) the Thunderhawk field (Eni’s interest 25%) through the drilling of underwater wells and linkage to a semi submersible production unit with a treatment capacity of 45 kbbl/d of oil and about 71 mmcf/d of natural gas; (ii) the Longhorn field (Eni’s interest 75%) through the drilling of underwater wells and installation of production platform with a treatment capacity of approximately 247 mmcf/d; (iii) the Leo field (Eni’s interest 75%) by means of the linkage to the Longhorn production facilities. The development plan of the Appaloosa discovery (Eni’s interest 100%) was sanctioned. The discovery is planned to be developed in synergy with the Longhorn production facilities. Start-up is expected in 2010 with production peaking at 1.5 kboe/d.
Other ongoing activities concerned the phased development plan of the Nikaitchuq operated field (Eni’s interest 100%), located in North Slope basins in Alaska. First oil is expected in 2011 with peaking production at 28 kbbl/d. Venezuela A large gas discovery was made in the Perla field, located in the Cardon IV block (Eni 50%) in the Gulf of Venezuela, yielding 21 mmcf/d (approximately 3.7 kboe/d) during flow tests. The field has been estimated to contain a reserve potential of more than 5,650 bcf of gas (1 bboe).
On January 26, 2010 Eni and the Venezuelan National Oil Company PDVSA signed an agreement for the joint development of the giant field Junin 5 with 35 bbbl of certified heavy oil in place, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 kbbl/d and a long term production plateau of 240 kboe/d is targeted. Development will be conducted through an "Empresa Mixta" (Eni 40%, PDVSA 60%). At the time of the establishment of the "Empresa Mixta", Eni will disburse a bonus of $300 million, and further $346 million will be paid upon the achievement of certain project milestones. The agreement also includes an option to deploy Eni’s proprietary technology in hydrogenation for the conversion of heavy oils. Finally, Eni will present a project for the construction of a power plant in the Guiria peninsula. AUSTRALIA AND OCEANIA
Australia In 2009 production start-up was achieved at the Blacktip gas field (Eni’s interest 100%) located in the north western offshore in the South Bonaparte basin by means of a production platform and linkage to onshore treatment plant. Natural gas extracted from this field is sold under a 25-year contract signed with Power & Water Utility Co to fuel a power plant. Peak production at 26 bcf/y is expected in 2010.
Ongoing further development phase (phase 2) of Bayu Undan field (Eni’s interest 10.99%) is underway aimed at increasing liquids production and maintaining the field’s production profile.

(9) Shale gas is a continuous natural gas reservoir contained within fine grained rocks, dominated by shale.

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Capital expenditures Capital expenditures of the Exploration & Production division (euro 9,486 million) concerned development of oil and gas reserves (euro 7,478 million) directed mainly outside Italy, in particular Kazakhstan, United States, Egypt, Congo and Angola. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri as well as sidetrack and infilling activities in mature fields. About 97% of exploration expenditures that amounted to euro 1,228 million were directed outside Italy in particular to the United States, Libya, Egypt, Norway and Angola. In Italy, exploration activities were directed mainly to the offshore of Sicily. Acquisition of proved and unproved property concerned mainly the acquisition from Quicksilver Resources Inc of a 27.5% interest in the Alliance area, in Northern Texas and the extension of Eni’s mineral rights in Egypt, following the agreement signed in May 2009. As compared to 2008, capital expenditures increased by euro 205 million, up 2.2%, due to higher development expenditures mainly in Congo, Algeria, Nigeria, Kazakhstan, Italy, Australia and India.

   Capital expenditures (euro million) 2007 2008 2009 Change % Ch.

Acquisition of proved and unproved properties	96	836	697	(139	)	(16.6	)
North Africa	11	626	351
West Africa		210	73
Rest of Asia			94
America	85		179
Exploration	1,659	1,918	1,228	(690	)	(36.0	)
Italy	104	135	40	(95	)	(70.4	)
Rest of Europe	195	227	113	(114	)	(50.2	)
North Africa	373	379	317	(62	)	(16.4	)
West Africa	246	485	284	(201	)	(41.4	)
Kazakhstan	36	16	20	4		25.0
Rest of Asia	162	187	159	(28	)	(15.0	)
America	505	441	243	(198	)	(44.9	)
Australia and Oceania	38	48	52	4		8.3
Development	4,643	6,429	7,478	1,049		16.3
Italy	461	570	689	119		20.9
Rest of Europe	429	598	673	75		12.5
North Africa	948	1,246	1,381	135		10.8
West Africa	1,343	1,717	2,105	388		22.6
Kazakhstan	733	968	1,083	115		11.9
Rest of Asia	238	355	406	51		14.4
America	345	655	706	51		7.8
Australia and Oceania	146	320	435	115		35.9
Other expenditures	82	98	83	(15	)	(15.3	)
	6,480	9,281	9,486	205		2.2

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Key performance indicators ^(a) 2007 2008 2009

Net sales from operations (b)	(euro million)	27,793	37,062	30,447
Operating profit		4,465	4,030	3,687
Adjusted operating profit		4,414	3,564	3,901
Market		2,284	1,309	1,721
Regulated businesses in Italy		1,685	1,732	1,796
International transport		445	523	384
Adjusted net profit		3,127	2,648	2,916
EBITDA pro-forma adjusted (b)		5,029	4,310	4,403
Market		3,061	2,271	2,392
Regulated businesses in Italy		1,248	1,284	1,345
International transport		720	755	666
Capital expenditures		1,511	2,058	1,686
Adjusted capital employed, net at year end (c)		21,364	22,273	25,024
Adjusted ROACE (c)	(%)	15.2	12.2	12.3
Worldwide gas sales (d)	(bcm)	98.96	104.23	103.72
LNG sales (e)		11.7	12.0	12.9
Customers in Italy	(million)	6.61	6.63	6.88
Gas volumes transported in Italy	(bcm)	83.28	85.64	76.90
Electricity sold	(TWh)	33.19	29.93	33.96
Employees at year end	(units)	11,893	11,692	11,404

(a)	From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit, within the regulated businesses results, following restructuring of Eni regulated gas businesses in Italy. As of that date, the results of the regulated businesses in Italy therefore include results of the Transport, Distribution, Regasification and Storage activities in Italy. Results of the power generation activity are reported within the marketing business as it is ancillary to the latter. Prior period results have been restated accordingly.
(b)	Before the elimination of intragroup sales.
(c)	For a detailed explanation of adjusted capital employed and adjusted ROACE, see paragraph "Return On Average Capital Employed (ROACE)".
(d)	Include volumes marketed by the Exploration & Production division of 6.17 bcm (5.39 and 6.00 bcm in 2007 and 2008, respectively), of which 2.57 bcm in Europe (3.59 and 3.36 bcm in 2007 and 2008, respectively) and in the Gulf of Mexico (1.80 bcm and 2.84 bcm in 2007 and 2008, respectively).
(e)	Refer to LNG sales of the G&P division (included in worldwide gas sales) and the E&P division.

Presentation to the European Commission of a set of structural remedies related to some international gas pipelines
› On February 4, 2010, Eni has formally presented to the European Commission a set of structural remedies relating to certain international gas pipelines. With prior agreement from its partners, Eni has committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test,

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Eni will be in the position to resolve an inquiry started in May 2006 for alleged infringements of the European antitrust regulations in the gas sector, which involved the main players in the European gas market. Eni received a statement of objections from the European Commission which alleged that during the 2000-2005 period Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas, thus restricting gas availability in Italy. Given the strategic importance of the Austrian TAG pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. The remedies negotiated with the Commission do not affect Eni’s contractual gas transport rights. For further details on this topic see note "Guarantees, commitments and risks" to the Consolidated Financial Statements.

European gas market
› In 2009, the mandatory tender offer on the minorities of Distrigas was finalized and Distrigas shares have been delisted from Euronext Brussels. Thanks to the achievement of synergies on integration, the Distrigas acquisition represented for Eni a remarkable result in strengthening its leadership in the European gas market.

› Notwithstanding the unfavorable trends in natural gas demand, in 2009 Eni achieved organic growth outside Italy, increasing market shares in a number of European gas markets. This increase, coupled with the full contribution of Distrigas sales, determined a change in natural gas sales portfolio with international sales at 63.68 bcm representing 61% of total sales (49% in 2008).

Reorganization of regulated businesses in the Italian gas sector
› In 2009 the reorganization of gas infrastructures was concluded through the sale of Italgas SpA and Stoccaggi Gas Italia SpA (Stogit) to Snam Rete Gas. The transaction is expected to create significant synergies in the segment of regulated businesses allowing Eni to maximize the value of both gas distribution and storage activities and to strengthen the financial soundness of the Group’s capital structure.

Strategic partnership with Gazprom
› The strategic partnership between Eni and Gazprom, leading world natural gas producer, celebrated its 40^th year of activity in 2009. The partners plan to proceed with the joint development of projects in the sectors of upstream and natural gas markets. In particular, concerning the gas business, Eni and Gazprom have agreed upon a new scope of work in the development project of the South Stream pipeline, aimed at increasing its transport capacity from an original amount of 31 bcm/y to 63 bcm/y.

Projects in the Hewett area
› In order to strengthen its European leadership in the storage business, Eni continued pre-development activities for a project to build an offshore storage facility in the Hewett area, near the Bacton terminal (North Sea basin). Eni targets to develop storage capacity in order to support the seasonal swings of gas demand in the United Kingdom. The project sanction is expected at some point in 2010, with start up in 2015.

Financial results
› In 2009 adjusted net profit was euro 2,916 million, increasing by euro 268 million from 2008 (up 10.1%) due to the positive performance recorded by the Marketing business. An improved scenario for energy parameters, the full contribution of the acquisition of Distrigas in terms of integration synergies and improved performance, as well as the impact of the renegotiation of long-term supply contracts, were the main positive drivers of the year. These positives were partly offset by lower sales volumes, mainly on the Italian market. Regulated Businesses in Italy recorded steady results. The International transport business reported weaker results.

› In 2010 natural gas sales are expected to remain flat compared to 2009. Increasing competitive pressures, mainly in Italy, will be offset by an expected recovery in European gas demand. Other positive trends include a benefit associated with integrating Distrigas operations and the optimization of supply portfolio, including re-negotiation of long-term supply contracts.

› Eni expects to achieve gas sales of approximately 118 bcm by 2013 with an average annual growth rate higher than 3%.

› Return on average capital employed (ROACE) on an adjusted basis was 12.3% (12.2% in 2008).

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› Capital expenditures totaled euro 1,686 million and mainly related to the development and upgrading of Eni’s transport and distribution networks in Italy, the upgrading of storage capacity and the ongoing plan for improving power generation efficiency standards.

Operating results
› In 2009 Eni’s natural gas sales (103.72 bcm) were slightly down as a result of offsetting trends. On the negative side, volumes supplied to the Italian market were materially lower from a year ago against the backdrop of the economic downturn and stronger competitive pressures (down 12.83 bcm, or 24.3%). On the plus side, volumes gains were associated with the full contribution of the Distrigas acquisition (up 12.02 bcm for the full year) and organic growth achieved in a number of European markets.

› Electricity volumes sold were 33.96 TWh, increasing by 4.03 TWh, or 13.5%, from 2008.

› Natural gas volumes transported on the Italian network were 76.90 bcm, down 10.2% from 2008.

NATURAL GAS Supply of natural gas In 2009 Eni’s consolidated subsidiaries, including the Distrigas share amounting to 16.91 bcm, supplied 88.65 bcm of natural gas with a 1 bcm decrease from 2008, down 1.1%.
Gas volumes supplied outside Italy (81.79 bcm from consolidated companies), imported in Italy or sold outside Italy, represented 91% of total supplies with an increase of 0.14 bcm from 2008, or 0.2%, mainly due to the growth registered on European markets in particular due to Distrigas full contribution, with higher volumes purchased from: (i) Norway (up 5.68 bcm); (ii) Qatar (up 2.20 bcm) due to the coming on stream of LNG long-term supply contracts; and (iii) the Netherlands (up 1.90 bcm).
Lower volumes were purchased from: (i) Algeria (down 5.40 bcm) due to the damage occurred to the TMPC pipeline in late December 2008; (ii) Libya (down 0.73 bcm); (iii) Russia mainly to Italy (down 2.75 bcm) in line with the implementation of agreements with Gazprom providing for Gazprom’s entrance in the market of supplies to Italian importers.
Supplies in Italy (6.86 bcm) declined by 1.14 bcm from 2008, or 14.3%, due to lower domestic production.
In 2009, main gas volumes from equity production derived from: (i) Italian gas fields (6.5 bcm); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2009 these two fields supplied 2.5 bcm net to Eni; (iii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.9 bcm); and (iv) other European areas (in particular Croatia with 0.8 bcm). Considering also the direct sales of the Exploration & Production division in Europe and in the Gulf of Mexico and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 20.1 bcm representing 19% of total volumes available for sale.

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Supply of natural gas (bcm) 2007 2008 2009 Change % Ch.

ITALY	8.65		8.00		6.86		(1.14	)	(14.3	)
Russia	23.44		22.91		22.02		(0.89	)	(3.9	)
Algeria (including LNG)	18.41		19.22		13.82		(5.40	)	(28.1	)
Libya	9.24		9.87		9.14		(0.73	)	(7.4	)
Netherlands	7.74		9.83		11.73		1.90		19.3
Norway	5.78		6.97		12.65		5.68		81.5
United Kingdom	3.15		3.12		3.06		(0.06	)	(1.9	)
Hungary	2.87		2.84		0.63		(2.21	)	(77.8	)
Qatar (LNG)	-		0.71		2.91		2.20		..
Other supplies of natural gas	2.20		4.07		4.49		0.42		10.3
Other supplies of LNG	2.32		2.11		1.34		(0.77	)	(36.5	)
OUTSIDE ITALY	75.15		81.65		81.79		0.14		0.2
Total supplies of Eni's consolidated subsidiaries	83.80		89.65		88.65		(1.00	)	(1.1	)
Offtake from (input to) storage	1.49		(0.08	)	1.25		1.33		..
Network losses, measurement differences and other changes	(0.46	)	(0.25	)	(0.30	)	(0.05	)	20.0
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES	84.83		89.32		89.60		0.28		0.3
Available for sale by Eni's affiliates	8.74		8.91		7.95		(0.96	)	(10.8	)
E&P volumes	5.39		6.00		6.17		0.17		2.8
GAS VOLUMES AVAILABLE FOR SALE	98.96		104.23		103.72		(0.51	)	(0.5	)

Sales of natural gas In 2009 natural gas sales were 103.72 bcm, declining slightly from 2008 (down 0.51 bcm, or 0.5%). Sales included own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and the Gulf of Mexico. The contribution of the Distrigas acquisition (up 12.02 bcm) partly offset the negative effects of sharply lower gas demand in Italy (down 10%) and Europe (down 7.4%, both percentages net of seasonal swings). In Italy, sales volumes decreased by 12.83 bcm, or 24.3%, to 40.04 bcm reflecting sharply lower supplies to power generation utilities (down 8.01 bcm), industrial customers (down 2.01 bcm) and wholesalers (down 1.60 bcm) dragged down by a decline in industrial production following the economic downturn and competitive pressures, especially in the last part of the year which was affected by new gas availability. Volumes sold to the residential sector increased slightly due to higher weather-related sales, particularly in the first and fourth quarter of 2009 as well as volumes destined to Eni’s power generation business.
International sales were up 12.32 bcm, or 24%, to 63.68 bcm, benefiting from the contribution of Distrigas (up 12.02 bcm). Organic sales increases were achieved in France (up 1.27 bcm) and in Northern Europe (up 1.10 bcm). These increases were offset in part by lower volumes reported in supplies to importers to Italy (down 0.77 bcm), in the Iberian Peninsula (down 0.63 bcm) and Hungary (down 0.24 bcm) mainly due to declining demand. Sales to markets outside Europe (2.06 bcm) declined by 0.27 bcm from 2008. E&P sales in Europe and in the United States (6.17 bcm) increased by 0.17 bcm, up 2.8%.

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Gas sales by market (bcm) 2007 2008 2009 Change % Ch.

ITALY	56.13	52.87	40.04	(12.83	)	(24.3	)
Wholesalers	10.01	7.52	5.92	(1.60	)	(21.3	)
Gas release	2.37	3.28	1.30	(1.98	)	(60.4	)
Italian gas exchange and spot markets	1.90	1.89	2.37	0.48		25.4
Industries	11.77	9.59	7.58	(2.01	)	(21.0	)
Medium-sized enterprises and services	1.00	1.05	1.08	0.03		2.9
Power generation	17.21	17.69	9.68	(8.01	)	(45.3	)
Residential	5.79	6.22	6.30	0.08		1.3
Own consumption	6.08	5.63	5.81	0.18		3.2
INTERNATIONAL SALES	42.83	51.36	63.68	12.32		24.0
Rest of Europe	35.02	43.03	55.45	12.42		28.9
Importers in Italy	10.67	11.25	10.48	(0.77	)	(6.8	)
European markets	24.35	31.78	44.97	13.19		41.5
Iberian Peninsula	6.91	7.44	6.81	(0.63	)	(8.5	)
Germany-Austria	5.03	5.29	5.36	0.07		1.3
Belgium	-	4.57	14.86	10.29		..
Hungary	2.74	2.82	2.58	(0.24	)	(8.5	)
Northern Europe	3.15	3.21	4.31	1.10		34.3
Turkey	4.62	4.93	4.79	(0.14	)	(2.8	)
France	1.62	2.66	4.91	2.25		84.6
Other	0.28	0.86	1.35	0.49		57.0
Outside Europe	2.42	2.33	2.06	(0.27	)	(11.6	)
E&P in Europe and in the Gulf of Mexico	5.39	6.00	6.17	0.17		2.8
WORLDWIDE GAS SALES	98.96	104.23	103.72	(0.51	)	(0.5	)

Gas sales by entity (bcm) 2007 2008 2009 Change % Ch.

Sales of consolidated companies	84.83	89.32	89.60	0.28		0.3
Italy (including own consumption)	56.08	52.82	40.04	(12.78	)	(24.2	)
Rest of Europe	27.86	35.61	48.65	13.04		36.6
Outside Europe	0.89	0.89	0.91	0.02		2.2
Sales of Eni's affiliates (net to Eni)	8.74	8.91	7.95	(0.96	)	(10.8	)
Italy	0.05	0.05	-	(0.05	)	(100.0	)
Rest of Europe	7.16	7.42	6.80	(0.62	)	(8.4	)
Outside Europe	1.53	1.44	1.15	(0.29	)	(20.1	)
E&P in Europe and in the Gulf of Mexico	5.39	6.00	6.17	0.17		2.8
Worldwide gas sales	98.96	104.23	103.72	(0.51	)	(0.5	)

Risk factors related to the natural gas market

Risks and uncertainties associated with the current outlook for gas demand and supply in Europe and Italy
In 2009 European gas demand was severely impacted by the economic downturn (down 7.4% from 2008, assuming normal average temperatures). As a result of that trend, both producing activities and request for electricity reduced. The Italian market was particularly hit by the downturn as demand fell by approximately 9 bcm from 2008, down 10%, and almost 10 bcm from the pre-crisis levels seen in 2007, down 12%, assuming normal average temperatures. In the meantime, new gas supplies entered the market as several operators, including Eni, completed plans to upgrade gas import pipelines from gas producing Countries or to build new facilities to import gas to Europe via LNG. Particularly, Eni has finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria by 13 bcm/y (the gas pipelines TAG and TTPC), with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 bcm/y commenced operations late in 2009, operated by a consortium of competitors. As a result, gas availability on the Italian market increased at a time when demand actually shrunk, resulting in a situation of oversupply. In this context, Eni’s results of the gas marketing business, sales volumes and average gas selling margins were driven down by rising competition and weak demand both in Italy and Europe. Large gas availability on European markets also prevented the

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Company from disposing of part of its gas availability by selling it on European markets.
The outlook for gas supply and demand both in Europe and Italy is challenging as GDP growth in the 27 EU Countries will remain weak over the next few years and gas demand is expected to recover only gradually to pre-crisis levels. In addition, ongoing patterns towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt their Climate Action and Renewable Energy Package. This legislation was voted by the European Parliament in December 2008. The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020. To factor in those trends, management has revised down its long-term projections of European gas demand growth from a previous compound average growth rate (c.a.g.r.) of 2% till 2020 to a revised 1.5% c.a.g.r. These assumptions imply an overall consumption of approximately 600 bcm by 2020 compared to a previous forecast of 720 bcm. Management also expects the Italian market to grow less than anticipated at an annual rate that will be slightly lower than 2%, implying a level of consumption amounting to 94 bcm versus a previous forecast of 107 bcm at 2020. These demand trends of sluggish growth associated with ample gas availability on the marketplace might adversely affect the Company’s results of operations and cash flow in its gas marketing business over the next few years. Current negative trends in gas demand and supply may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
In order to secure long-term access to gas availability, particularly in view of supplying the Italian gas market, the Company has signed a number of long-term gas supply contracts with key producing Countries that supply European gas markets. These contracts will ensure approximately 62.4 bcm of gas availability in 2010 (excluding the contribution of other subsidiaries and associates) with a residual life of approximately 20 years, and provide take-or-pay clauses whereby the Company is required to collect minimum predetermined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of it, of uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash pre-payments and time schedules for collecting pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices current in the year of non-fulfillment with the balance due in the year when the gas is actually collected. Amounts of pre-payments range from 10 to 100 percent of the full price. The right to collect pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements.
In addition, rights to collect pre-paid gas in future years can be exercised provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity that can be collected in each contractual year. In this case, Eni will pay the residual price calculating it as the percentage that complements 100, based on the arithmetical average of monthly base prices in place in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations.
Management believes that the current outlook for gas demand and large gas availability on the marketplace, as well as the possible evolution of sector-specific regulation, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts.
Under current contractual terms, in 2009 Eni collected lower volumes than its minimum take and recognized a trade payables corresponding to the amount of gas that the Company was contractually required to collect.
Management believes that over the next three years the Company will experience failure to fulfill its take-or-pay obligations associated with significant volumes of gas, unless demand fundamentals improve substantially and a better balance between demand and supply is achieved on the marketplace. Currently, the Company is unable to forecast the timing of such a recovery.
In addition, there also exist both a pricing risk as a portion of the gas purchase price is based on the prices of the energy parameters recorded in the year of non-fulfillment, and a volume risk in case the Company is actually unable to dispose of pre-paid volumes. In this context, the Company’s selling margins, results of operations and cash flow may be negatively affected.
Based on management’s projections for sales volumes and prices for the four-year plan and subsequent years, volumes for which an obligation to pay cash advances might arise due to take or pay clauses will be off-taken within contractual terms, thus recovering cash advances. Even if financing associated with cash advances is factored in, the net present value associated with those long-term contracts discounted at the weighted average cost of capital for the Gas & Power

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segment still remains a positive and consequently those contracts do not fall within the category of the onerous contract provided by IAS 37.
In the medium term Eni intends to preserve the profitability and cash flow generation of its gas marketing operations. A number of initiatives have been identified, including:
- Maximization of gas sales volumes leveraging on the multiple presence in a number of markets; market knowledge, the integration with Distrigas commercial operations and supply portfolio (which is not expected to have take-or-pay obligations in future years) and marketing policies aimed at increasing Eni’s market share in Europe;
- Renegotiations of the main long-term supply contracts through the exercise of the contractual right to amend terms and conditions of the contracts as provided by specific contractual clauses in case of significant changes in the market environment, as those that have been occurring from the second half of 2008. These renegotiations were finalized early in 2010 with a positive impact both on 2009 results and on future commercial plans giving Eni more flexibility in its marketing operations;
- Launching of innovative pricing formulas and improving the quality of services on the core Italian market;
- Reduction in the cost-to-serve;
- Monitoring and controlling working capital requirements. Risks associated with sector-specific regulations in Italy
Legislative Decree No. 164/2000 opened the Italian natural gas market to competition, impacting on Eni’s activities, as the company is engaged in all the phases of the natural gas chain. The opening to competition was achieved through the enactment of certain antitrust thresholds on volumes input into the national transport network and on volumes sold to final customers. These enabled new competitors to enter the Italian gas market, resulting in declining selling margins on gas. Other material aspects regarding the Italian gas sector regulations are the regulated access to natural gas infrastructure (transport backbones, storage fields, distribution networks and LNG terminals), the provision that activities relating to infrastructures are mandatory charged to separate companies; the Code adopted by the Authority for Electricity and Gas on the issue of unbundling which forbids a controlling entity from interfering in the decision-making process of its subsidiaries running gas transport and distribution and other infrastructures and the circumstance that the Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing and in establishing tariffs for the use of natural gas infrastructures. Specifically, the Authority for Electricity and Gas holds a general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users consuming less than 200,000 cm/y (qualified as non eligible customers at December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of fuels onto final consumers of natural gas. Following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority finally established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 cm/y, establishing, among other things that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account a new indexation mechanism of the raw material cost component. This indexation mechanism has been recently updated based on Resolution No. 64/2009 of the Authority, which provides that changes in a preset basket of hydrocarbons are transferred to the cost of the supply to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons.
Also certain provisions of law may limit the Company’s ability to set commercial margins. Specifically, Law Decree No. 112 enacted in June 2008 forbids energy companies like Eni to pass to prices to final customers the higher income taxes incurred in connection with a supplemental tax rate of 6.5 percentage points introduced by the same decree on energy companies with a yearly turnover in excess of euro 25 million. The Authority for Electricity and Gas is in charge of monitoring compliance with this rule. The Authority has subsequently established with a set of deliberations that energy companies have to adopt effective operational and monitoring systems in order to prevent unlawful increases in final prices of gas.
Other risk factors and uncertainties deriving from the regulatory framework are associated with the regulation of the access to the Italian gas transport network that is currently set by Decision No. 137/2002 of the Authority for Electricity and Gas. The decision is fully incorporated into the network code presently in force as prepared by the system’s operator. The decision sets priority criteria for transport capacity entitlements at points where the Italian transport network connects with international

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import pipelines (the so-called entry points to the Italian transport system). Specifically, operators that are holders of take-or-pay contracts, as in the case of Eni, are entitled to a priority in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes are not entitled to any priority and, in case of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity assignments. The ability of Eni to collect gas volumes exceeding average daily volumes as provided by its take-or-pay supply contracts represents an important operational flexibility that the Company uses to satisfy demand peaks. In planning its commercial flows, the Company normally assumes to make full use of its contractual flexibility and to obtain the necessary capacity entitlements at the entry points to the national transport network. Those assumptions may be inconsistent with rules set by Decision No. 137/2002 specifically with regard to priority criteria governing capacity entitlements. Eni considers Decision No. 137/2002 to be illegitimate as it is supposedly in contrast with the rationale of the European regulatory framework on the gas market as provided in European Directive 55/03/CE. Based on that belief the Company has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court which recently confirmed in part Eni’s position. An upper grade court also confirmed the Company’s position. Specifically, the Court stated that the purchase of contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in the access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impair Eni’s marketing plans.
Further uncertainty factors related to the regulatory framework are the so called gas release measures that are intended to increase flexibility and liquidity in the gas market. This measure strongly affected Eni’s marketing activity in Italy. In 2004, based on certain agreements with the Antitrust Authority, Eni released in a four-year period a total amount of 9.2 bcm (2.3 bcm per year between October 1, 2004 and September 30, 2008) and the related transport capacity. In addition, in 2007 Eni agreed to adhere to a new gas release program involving 4 bcm which were disposed of at the virtual exchange point (PSV) in a two-year period (from October 1, 2007 and September 30, 2009).
For thermal year 2009-2010 Italian Law No. 99/2009 introduced a new obligation for Eni to make additional sales at the virtual exchange point for a total of 5 bcm of gas in yearly and half-yearly amounts. Although the allotment procedure (bid) was based on a minimum price set by the Ministry for Economic Development as proposed by the Authority (Eni considering this point discriminatory, filed a claim to the competent authority), only a 1.1 bcm portion of the gas release was awarded out of the 5 bcm which had been planned.
For the next few years, based on indications of the Authority (in a report to the Parliament on the situation of the gas and electricity market in Italy as provided in Resolution PAS 3/2010), Eni cannot exclude the possibility that new gas release programs will be imposed on it.
LNG In 2009, LNG sales (12.9 bcm) increased by 0.9 bcm from 2008, up 7.5%, mainly reflecting higher volumes sold by the Gas & Power segment (9.8 bcm, included in worldwide gas sales) that increased by 1.4 bcm, up 16.7%, from 2008, due to the Distrigas contribution related to the coming on stream of a long-term supply contract from Qatar (up 2.2 bcm).

LNG sales (bcm) 2007 2008 2009 Change % Ch.

G&P sales	8.0	8.4	9.8	1.4		16.7
Italy	1.2	0.3	0.1	(0.2	)	(66.7	)
Rest of Europe	5.6	7.0	8.9	1.9		27.1
Outside Europe	1.2	1.1	0.8	(0.3	)	(27.3	)
E&P sales	3.7	3.6	3.1	(0.5	)	(13.9	)
Terminals:
- Bontang (Indonesia)	0.7	0.7	0.8	0.1		14.3
- Point Fortin (Trinidad & Tobago)	0.6	0.5	0.5
- Bonny (Nigeria)	2.0	2.0	1.4	(0.6	)	(30.0	)
- Darwin (Australia)	0.4	0.4	0.4
	11.7	12.0	12.9	0.9		7.5

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POWER Availability of electricity Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi and Ferrara. In 2009, power generation was 24.09 TWh, up 0.76 TWh or 3.3% from 2008, due mainly to higher production at the Ferrara plant (Eni’s interest 51%), in connection with the coming on line of two new 390 megawatt combined cycle units.
At December 31, 2009, installed capacity was 5.3 GW (4.9 GW in 2008).
Power availability in 2009 was supported by the growth in electricity trading activity (up 3.27 TWh from 2008, or 49.5%) as a consequence of higher volumes traded on the Italian power exchange benefiting from lower purchase prices.
By 2013 Eni intends to complete its plan for expanding its power generation capacity, targeting an installed capacity of 5.4 GW¹. The development plan is underway at Taranto (Eni 100%) and Ferrara (Eni 51%), as well as at the recently acquired Bolgiano plant (Eni 100%).
Electricity sales In 2009 electricity sales (33.96 TWh) were directed to the free market (73%), the Italian power exchange (14%), industrial sites (9%) and others (4%).
Notwithstanding weaker domestic demand, Eni’s sales (up 4.03 TWh, or 13.5%) were driven by: (i) higher sales on open markets, in particular the retail market, with an increased number of clients served following intensive marketing campaigns, and to wholesalers due to the start of VPP (Virtual Power Plant) supply agreements signed at the end of 2008. Sales to large clients, on the other hand declined due to a reduction in the customer base and the impact of the economic downturn; (ii) higher volumes traded on the Italian power exchange (up 0.88 TWh, or 23%).

2007 2008 2009 Change % Ch.

Purchases of natural gas	(mmcm)	4,860	4,530	4,790	260		5.7
Purchases of other fuels	(ktoe)	720	560	569	9		1.6
Power generation	(TWh)	25.49	23.33	24.09	0.76		3.3
Steam	(ktonnes)	10,849	10,584	10,048	(536	)	(5.1	)

Availability of electricity (TWh) 2007 2008 2009 Change % Ch.

Power generation	25.49	23.33	24.09	0.76	3.3
Trading of electricity (a)	7.70	6.60	9.87	3.27	49.5
	33.19	29.93	33.96	4.03	13.5
Free market	20.73	22.89	24.74	1.85	8.1
Italian power exchange	8.66	3.82	4.70	0.88	23.0
Industrial plants	2.81	2.71	2.92	0.21	7.7
Other (a)	0.99	0.51	1.60	1.09	..
Electricity sales	33.19	29.93	33.96	4.03	13.5

(a) Include positive and negative unbalances.

Transport and regasification of natural gas

Volumes of gas transported in Italy in 2009 were 76.90 bcm decreasing by 8.74 bcm, or 10.2%, from 2008 due to lower gas deliveries due to a weaker demand.
Natural gas volumes transported on behalf of third parties (37.27 bcm) increased by 0.09 bcm, or 10.1%.
In 2009, the LNG terminal in Panigaglia (La Spezia) regasified 1.32 bcm of natural gas (1.52 bcm in 2008).

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

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Gas volumes transported ^(a) (bcm) 2007 2008 2009 Change % Ch.

Eni	52.39	51.80	39.63	(12.17	)	(23.5	)
On behalf of third parties	30.89	33.84	37.27	3.43		10.1
	83.28	85.64	76.90	(8.74	)	(10.2	)

(a) Include amounts destined to domestic storage.

Storage

In 2009, 8.71 bcm of gas were supplied (up 3.44 bcm from 2008) while 7.81 bcm were input to the Company’s storage deposits, an increase of 1.51 bcm compared to 2008. In 2009 storage capacity amounted to 13.9 bcm, of which 5 were destined to strategic storage.
The share of storage capacity used by third parties was 70% (61% in 2008).

2007 2008 2009 Change % Ch.

Total storage capacity:	(bcm)	13.6	13.7	13.9	0.2		1.5
- of which strategic storage		5.1	5.1	5	(0.1	)	(2.0	)
- of which available storage		8.5	8.6	8.9	0.3		3.5
Available capacity: share utilized by Eni	(%)	44	39	30	(9	)	(23.1	)
Total offtake from (input to) storage:	(bcm)	9.27	11.57	16.52	4.95		42.8
- input to storage		4.00	6.30	7.81	1.51		24.0
- offtake from storage		5.27	5.27	8.71	3.44		65.3
Total customers	(No.)	44	48	56	8		16.7

Main development projects for 2009

MARKETING
Natural gas
Finalization of the acquisition of Distrigas
Following the acquisition of the 57.24% majority stake in Distrigas NV from French company Suez-Gaz de France, Eni made an unconditional mandatory public takeover bid on the minorities of Distrigas (42.76% stake), at the same price proposed to Suez (euro 6,809.64 per share)².
On March 19, 2009, the mandatory tender offer on the minorities of Distrigas was finalized. Shareholders representing 41.61% of the share capital of Distrigas, including the second largest shareholder, Publigaz SCRL with a 31.25% interest, tendered their shares. The squeeze-out of the residual 1.14% of the share capital was finalized on May 4, 2009. After this, Distrigas shares have been delisted from Euronext Brussels. The total cash consideration amounted to euro 2,045 million. As of December 31, 2009, Eni owns the entire share capital of Distrigas, except for one share with special powers owned by the Belgian State.
The purchase of Belgian company Distrigas has entailed


a significant expansion of Eni’s supply portfolio with an addition of long-term supplies of approximately 14.7 bcm (from the Netherlands, Norway and Qatar) having a maximum residual life of 18 years. In 2009 Distrigas sales amounted to 17.25 bcm. Projects in the Hewett area
Following the recent acquisition of an interest in the Hewett Unit, pre-development activities progressed for building an offshore storage facility in the Hewett area (Eni’s interest 89%) located in the Southern Gas Basin in the North Sea, near the Bacton terminal. Peak working gas is estimated at 5.6 bcm with a production of approximately 60 mmcm/d. An appraisal well is planned to be drilled shortly, whose outcome will provide further data to confirm those estimates.
The project sanction is expected in 2010 with start up in 2015.

(2) Eni recognized to minority shareholders a certificate granting the right to receive an additional consideration to the bid price for a pro-rata amount of any price revision set as a part of the sale agreement pursuant to which Distrigas sold its subsidiary Distrigas & Co to Belgian operators Fluxys SA and Huberator SA.

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LNG
USA
Cameron In the third quarter of 2009 operations started at the Cameron re-gasification plant located on the banks of the Calcasieu River, approximately 15 miles south of Lake Charles in Louisiana, USA.
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 the regasification capacity. 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.
Taking into account the oversupply characterizing at the moment the US gas market, Eni rescheduled the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant. The start-up is now expected in 2015. Pascagoula This project is part of an upstream development related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 bcm/y) for the North American market in order to market part of the Company’s gas reserves. As part of the downstream leg of the project, Eni signed with Gulf LNG a 20-year contract to buy 5.8 bcm/y of the regasification capacity of the plant under construction near Pascagoula in Mississippi, with expected start up by end of 2012 in line with the start-up of the upstream project in Angola.
At the same time Eni Usa Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 bcm/y of regasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG. REGULATED BUSINESSES IN ITALY
Reorganization of the regulated business in the Italian gas sector
On June 30, 2009 the parent company Eni SpA concluded the sale of the entire share capital of its fully-owned subsidiaries Italgas SpA and Stoccaggi Gas Italia SpA to its subsidiary Snam Rete Gas. The transaction, which was approved by Eni’s Board of Directors in February 2009, included cash consideration amounting to euro 4,509 million (euro 2,922 million and euro 1,587 million, respectively). Snam Rete Gas funded the transaction by means of: (i) a share capital increase amounting to euro 3.5 billion, which was entirely subscribed to by minorities and Eni for their respective shares; and (ii) arranging medium and long-term financing. The main impact expected on Eni’s consolidated financial statements are: (i) as of December 31, 2009 a decrease of euro 1.54 billion was reported in the Group consolidated net borrowings and a corresponding increase in total equity as a consequence of the pro-quota subscription of the Snam Rete Gas capital increase by minorities; (ii) a decrease in Eni’s net profit equal to 45% of the aggregate net profit of Italgas and Stogit reported in the consolidated profit and loss for the second half of 2009, with a corresponding increase in net profit pertaining to minorities.
As of December 31, 2009 Eni’s interest in Snam Rete Gas is equal to 52.54%. SOUTH STREAM PROJECT
New agreement with Gazprom
Based on the agreements signed between Italy and Russia on May 15, 2009, the original scope of work of the project to build the South Stream pipeline has been enlarged, providing for an increase in transport capacity from 31 to 63 bcm/y.
Following the project, the South Stream pipeline is expected to be composed by two sections: (i) an offshore section crossing the Black Sea from the Russian coast at Beregovaya (the same starting point of the Blue Stream pipeline) to the Bulgarian coast at Varna; (ii) an onshore section crossing Bulgaria for which two options are currently being evaluated: one pointing North West and another one pointing South West. The second option envisages crossing Greece and the Adriatic Sea before linking to the Italian network.
In December 2009, Eni and Gazprom signed an agreement for the entrance of French company Edf in the project. The conditions of the agreement will be defined in the coming months. INTERNATIONAL TRANSPORT
Accident at the TMPC pipeline
In 2009, the operation of TMPC gas pipeline was fully restored. One of the five lines of the import pipeline from Algeria was damaged by an oil tanker anchor crossing the Sicily channel on December 19, 2008. Transport continued on the remaining lines. TAG - Russia
In 2009 the upgrading of the TAG pipeline has been finalized increasing the total capacity to the current 37.4 bcm/y. The second 3.3 bcm/y portion of the upgrade started-up in the fourth quarter of 2009 and was entirely awarded to third parties.

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Regulatory framework Legislative Decree No. 164/2000
Legislative Decree No. 164/2000 imposed thresholds to operators until December 31, 2010 calculated as a share of domestic consumption as follows: (i) operators are forbidden from importing into the national transport network imported or domestically produced gas volumes higher than a preset share of Italian final consumption. This share is 61% in the 2009-2010 period; and (ii) operators are forbidden from marketing gas volumes to final customers in excess of 50% of overall volumes marketed to final customers. Compliance with these ceilings is verified yearly by comparing the allowed average share computed on a three-year period for both volumes input and volumes marketed to the actual average share achieved by each operator in the same three-year period. Allowed shares are calculated net of losses (in the case of sales) and volumes of natural gas consumed in own operations. In particular, 2009 closes the sixth three-year regulated period for natural gas volumes input in the domestic transport network, and the fifth three-year regulated period for sales volumes to the Italian market. Eni’s presence on the Italian market complied with said limits. Resolution ARG/gas 64/2009: Approval of the code for the retail sale of natural gas and gas other than natural gas distributed through urban pipeline networks
With resolution ARG 64/2009, the Authority for Electricity and Gas approved the code for the retail sale of natural gas and gas other than natural gas distributed through urban pipeline networks.
Main changes introduced by the Authority refer to the definition of a unique national value for sale price to retail customers, including a new calculation mechanism of distribution tariffs aimed to favor domestic customers with a low consumption profile, and, since October 1, 2009, the review of the formula for calculating the components to cover the wholesale marketing costs. Resolution ARG/gas 159/2008: Tariff criteria for the 2009-2012 regulated period for the service of gas distribution and measurement and transitional rules for 2009
With resolution ARG 159/2008, the Authority for Electricity and Gas approved a new methodology for determining revenues to natural gas distributing companies that operate through local low pressure networks and serve final customers in the residential and tertiary sector. Starting from July 1, 2009 and for the duration of the three-year regulated period, i.e. until 2012, the resolution provides for the recognition of total revenues for each regulated year amounting to a value that the Authority will set at the time of approving the operators’ requests for distribution tariffs and defined as total revenue cap, representing the maximum remuneration recognized by the Authority to each operator for covering costs borne. In previous years, revenues were determined by applying tariffs set by the Authority to volumes actually distributed to selling companies in the relevant year. The resolution also provides for any positive or negative difference between the total revenue cap and revenues resulting from invoices for actually distributed volumes to be regulated through an equalization device making use of credit/debit cards lodged with the Electricity Equalization Exchange. As a result of the new mechanism, revenues are no longer related to the seasonality of volumes distributed. The introduction of this new mechanism does not cause a decline in total revenues on a yearly basis. Law No. 99 July 23, 2009 converting the "Anti-crisis Decree"
Within the framework of measures approved to counter the economic downturn, on June 26, 2009, the Italian Council of Ministers approved the so called "Anti-crisis Decree" whose Article 3 concerns measures for reducing the cost of energy for companies and households and introduces the obligation for Eni to make new sales at the virtual exchange point for a total of 5 bcm of gas (so called gas release) in the period October 2009-September 2010. In particular the decree provides for these sales to be made under non discriminatory competitive procedures (bids) at the terms and conditions decided with proposal of the Authority for Electricity and Gas. The price paid to Eni is determined with a decree of the Ministry for Economic Development, as recommended by the Authority, taking into account the average prices on the most relevant European markets and the structure of supply costs borne by Eni. Any positive difference between the sale price determined by the procedure of volume allocation and that determined by the Ministry and the Authority will be destined to industrial final customers that showed a high use rate of gas withdrawals in the past three years according to criteria determined by the Ministry. The decree provides also that the Authority within 90 days from the entry into force of the same decree: (i) introduces degressive elements in transport tariffs for the 2010-2013 regulatory period; (ii) reforms the balancing methods by adopting flexibility mechanisms providing advantages to all final customers, including industrial customers; (iii) promotes the supply of peak services and storage for industrial and power generation customers. Resolution ARG/gas 184/2009 - Quality and tariff code for the natural gas transport and dispatching services and tariff regulations for the metering service of natural gas transport for the 2010-2013 regulatory period
With resolution ARG/gas 184/2009, published on

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December 2, 2009, the Authority set the criteria regulating the tariffs for natural gas transportation on the national and regional gas pipeline network for the third regulatory period (January 1, 2010 - December 31, 2013).
The Authority also recognized Snam Rete Gas a total amount of euro 33.6 million as settlement of additional costs incurred during the 2007-2008 thermal year and referring to the purchase of fuel gas for compression stations. The Regulatory Asset Base (RAB) is calculated with the re-valuated historical cost methodology.
The allowed rate of return (WACC) on the RAB has been set equal to 6.4% in real terms pre tax.
The new tariff structure confirms the recognition in tariffs of expenditures incurred for network upgrading, providing for a higher remuneration than WACC, changing in a 1-3% range in relation to the nature of expenditures and for a period of 5 to 15 years. Depreciation costs of gas transport infrastructures (gas pipelines) are determined on a 50-year useful technical life and are excluded from the price cap mechanism. Operating costs are defined with reference to operating costs incurred during 2008 and increased by a 50% rate to recognize productivity gains achieved in the second regulatory period. Fuel gas is excluded from the price cap mechanism. The revenue component related to volumes transported is determined referring to operating costs recognized in tariffs and amounts to 15% of the revenue cap. Third Energy Package: 2009 European Directive No. 2009/73/CE
As a part of the so-called "Third Energy Package" published in 2009, European Directive No. 73 regulates the internal market for natural gas requesting that member states choose one of two options for ensuring carriers’ independence in case transport systems belong to vertically integrated companies.
The two options provided are:
(i) Separation of ownership under two alternative modes:
- Ownership Unbundling (OU): the company that owns the networks and manages transport activities is unbundled from its integrated parent company that will retain supply/production and sale activities;
- Independent System Operator (ISO): the vertically integrated company retains ownership of the networks but confers their management to a third independent party.
(ii) Strengthened functional separation:
- Independent Transmission Operator (ITO): the vertically integrated company retains control of the company that manages transport activities and owns transport networks, provided the vertically integrated company refrains from interfering in the decision-making process of the controlled carrier company. Capital expenditures In 2009, capital expenditures totaled euro 1,686 million and mainly related to: (i) developing and upgrading Eni’s transport network in Italy (euro 1,479 million); (ii) developing and upgrading Eni’s storage capacity in Italy (euro 282 million); (iii) developing and upgrading Eni’s distribution network in Italy (euro 278 million); (iv) completion of construction of combined cycle power plants (euro 73 million), in particular at the Ferrara site; (v) the upgrading plan of international pipelines (euro 32 million).

Capital expenditures (euro million) 2007 2008 2009 Change % Ch.

Italy	1,219	1,750	1,564	(186	)	(10.6	)
Outside Italy	292	308	122	(186	)	(60.4	)
	1,511	2,058	1,686	(372	)	(18.1	)
Marketing	238	198	175	(23	)	(11.6	)
Marketing	63	91	102	11		12.1
Italy	13	16	12	(4	)	(25.0	)
Outside Italy	50	75	90	15		20.0
Power generation	175	107	73	(34	)	(31.8	)
Regulated businesses in Italy	1,031	1,627	1,479	(148	)	(9.1	)
Transport	691	1,130	919	(211	)	(18.7	)
Distribution	195	233	278	45		19.3
Storage	145	264	282	18		6.8
International transport	242	233	32	(201	)	(86.3	)
	1,511	2,058	1,686	(372	)	(18.1	)

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Key performance indicators 2007 2008 2009

Net sales from operations (a) (b)	(euro million)	36,349	45,017		31,769
Operating profit		686	(988	)	(102	)
Adjusted operating profit		292	580		(357	)
Adjusted net profit		294	521		(197	)
Capital expenditures		979	965		635
Adjusted capital employed, net at year end (c)		7,149	8,260		7,560
Adjusted ROACE (c)	(%)	4.6	6.5		(2.6	)
Refinery throughputs on own account	(mmtonnes)	37.15	35.84		34.55
Conversion index	(%)	56	58		60
Balanced capacity of refineries	(kbbl/d)	748	737		747
Retail sales of petroleum products in Europe	(mmtonnes)	11.80	12.03		12.02
Service stations in Europe at year end (d)	(units)	6,440	5,956		5,986
Average throughput per service station in Europe (d)	(kliters)	2,486	2,502		2,477
Employees at year end	(units)	9,428	8,327		8,166

(a)	From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programmes be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results have been restated accordingly.
(b)	Before elimination of intragroup sales.
(c)	For a detailed explanation of adjusted capital employed and adjusted ROACE, see paragraph "Return On Average Capital Employed (ROACE)".
(d)	2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Portfolio development and main projects
› On January 21, 2010 Eni signed an agreement for the acquisition of downstream activities in Austria, including a retail network of 135 service stations, wholesale activities (with 36 additional Esso retail service stations owned by third parties) as well as commercial assets in the aviation business and related logistic and storage activities. The finalization of the transaction is subject to the approval of the relevant antitrust authorities.

› The upgrading process of Eni’s retail network of service stations continued aimed at improving service and quality standards. In 2010 the re-branding to "eni" brand of all downstream activities was launched.

Financial results
› In 2009 the Refining & Marketing division reported an adjusted net loss of euro 197 million (down euro 718 million, reversing a prior year profit of euro 521 million) mainly driven by a lower operating performance, reflecting lower refining margins as a result of an

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unfavorable trading scenario, as well as decreased earnings reported by equity-accounted subsidiaries.

› Return on average capital employed on an adjusted basis was a negative 2.6% declining from 2008 (6.5%).

› Capital expenditures totaled euro 635 million and related mainly to projects designed to improve the conversion rate and flexibility of refineries, logistic assets, the upgrade the refined product retail network in Italy and in the rest of Europe.

› In the medium term, management plans to recovery profitability by improving the refining system and reinforcing Eni’s leadership in the Italian retail market and increasing market shares in core European countries.

Operating results
Eni’s refining throughputs for 2009 were 34.55 mmtonnes, down 3.6% from 2008. Lower volumes were recorded in Italy (down 3.3%) as refinery operations were rescheduled at certain plants to take account of weak demand for products. Volumes processed outside Italy declined in particular in the Czech Republic due to lower utilization of plant capacity in response to weak market conditions.

In 2009 Eni’s retail market share in Italy averaged 31.5%, up 0.9 percentage points from 2008 driven by the "You&Agip" promotional campaign, marketing pricing initiatives (in particular the success of the Iperself program), and the opening of new service stations. While Italian consumption was barely unchanged (down 0.6%), retail sales in Italy were 9.03 mmtonnes (up 2.5%) driven by higher volumes of gasoil and LPG sales.

Retail sales in the rest of Europe (approximately 2.99 mmtonnes) decreased by approximately 230 ktonnes, or 7.1%, mainly reflecting a decline in fuel demand, particularly in Eastern Europe.

In 2009 Eni opened/restructured 53 stores for the sale of convenience items and car services at its service stations in Italy. Excluding the impact of the divestment of marketing activities in the Iberian Peninsula in October 2008, non oil revenues were euro 147 million, up 2.4% from 2008.

Supply and trading In 2009, a total of 67.40 mmtonnes of crude were purchased by the Refining & Marketing division (57.91 mmtonnes in 2008), of which 32.75 mmtonnes from Eni’s Exploration & Production division. Volumes amounting to 19.71 mmtonnes were purchased under long-term supply contracts with producing countries, while 14.94 mmtonnes were purchased on the spot market. Approximately 25% of crude purchased in 2009 came from West Africa, 19% from European and Asian Russia, 15% from the Middle East, 13% from North Africa, 11% from the North Sea, 4% from Italy, and 13% from other areas.

Purchases (mmtonnes) 2007 2008 2009 Change % Ch.

Equity crude oil
Eni production outside Italy	27.47		26.14		29.84		3.70		14.2
Eni production in Italy	4.10		3.57		2.91		(0.66	)	(18.5	)
	31.57		29.71		32.75		3.04		10.2
Other crude oil
Purchases on spot markets	11.34		12.09		14.94		2.85		23.6
Purchases under long-term contracts	16.65		16.11		19.71		3.60		22.3
	27.99		28.20		34.65		6.45		22.9
Total crude oil purchases	59.56		57.91		67.40		9.49		16.4
Purchases of intermediate products	3.59		3.39		2.92		(0.47	)	(13.9	)
Purchases of products	16.14		17.42		13.98		(3.44	)	(19.7	)
TOTAL PURCHASES	79.29		78.72		84.30		5.58		7.1
Consumption for power generation	(1.13	)	(1.00	)	(0.96	)	0.04		(4.0	)
Other changes (a)	(2.19	)	(1.04	)	(1.64	)	(0.60	)	(57.7	)
	75.97		76.68		81.70		5.02		6.5

(a) Include change in inventories, decrease in transportation, consumption and losses.

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In 2009 some 36.11 mmtonnes of crude purchased were marketed, up 38.9% from 2008, mainly driven by higher trading activities. In addition, 2.92 mmtonnes of intermediate products were purchased (3.39 mmtonnes in the 2008) to be used as feedstock in conversion plants and 13.98 mmtonnes of refined products (17.42 mmtonnes in the 2008) were purchased to be sold on markets outside Italy (10.10 mmtonnes) and on the domestic market (3.88 mmtonnes) as a complement to available production.
Refining In 2009, refining throughputs on own account in Italy and outside Italy were 34.55 mmtonnes, down 1.29 mmtonnes from 2008, or 3.6%. Volumes processed in Italy decreased by approximately 990 ktonnes, down 3.3%, mainly at the Gela plant due to the extension of planned refinery downtime, and at the Livorno and Taranto plants as refinery operations were rescheduled to take account of a weak demand for products. Volumes processed outside Italy declined by approximately 330 ktonnes in particular in the Czech Republic and in Germany due to lower utilization of plant capacity in response to weak market conditions and the restructuring of the Ingolstadt facility in Germany.
Total throughputs in wholly-owned refineries (24.02 mmtonnes) decreased by 1.57 mmtonnes, down 6.1%, from 2008, due to lower refining throughputs for third parties in the Venezia and Sannazzaro plants for the termination of the agreement with Tamoil at the end of 2008.
Approximately 16.3% of volumes of processed crude was supplied by Eni’s Exploration & Production segment (21.5% in 2008) representing a 5.2 percentage point decrease from 2008, corresponding to a lower volume of 1.87 mmtonnes.

Availability of refined products (mmtonnes) 2007 2008 2009 Change % Ch.

ITALY
At wholly-owned refineries	27.79		25.59		24.02		(1.57	)	(6.1	)
Less input on account of third parties	(1.76	)	(1.37	)	(0.49	)	0.88		64.2
At affiliated refineries	6.42		6.17		5.87		(0.30	)	(4.9	)
Refinery throughputs on own account	32.45		30.39		29.40		(0.99	)	(3.3	)
Consumption and losses	(1.63	)	(1.61	)	(1.60	)	0.01		0.6
Products available for sale	30.82		28.78		27.80		(0.98	)	(3.4	)
Purchases of refined products and change in inventories	2.16		2.56		3.73		1.17		45.7
Products transferred to operations outside Italy	(3.80	)	(1.42	)	(3.89	)	(2.47	)	..
Consumption for power generation	(1.13	)	(1.00	)	(0.96	)	0.04		4.0
Sales of products	28.05		28.92		26.68		(2.24	)	(7.7	)
OUTSIDE ITALY
Refinery throughputs on own account	4.70		5.45		5.15		(0.30	)	(5.5	)
Consumption and losses	(0.31	)	(0.25	)	(0.25	)
Products available for sale	4.39		5.20		4.90		(0.30	)	(5.8	)
Purchases of refined products and change in inventories	13.91		15.14		10.12		(5.02	)	(33.2	)
Products transferred from Italian operations	3.80		1.42		3.89		2.47		..
Sales of products	22.10		21.76		18.91		(2.85	)	(13.1	)
Refinery throughputs on own account	37.15		35.84		34.55		(1.29	)	(3.6	)
of which: refinery throughputs of equity crude on own account	9.29		6.98		5.11		(1.87	)	(26.8	)
Total sales of refined products	50.15		50.68		45.59		(5.09	)	(10.0	)
Crude oil sales	25.82		26.00		36.11		10.11		38.9
TOTAL SALES	75.97		76.68		81.70		5.02		6.5

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Marketing of refined products

In 2009, excluding the impact of the divestment of marketing activities in the Iberian Peninsula in 2008 (down 1.52 mmtonnes), sales volumes of refined products (45.59 mmtonnes) were down 3.57 mmtonnes from 2008, or 7.3%, mainly due to lower wholesale sales on the domestic and foreign market.

Product sales in Italy and outside Italy by market (mmtonnes) 2007 2008 2009 Change % Ch.

Retail	8.62	8.81	9.03	0.22		2.5
Wholesale	11.09	11.15	9.56	(1.59	)	(14.3	)
Petrochemicals	1.93	1.70	1.33	(0.37	)	(21.8	)
Other sales	6.41	7.26	6.76	(0.50	)	(6.9	)
Sales in Italy	28.05	28.92	26.68	(2.24	)	(7.7	)
Retail rest of Europe	3.18	3.22	2.99	(0.23	)	(7.1	)
Wholesale rest of Europe	3.20	3.94	3.66	(0.28	)	(7.1	)
Wholesale outside Italy	0.57	0.56	0.41	(0.15	)	(26.8	)
Other sales	13.11	12.52	11.85	(0.67	)	(5.4	)
Sales outside Italy	20.06	20.24	18.91	(1.33	)	(6.6	)
	48.11	49.16	45.59	(3.57	)	(7.3	)
Iberian Peninsula	2.04	1.52	-	(1.52	)	..
of which:
- Retail	0.85	0.64		(0.64	)	..
- Wholesale	1.19	0.88		(0.88	)	..
TOTAL SALES	50.15	50.68	45.59	(5.09	)	(10.0	)

Retail sales in Italy
In 2009, while domestic consumption was barely unchanged, retail sales on the Italian network (9.03 mmtonnes) were up approximately 220 ktonnes from 2008, or 2.5%, mainly due to fidelity programs, marketing and pricing initiatives, in particular "Iperself" sales, and the opening of new services stations that sustained a 0.9 percentage point growth in market share from 30.6% at December 31, 2008 to 31.5% at December 31,2009. Higher sales mainly regarded gasoil and LPG sales, while gasoline sales declined slightly. At December 31, 2009, Eni’s retail network in Italy consisted of 4,474 service stations, 65 more than at December 31, 2008 (4,409 service stations), resulting from the positive balance of acquisitions/releases of lease concessions (90 units), the opening of new service stations (7 units), partly offset by the closing of service stations with low throughput (24 units) and the release of 9 service stations under highway concession. Average throughput related to gasoline and gasoil (2,482 kliters) registered an increase of 13 kliters from 2008.

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Retail and wholesale sales of refined products (mmtonnes) 2007 2008 2009 Change % Ch.

Italy	19.71	19.96	18.59	(1.37	)	(6.9	)
Retail sales	8.62	8.81	9.03	0.22		2.5
Gasoline	3.19	3.11	3.05	(0.06	)	(1.9	)
Gasoil	5.25	5.50	5.74	0.24		4.4
LPG	0.17	0.19	0.22	0.03		15.8
Lubricants	0.01	0.01	0.02	0.01		..
Wholesale sales	11.09	11.15	9.56	(1.59	)	(14.3	)
Gasoil	4.42	4.52	4.30	(0.22	)	(4.9	)
Fuel Oil	0.95	0.85	0.72	(0.13	)	(15.3	)
LPG	0.37	0.38	0.35	(0.03	)	(7.9	)
Gasoline	0.15	0.15	0.12	(0.03	)	(20.0	)
Lubricants	0.13	0.12	0.09	(0.03	)	(25.0	)
Bunker	1.58	1.70	1.38	(0.32	)	(18.8	)
Other	3.49	3.43	2.60	(0.83	)	(24.2	)
Outside Italy (retail+wholesale)	8.99	7.72	7.06	(0.66	)	(8.5	)
Gasoline	2.29	2.12	1.89	(0.23	)	(10.8	)
Gasoil	5.16	3.80	3.54	(0.26	)	(6.8	)
Jet fuel	0.38	0.47	0.35	(0.12	)	(25.5	)
Fuel Oil	0.25	0.23	0.28	0.05		21.7
Lubricants	0.09	0.11	0.10	(0.01	)	(9.1	)
LPG	0.49	0.52	0.50	(0.02	)	(3.8	)
Other	0.33	0.47	0.40	(0.07	)	(14.9	)
	28.70	27.68	25.65	(2.03	)	(7.3	)
Iberian Peninsula	2.04	1.52	-	(1.52	)	..
TOTAL SALES	30.74	29.20	25.65	(3.55	)	(12.2	)

In 2009, fuel sales of the Blu line – high performance and low environmental impact fuel – recorded lower prices from 2008 with the stability of sales due to marketing initiatives and fidelity programs during the year. Sales of BluDiesel and its reformulated version BluDieselTech amounted approximately to 600 ktonnes (720 mmliters), and represented 10.5% of gasoil sales on Eni’s retail network. At December 31, 2009, service stations marketing BluDiesel totaled 4,104 units (4,095 at 2008 year end) covering approximately 92% of Eni’s network. Retail sales of BluSuper amounted to 82 ktonnes (110 mmliters), in line with 2008 and covered 2.6% of gasoline sales on Eni’s retail network. At December 31, 2009, service stations marketing BluSuper totaled 2,679 units (2,631 at December 31, 2008), covering approximately 60% of Eni’s network.
"You&Agip", the promotional campaign, launched in March 2007 and lasting 3 years finished in 2009. As of December 31, 2009, the number of customers that actively used the card in the year amounted to approximately 5.4 million. The average number of cards active each month was over 3.1 million. Volumes of fuel marketed under this initiative represented over 45% of total volumes marketed on Eni’s service stations joining the program, and 44% of overall volumes marketed on Eni’s network. In February 2010 Eni launched the new promotional campaign "you&eni" lasting 3 years until January 31, 2013.

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Retail sales in the Rest of Europe
Excluding the impact of the divestment of marketing activities in the Iberian Peninsula to Galp (down 0.64 mmtonnes), in 2009 retail sales of refined products marketed in the rest of Europe (2.99 mmtonnes) were down approximately 230 ktonnes from 2008, or 7.1%, mainly in Germany and Eastern Europe due to a decrease in fuel demand. At December 31, 2009, Eni’s retail network in the rest of Europe consisted of 1,512 units, a decrease of 35 units from December 31, 2008 (1,547 service stations). The network evolution was as follows: (i) 32 low throughput service stations were closed; (ii) negative balance of acquisitions/releases of lease concessions (32 units) with negative changes in Germany and positive changes in Hungary; (iii) purchased 21 service stations, in particular in Romania; (iv) opened 8 new outlets.
Average throughput (2,461 kliters) decreased by 116 kliters from 2008. Wholesale and other sales
In 2009, sales volumes on wholesale markets in Italy (9.56 mmtonnes) were down 1.59 mmtonnes from 2008, or 14.3%, reflecting mainly a decrease in demand for jet fuel, the bunkering market and fuel oil for power generation, as well as in gasoil sales due to lower industrial consumption reflecting the economic downturn. Sales on wholesale markets in the rest of Europe (3.66 mmtonnes) decreased by approximately 280 ktonnes, or 7.1% (excluding the impact of asset divestments in the Iberian Peninsula), mainly in Germany, in the Czech Republic and Switzerland due to declining consumption in particular of gasoil for heating.
Supplies of feedstock to the petrochemical industry (1.33 mmtonnes) decreased by approximately 370 ktonnes due to declining demand. Other sales (18.61 mmtonnes) decreased by approximately 1.17 mmtonnes, or 5.9%, mainly due to lower sales volumes to trader and oil companies, as well as the reduction of volumes sold to the cargo market, also due to lower refining throughputs.
Capital expenditures In 2009, capital expenditures in the Refining & Marketing segment amounted to euro 635 million and regarded mainly: (i) refining, supply and logistics in Italy (euro 436 million), with projects designed to improve the conversion rate and flexibility of refineries, including the construction of an industrial plant employing the Eni’s proprietary Est technology, a new hydrocracker at the Sannazzaro refinery (operating from July) and at the Taranto refinery (start up scheduled in 2010) as well as expenditures on health, safety and environmental upgrades; (ii) upgrade of the retail network in Italy, wholesale and LPG activities (euro 118 million); (iii) upgrade of the retail network and purchase of service stations in the rest of Europe (euro 54 million). Expenditures on health, safety and the environment amounted to euro 78 million.

Capital expenditures (euro million) 2007 2008 2009 Change % Ch.

Italy	873	850	581	(269	)	(31.6	)
Outside Italy	106	115	54	(61	)	(53.0	)
	979	965	635	(330	)	(34.2	)
Refinery, supply and logistic	675	630	436	(194	)	(30.8	)
Italy	675	630	436	(194	)	(30.8	)
Marketing	282	298	172	(126	)	(42.3	)
Italy	176	183	118	(65	)	(35.5	)
Outside Italy	106	115	54	(61	)	(53.0	)
Other	22	37	27	(10	)	(27.0	)
	979	965	635	(330	)	(34.2	)

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Key performance indicators 2007 2008 2009

Net sales from operations (a)	(euro million)	6,934	6,303		4,203
Basic petrochemicals		3,582	3,060		1,832
Polymers		3,109	2,961		2,185
Other sales		243	282		186
Operating profit		100	(845	)	(675	)
Adjusted operating profit		116	(398	)	(426	)
Adjusted net profit		74	(323	)	(340	)
Capital expenditures		145	212		145
Production	(ktonnes)	8,795	7,372		6,521
Sales of petrochemical products		5,513	4,684		4,265
Average plant utilization rate	(%)	80.6	68.6		65.4
Employees at period end	(units)	6,534	6,274		6,068

(a) Before elimination of intragroup sales.

› In 2009, the Petrochemical segment incurred an adjusted net loss of euro 340 million, a decrease of euro 17 million from 2008, due to a prolonged weakness in industry fundamentals reflecting lower end-market demand and high competitive pressure.

› Sales of petrochemical products were 4,265 ktonnes, down 419 ktonnes from last year, or 8.9%, due to a context of economic downturn, especially in the automotive sector, that negatively influenced demand for petrochemical products.

› Petrochemical production volumes were 6,521 ktonnes, down 851 ktonnes, or 11.5%, due to a steep decline in demand for petrochemical products in all business.

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Sales - production - prices In 2009 sales of petrochemical products (4,265 ktonnes) decreased by 419 ktonnes from 2008 (or 8.9%) due to a general weakness of end-markets in the first nine months of 2009 with a slight recovery in demand for polymers in the last quarter. Petrochemical production (6,521 ktonnes) decreased by 851 ktonnes from 2008 (or 11.5%) affecting all business areas. The general demand decrease in the chemical industry, in particular for commodities, required unexpected outages in a number of plants in order to avoid excess stocks. Relevant production decreases were registered at the Porto Torres plant (down 51%), as result of the shutdown of the phenol plant at the beginning of the year and of reduced production for commercial reasons.
Nominal production capacity decreased by 3.3% from 2008, due to the shutdown of the Gela cracker and the Porto Torres phenol plant. The average plant utilization rate, calculated on nominal capacity decreased from 68.6% to 65.4% due to reduced production. Average unit sale prices decreased by 26%. The steeper decreases affected the prices of the main petrochemical products (olefins were down 35%), due to the negative impact of the oil price scenario (virgin naphtha was down 32.3% from 2008). Average unit prices of polymers, in particular elastomers (down 17%) decreased less, due to a slower adjustment to the oil scenario and to expected price increases in 2010.

Product availability (ktonnes) 2007 2008 2009 Change % Ch.

Basic petrochemicals	6,274		5,110		4,350		(760	)	(14.9	)
Polymers	2,521		2,262		2,171		(91	)	(4.0	)
Production	8,795		7,372		6,521		(851	)	(11.5	)
Consumption and losses	(4,099	)	(3,539	)	(2,701	)	838		(23.7	)
Purchases and change in inventories	816		851		445		(406	)	(47.7	)
	5,513		4,684		4,265		(419	)	(8.9	)

Business trends

Basic petrochemicals
Basic petrochemical revenues (euro 1,832 million) decreased by euro 1,228 million from 2008 (or 40.1%) in all the main business segments due to the steep reduction in average unit prices (ranging from 25% to 35%) related to the prices of main petrochemical products, and to a lower extent to the decrease in sales volumes. In particular olefins and aromatics sales volumes decreased by 8% and 10.5%, respectively, with a slight increase in the last quarter of 2009. Intermediates sales volumes continued to report a negative performance (down 34%) as a result of lower product availability due to the shutdown of the Porto Torres plant as a result of the unfavorable scenario.
Basic petrochemicals production (4,350 ktonnes) decreased by 760 ktonnes from 2008 (or 14.9%), in line with lower demand of monomers. Polymers
Polymer revenues (euro 2,185 million) decreased by euro 776 million, or 26.2%, from 2008, mainly due to price reductions.
Sales volumes of polyethylene decreased by 1.3% in spite of a slight demand increase registered in the last months of the year. Styrene sales achieved a stable performance and compact polystyrene sales increased by 2.5% from 2008. Sales decreases were registered mainly in elastomers (down 7%) due to a greater impact of industrial sectors affected by the economic downturn (mainly automotive).
Polymers production (2,171 ktonnes) decreased by 91 ktonnes from 2008 (or 4%), in line with sales trends. Production volumes of styrene and elastomers decreased by 3% mainly due to the shutdown of the Porto Torres plant. Elastomers production decreased by 8.8% as a result of plants outages, mainly in the first months of 2009 due to lower demand from industries, in particular the automotive sector.
Capital expenditures In 2009, capital expenditures in the Petrochemicals segment amounted to euro 145 million (euro 212 million in 2008) and regarded mainly plant upgrades (euro 58 million), extraordinary maintenance (euro 28 million), environmental protection, safety and environmental regulation compliance (euro 28 million), upkeeping and rationalization (euro 20 million).

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Key performance indicators 2007 2008 2009

Net sales from operations (a)	(euro million)	8,678	9,176	9,664
Operating profit		837	1,045	881
Adjusted operating profit		840	1,041	1,120
Adjusted net profit		658	784	892
Capital expenditures		1,410	2,027	1,630
Adjusted ROACE (b)	(%)	17.1	16.8	15.4
Orders acquired	(euro million)	11,845	13,860	9,917
Order backlog	(euro million)	15,390	19,105	18,730
Employees at period end	(units)	33,111	35,629	35,969

(a)	Before elimination of intragroup sales.
(b)	For a detailed explanation of adjusted capital employed and adjusted ROACE, see paragraph "Return On Average Capital Employed (ROACE)".

› Adjusted net profit was euro 892 million, up euro 108 million from a year ago, or 13.8%, driven by steady revenue flows and profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.

› Operating profit decreased to euro 881 million, down euro 164 million from 2008, or 15.7%, as a result of a non-recurring charge amounting to euro 250 million reflecting the estimated cost of a possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with US Authorities. The matter is fully disclosed under the section "Legal Proceedings" in the notes to the consolidated statements. Notwithstanding the charge is recognized in the segment results of the Engineering & Construction business as it relates to a project to build gas liquefaction plants, it will be fully incurred by Eni and Saipem’s minorities will be left unaffected due to the contractual obligations assumed by Eni to indemnify Saipem as part of the divestiture of Snamprogetti SpA, whose subsidiary Snamprogetti Netherlands BV participated to the TSKJ venture.

› Return on average capital employed calculated on an adjusted basis was 15.4% in 2009, lower than in 2008 (16.8%).

› Orders acquired amounted to euro 9,917 million, down euro 3,943 million from 2008 (down 28.4%), in particular in onshore construction and drilling onshore activities.

› Order backlog was euro 18,730 million at December 31, 2009 (euro 19,105 million at December 31, 2008), related in particular to projects in North Africa (30%), West Africa (15%) and the Rest of Europe (13%).

› Capital expenditures amounted to euro 1,630 million, down euro 397 million from 2008, or 19.6%. The main projects related to the upgrade of the construction and drilling fleet.

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Activity for the year Among the main orders acquired in 2009 were:
- an EPC contract on behalf of the joint venture between Eni and Sonatrach for the construction of facilities for the treatment of natural gas extracted from the Menzel Ledjmet East field and from the future developments of the CAFC (Central Area Field Complex) in Algeria;
- an EPC contract on behalf of Agip KCO as part of the development program of the Kashagan field related to the hook-up and commissioning of offshore facilities, as well as activities to be executed in the Kuryk construction yard in Kazakhstan;
- a contract on behalf of Eni for the conversion of a tanker into an FPSO (Floating Production Storage and Offloading) vessel that will have a storage and production capacity of 700 kbbl/d and 12 kbbl/d, respectively;
- an EPC contract on behalf of Sonatrach for the construction of the GK3-lot 3 gas pipeline that will connect various cities situated in the north-eastern region of Algeria for a total length of approximately 350 kilometers;
- an EPC contract on behalf of Esso Exploration Angola for the development of Kizomba Satellites Project offshore Angola. The project is related to the connection of the Mavacola and Clochas fields to the existing FPSO units;
- an EPC contract on behalf of Qafco for the construction of a new urea plant in the city of Mesaieed, in Qatar;
- a contract on behalf of Esso Highlands Ltd, for the installation of the gas sealine PNG LNG EPC2 for a total length of 407 kilometers, in Papua New Guinea;
- an EPIC contract on behalf of Premier Oil Natuna Sea BV for the construction of two platforms and related infrastructures in the Gajah Baru offshore field in Indonesia;
- an EPC contract on behalf of Sonatrach for the construction of a marine export terminal for the future urea/ammonia plant to be built near Arzew, in Algeria. Orders acquired amounted to euro 9,917 million, of these projects to be carried out outside Italy represented 79%, while orders from Eni companies amounted to 32% of the total. Eni’s order backlog was euro 18,730 million at December 31, 2008 (euro 19,105 million at December 31, 2008). Projects to be carried out outside Italy represented 93% of the total order backlog, while orders from Eni companies amounted to 22% of the total.

Orders acquired (euro million) 2007 2008 2009 Change % Ch.

Orders acquired	11,845		13,860	9,917	(3,943	)	(28.4	)
Offshore construction	3,496		4,381	5,089	708		16.2
Onshore construction	6,070	(a)	7,522	3,665	(3,857	)	(51.3	)
Offshore drilling	1,644		760	585	(175	)	(23.0	)
Onshore drilling	635		1,197	578	(619	)	(51.7	)
of which:
- Eni	1,923		540	3,147	2,607		..
- Third parties	9,922		13,320	6,770	(6,550	)	(49.2	)
of which:
- Italy	574		831	2,081	1,250		..
- Outside Italy	11,271		13,029	7,836	(5,193	)	(39.9	)

(a) Net of the backlog of divested companies (Haldor Topsøe and Camom Group) for euro 181 million.

Order backlog (euro million) Dec. 31, 2007 Dec. 31, 2008 Dec. 31, 2009 Change % Ch.

Order backlog	15,390		19,105	18,730	(375	)	(2.0	)
Offshore construction	4,215		4,682	5,430	748		16.0
Onshore construction	7,003	(a)	9,201	8,035	(1,166	)	(12.7	)
Offshore drilling	3,471		3,759	3,778	19		0.5
Onshore drilling	701		1,463	1,487	24		1.6
of which:
- Eni	3,399		2,547	4,103	1,556		61.1
- Third parties	11,991		16,558	14,627	(1,931	)	(11.7	)
of which:
- Italy	799		435	1,341	906		..
- Outside Italy	14,591		18,670	17,839	(831	)	(4.5	)

(a) Net of the backlog of divested companies (Haldor Topsøe and Camom Group) for euro 181 million.

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Capital expenditures In 2009 capital expenditures in the Engineering & Construction segment (euro 1,630 million) mainly regarded:
(i) Offshore: purchase of the lay barge Acergy Piper renamed Castoro Sette, construction of a new pipelayer and the ultra-deep water Field Development Ship FDS2, construction of a new fabrication yard in Indonesia and the activities for the conversion of a tanker into an FPSO;
(ii) Offshore drilling: construction of the two semisubmersible rigs Scarabeo 8 and 9, the new ultra deep water drillship Saipem 12000 and the jack up Perro Negro 6;
(iii) Onshore drilling: construction/development of operating structures;
(iv) Onshore: maintenance and upgrading of the existing asset base.

  Capital expenditures (euro million) 2007 2008 2009 Change % Ch.

Offshore construction	566	741	691	(50	)	(6.7	)
Onshore construction	76	48	19	(29	)	(60.4	)
Offshore drilling	478	785	706	(79	)	(10.1	)
Onshore drilling	266	424	188	(236	)	(55.7	)
Other expenditures	24	29	26	(3	)	(10.3	)
	1,410	2,027	1,630	(397	)	(19.6	)

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Financial review

PROFIT AND LOSS ACCOUNT

2007 (euro million) 2008 2009 Change % Ch.

87,204		Net sales from operations (a)	108,082		83,227		(24,855	)	(23.0	)
833		Other income and revenues	728		1,118		390		53.6
(61,933	)	Operating expenses	(80,354	)	(62,532	)	17,822		22.2
(8	)	of which non recurring items	21		(250	)	(271	)
(129	)	Operating income (expense) (b)	(124	)	55		179		..
(7,236	)	Depreciation, depletion, amortization and impairments	(9,815	)	(9,813	)	2		..
18,739		Operating profit	18,517		12,055		(6,462	)	(34.9	)
46		Finance (expense) income	(640	)	(551	)	89		13.9
1,243		Net income from investments	1,373		569		(804	)	(58.6	)
20,028		Profit before income taxes	19,250		12,073		(7,177	)	(37.3	)
(9,219	)	Income taxes	(9,692	)	(6,756	)	2,936		30.3
46.0		Tax rate (%)	50.3		56.0		5.7
10,809		Net profit	9,558		5,317		(4,241	)	(44.4	)
		Attributable to:
10,011		- Eni	8,825		4,367		(4,458	)	(50.5	)
798		- minority interest	733		950		217		29.6

(a)

From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programmes be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results have been restated accordingly.

(b)

From year 2009, the Company accounts gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and settled transactions, as items of operating profit. Adjusted operating profit and net profit only include gains and losses associated with settled transactions, gross and net of the associated tax impact respectively. Prior period results have been restated accordingly.

Net profit
In 2009 Eni’s net profit was euro 4,367 million compared with euro 8,825 million a year ago, down euro 4,458 million, or 50.5%. This result was driven by lower reported operating profit (down euro 6,462 million, or 34.9%) reflecting an unfavorable trading environment for oil prices, which were significantly lower than a year ago in the first nine months of the year. This trend was partly offset by the circumstance that the Company incurred a material charge related to inventory write-down of oil and products (down euro 2.35 billion) as they were aligned to their net realizable value at 2008 year end when the oil cycle hit a low. Group results were also affected by lower profits reported by equity-accounted entities, and a higher consolidated tax rate up from 50.3% to 56% (up 5.7 percentage points), mainly due to new tax rules in Italy and outside Italy which impacted taxes currently payable, charges accounted in the year which are not considered for fiscal purposes, and the circumstance that in 2008 the tax rate benefited from certain tax gains associated with an adjustment to deferred taxation amounting to euro 733 million as new tax provisions came into effect pertaining to both Italian and foreign subsidiaries.

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Adjusted net profit

2007 (euro million) 2008 2009 Change % Ch.

10,011		Net profit attributable to Eni	8,825		4,367		(4,458	)	(50.5	)
(499	)	Exclusion of inventory holding (gain) loss	723		(191	)	(914	)
57		Exclusion of special items	616		1,031		415
		of which:
35		- non recurring items	(21	)	250		271
22		- other special items	637		781		144
9,569		Eni's adjusted net profit (a)	10,164		5,207		(4,957	)	(48.8	)

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

Eni’s adjusted net profit for the year was euro 5,207 million compared with euro 10,164 million a year ago, down euro 4,957 million, or 48.8%.
Adjusted net profit excludes an inventory holding profit of euro 191 million and net special charges of euro 1,031 million, resulting in an overall adjustment equal to an increase of euro 840 million. The balance between special charges and gains is comprised of, on the negative side, impairment charges recorded on oil & gas properties in the Exploration & Production division, refineries and goodwill recognized on marketing assets in the Refining & Marketing division, and a number of petrochemicals plants (euro 1,395 million as before tax impact) as well as environmental (euro 298 million) and operational provisions (euro 378 million), including a non-recurring charge amounting to euro 250 million reflecting the estimated cost of a possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section "Legal Proceedings" in the notes to the consolidated financial statements. Notwithstanding the charge is recognized in the segment results of the Engineering & Construction business as it relates to a project to build gas liquefaction plants, it will be fully incurred by Eni and Saipem’s minorities will be left unaffected altogether due to the contractual obligations assumed by Eni to indemnify Saipem as part of the divestiture of Snamprogetti SpA, whose subsidiary Snamprogetti Netherlands BV participates to the TSKJ venture. On the positive side, gains were recorded on the divestment of certain oil & gas properties to the partner Suez (euro 277 million), gains on fair value evaluation of certain non-hedging commodity derivatives (euro 287 million), and positive adjustments on deferred taxation and other tax benefits (euro 222 million). The breakdown of adjusted net profit by division is shown in the table below:

2007 (euro million) 2008 2009 Change % Ch.

6,328		Exploration & Production	7,900		3,878		(4,022	)	(50.9	)
3,127		Gas & Power	2,648		2,916		268		10.1
294		Refining & Marketing	521		(197	)	(718	)	..
74		Petrochemicals	(323	)	(340	)	(17	)	(5.3	)
658		Engineering & Construction	784		892		108		13.8
(210	)	Other activities	(279	)	(245	)	34		12.2
(62	)	Corporate and financial companies	(532	)	(744	)	(212	)	(39.8	)
(16	)	Impact of unrealized intragroup profit elimination (a)	76		(3	)	(79	)	..
10,193			10,795		6,157		(4,638	)	(43.0	)
		of which attributable to:
624		- Minority interest	631		950		319		50.6
9,569		- Eni	10,164		5,207		(4,957	)	(48.8	)

(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.

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The decline in group adjusted net profit reflected lower results mainly reported by:
- the Exploration & Production division reported a decrease of euro 4,022 million in adjusted net profit, down 50.9%, due to a weaker operating performance (down euro 7,738 million, or 44.9%) affected by lower oil & gas realizations in dollars (down 32.2% and 29.8%, respectively) and lower sales volumes (down 9.2 mmboe, or 1.5%). These negatives were partly offset by the depreciation of the euro over the dollar (down 5.3%). The divisional performance was also impacted by a higher tax rate (from 55.9% to 60%);
- the Refining & Marketing division reported adjusted net loss of euro 197 million, reversing a prior year profit of euro 521 million. The euro 718 million decline was mainly due to an adjusted operating loss of euro 357 million, a decrease of euro 937 million from 2008, driven by sharply lower refining margins as a result of an unfavorable trading environment;
- the Petrochemicals division continued to report losses at both operating and net level (down euro 426 million and euro 340 million, respectively) due to weak industry fundamentals reflecting lower end markets demand, excess capacity and high competitive pressures. Net loss was almost in line with 2008. These negative performances were partly offset by higher results reported by:
- the Gas & Power division (up euro 268 million, or 10.1%) driven by a better operating performance of the Marketing activities (up euro 412 million). Higher results in the Marketing activities were also driven by gains recorded on the settlement of certain non-hedging commodity derivatives amounting to euro 218 million associated with future sales of gas and electricity. Under IFRS, the Company is required to recognize fair value accounting effects on those derivatives in profit or loss because hedge accounting is not followed. However, in assessing the underlying performance of the Marketing business, management calculates the EBITDA pro-forma adjusted as an alternative measure of performance, by bringing forward the impact of the settlement of those derivatives to future reporting periods where the associated revenues are expected to be recognized. Management believes that disclosing this internally-used measure is helpful in assisting investors to understand these business trends (see page 67). When measured against this performance indicator, the Marketing business confirmed the achievement of positive results. The underlying performance was mainly driven by a favorable trading environment related to energy parameters, improved results reported by the subsidiary Distrigas and the achievement of synergies on integration, as well as the impact of the renegotiation of long-term supply contracts. These positives were partly offset by lower sales volumes, mainly on the Italian market and the impact of rising competitive pressure on marketing margins. Regulated Businesses in Italy recorded steady results. The International transport business reported weaker results;
- the Engineering & Construction business achieved an increase of euro 108 million from 2008, or 13.8% reflecting better operating performance (up euro 79 million) driven by steady revenue flows and profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle. Return on average capital employed (ROACE) calculated on an adjusted basis was 9.2% (17.6% in 2008). Eni’s results for 2009 were achieved in a trading environment characterized by an average 31.2% decrease in hydrocarbon realizations driven by a fall in Brent prices which were down 36.6% from 2008. Eni’s realized refining margins in dollar terms were sharply lower in the full year 2009, mirroring trends in Brent margins (down $3.4 per barrel, or 51.8%). A number of negative factors explained the reduction. Firstly, significantly compressed light-heavy crude differentials due to a reduction in heavy crude availability on the marketplace negatively affected the profitability of Eni’s complex refineries. Secondly, the industry continued to be plagued by weak fundamentals due to excess capacity, high inventory levels and stagnant demand affecting end-prices, while feedstock costs have been on an upward trend since the beginning of the second half. Finally, middle-distillates prices plunged to historical lows in terms of spread versus the cost of oil. Results of operations for the full year were helped by the depreciation of the euro vs. the US dollar, down by 5.3%.

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Analysis of profit and loss account items

Net sales from operations

2007 (euro million) 2008 2009 Change % Ch.

26,920		Exploration & Production	33,042		23,801		(9,241	)	(28.0	)
27,793		Gas & Power	37,062		30,447		(6,615	)	(17.8	)
36,349		Refining & Marketing	45,017		31,769		(13,248	)	(29.4	)
6,934		Petrochemicals	6,303		4,203		(2,100	)	(33.3	)
8,678		Engineering & Construction	9,176		9,664		488		5.3
205		Other activities	185		88		(97	)	(52.4	)
1,313		Corporate and financial companies	1,331		1,280		(51	)	(3.8	)
		Impact of unrealized intragroup profit elimination	75		(66	)	(141	)
(20,988	)	Consolidation adjustment	(24,109	)	(17,959	)	6,150		..
87,204			108,082		83,227		(24,855	)	(23.0	)

Eni’s net sales from operations (revenues) for 2009 (euro 83,227 million) were down euro 24,855 million from 2008 (down 23%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms and lower sales volumes. These negatives were partly offset by the positive impact of the depreciation of the euro vs. the US dollar. Revenues generated by the Exploration & Production division (euro 23,801 million) decreased by euro 9,241 million, or 28%, mainly due to lower realizations in dollars (oil down 32.2%; natural gas down 29.8%) reflecting the first nine months trading environment and the impact of energy parameters on gas prices and a fall in gas spot prices. This decrease reflected also lower sales volumes (down 9.2 mmboe, or 1.5%). These negatives were partly offset by the depreciation of the euro vs. the US dollar. Revenues generated by the Gas & Power division (euro 30,447 million) decreased by euro 6,615 million, down 17.8%, mainly due to lower gas prices reflecting trends in energy parameters, as well as lower volumes sold in Italy (down 12.8 bcm, or 24.2%) due to the impact of the economic downturn. These negatives were partly offset by increased sales due to contribution of the Distrigas acquisition (up 12.02 bcm). Revenues generated by the Refining & Marketing division (euro 31,769 million) decreased by euro 13,248 million, or 29.4%, reflecting lower product prices and lower sales volumes (down 10%), partly offset by the impact of the depreciation of the euro vs. the US dollar. Revenues generated by the Petrochemical division (euro 4,203 million) decreased by euro 2,100 million, down 33.3% from 2008, mainly reflecting lower sales prices (down 26%) and a decline in volumes sold due to lower end-markets demand. Revenues generated by the Engineering & Construction business (euro 9,664 million) increased by euro 488 million, up 5.3% from 2008, as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.

Operating expenses

2007 (euro million) 2008 2009 Change % Ch.

58,133		Purchases, services and other	76,350		58,351	(17,999	)	(23.6	)
		of which:
91		- non-recurring items	(21	)	250	271
470		- other special items	761		537	(224	)
3,800		Payroll and related costs	4,004		4,181	177		4.4
		of which:
(83	)	- non-recurring items
198		- provision for redundancy incentives	91		134	43
61,933			80,354		62,532	(17,822	)	(22.2	)

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ENI ANNUAL REPORT / FINANCIAL REVIEW AND OTHER INFORMATION

Operating expenses for the year (euro 62,532 million) decreased by euro 17,822 million from 2008, down 22.2%. Purchases, services and other costs (euro 58,351 million) decreased by euro 17,999 million (down 23.6%) due to lower supply costs of purchased oil, gas and petrochemical feedstocks, partially offset by the depreciation of the euro against the dollar.
Purchases, services and other included environmental and other risk provisions, as well as impairments of certain current and non-current assets, other than tangible and intangible assets, amounting to euro 537 million. Non-recurring items represented by a charge amounting to euro 250 million, estimated on the basis of the possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section "Legal Proceedings" in the notes to the consolidated financial statements.
In 2008, environmental and risk provisions as well as impairments of certain current assets amounted to euro 761 million. Payroll and related costs (euro 4,181 million) increased by euro 177 million (up 4.4%) mainly due to higher unit labor cost in Italy and outside Italy, partly due to exchange rate translation differences, the increase in the average number of employees outside Italy, following the consolidation of Distrigas in the Gas & Power division, increased personnel in the Engineering & Construction and Exploration & Production businesses due to higher activity levels, as well as increased provisions for redundancy incentives. These increases were partially offset by a decrease in the average number of employees in Italy.

Depreciation, depletion, amortization and impairments

2007 (euro million) 2008 2009 Change % Ch.

5,431		Exploration & Production	6,678		6,789		111		1.7
739		Gas & Power	797		981		184		23.1
433		Refining & Marketing	430		408		(22	)	(5.1	)
116		Petrochemicals	117		83		(34	)	(29.1	)
248		Engineering & Construction	335		433		98		29.3
4		Other activities	3		2		(1	)	(33.3	)
68		Corporate and financial companies	76		83		7		9.2
(10	)	Impact of unrealized intragroup profit elimination	(14	)	(17	)	(3	)
7,029		Total depreciation, depletion and amortization	8,422		8,762		340		4.0
207		Impairments	1,393		1,051		(342	)	(24.6	)
7,236			9,815		9,813		(2	)	..

Depreciation, depletion and amortization (euro 8,762 million) increased by euro 340 million from 2008 (up 4%) mainly in the Gas & Power and Exploration & Production divisions (up euro 184 million and euro 111 million, respectively) in connection with rising development amortization charges reflecting consolidation of acquired assets and increased expenditures to develop new complex fields. These negatives were partly offset by the depreciation of the euro against the dollar. Impairment charges of euro 1,051 million mainly regarded: (i) impairment charges recorded on proved and unproved properties in the Exploration & Production division due to downward reserve revisions and cost increases mainly recorded in the Gulf of Mexico, Australia, Congo and Egypt; (ii) refinery plants with low complexity, impairment of goodwill recognized on marketing assets acquired in Central-Eastern Europe and certain other marketing assets in the Refining & Marketing division, in the light of the negative outlook for the refining industry and a downsizing of growth expectations on certain markets; (iii) a number of plants in the Petrochemical division due to a worsening pricing/margin environment as a result of lower petrochemical demand, excess capacity and higher competitive pressure.

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The breakdown of impairment charges by division is shown in the table below:

2007 (euro million) 2008 2009 Change % Ch.

143	Exploration & Production	810	576	(234	)	(28.9	)
	Gas & Power	1		(1	)	..
58	Refining & Marketing	299	346	47		15.7
	Petrochemicals	279	121	(158	)	(56.6	)
	Engineering & Construction		2	2		..
6	Other activities	4	6	2		50.0
207		1,393	1,051	(342	)	(24.6	)

Operating profit
The breakdown of the reported operating profit by division is provided below:

2007 (euro million) 2008 2009 Change % Ch.

13,433		Exploration & Production	16,239		9,120		(7,119	)	(43.8	)
4,465		Gas & Power	4,030		3,687		(343	)	(8.5	)
686		Refining & Marketing	(988	)	(102	)	886		89.7
100		Petrochemicals	(845	)	(675	)	170		20.1
837		Engineering & Construction	1,045		881		(164	)	(15.7	)
(444	)	Other activities	(346	)	(382	)	(36	)	(10.4	)
(312	)	Corporate and financial companies	(743	)	(474	)	269		36.2
(26	)	Impact of unrealized intragroup profit elimination	125				(125	)
18,739		Operating profit	18,517		12,055		(6,462	)	(34.9	)

Adjusted operating profitThe breakdown of adjusted operating profit by division is provided below:

2007 (euro million) 2008 2009 Change % Ch.

18,739		Operating profit	18,517		12,055		(6,462	)	(34.9	)
(620	)	Exclusion of inventory holding (gains) losses	936		(345	)	(1,281	)
885		Exclusion of special items	2,155		1,412		(743	)
		of which:
8		- non-recurring items	(21	)	250		271
877		- other special items	2,176		1,162		(1,014	)
19,004		Adjusted operating profit	21,608		13,122		(8,486	)	(39.3	)
		Breakdown by division:
13,770		Exploration & Production	17,222		9,484		(7,738	)	(44.9	)
4,414		Gas & Power	3,564		3,901		337		9.5
292		Refining & Marketing	580		(357	)	(937	)	..
116		Petrochemicals	(398	)	(426	)	(28	)	(7.0	)
840		Engineering & Construction	1,041		1,120		79		7.6
(207	)	Other activities	(244	)	(258	)	(14	)	(5.7	)
(195	)	Corporate and financial companies	(282	)	(342	)	(60	)	(21.3	)
(26	)	Impact of unrealized intragroup profit elimination	125				(125	)
19,004			21,608		13,122		(8,486	)	(39.3	)

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Eni’s adjusted operating profit amounted to euro 13,122 million, a reduction of euro 8,486 million from 2008 (down 39.3%). Adjusted operating profit is calculated by excluding an inventory holding profit of euro 345 million and special losses of euro 1,412 million. This reduction is mainly due to a weaker performance recorded by the following divisions:
- the Exploration & Production division performance (down euro 7,738 million, or 44.9%) was driven by lower oil and natural gas realizations in dollars (down 32.2% and 29.8%, respectively) and lower production sales volumes (down 9.2 mmboe). These negatives were partly offset by the depreciation of the euro over the dollar (approximately euro 500 million);
- the Refining & Marketing division reported an adjusted operating loss of euro 357 million (down euro 937 million) driven by sharply lower refining margins as a result of weak industry fundamentals and weaker results reported by the Marketing business;
- the Petrochemicals division reported an operating loss of euro 426 million (down euro 28 million, or 7%) due to a prolonged weakness in industry fundamentals reflecting lower end-markets demand and high competitive pressures.
These negatives were partly offset by the better operating performance recorded by:
- the Gas & Power division improved performance (up euro 337 million, or 9.5%) was driven by a better operating performance of the Marketing activities. This reflected gains recorded on the settlement of certain non-hedging commodity derivatives amounting to euro 218 million, associated with future sales of gas and electricity. Under IFRS, the Company is required to recognize fair value accounting effects on those derivatives in profit or loss because hedge accounting is not followed. However, in assessing the underlying performance of the Marketing business, management calculates the EBITDA pro-forma adjusted as an alternative measure of performance, by bringing forward the impact of the settlement of those derivatives to future reporting periods where the associated revenues are expected to be recognized. Management believes that disclosing this internally-used measure is helpful in assisting investors to understand these business trends (see page 67). When measured against this performance indicator, the Marketing business confirmed the achievement of positive results driven by a favorable trading environment related to energy parameters and exchange rates, the improved results of the subsidiary Distrigas and the achievement of synergies on integration, as well as the impact of the renegotiation of long-term supply contracts. These positives were partly offset by lower sales volumes (down 12.8 bcm), mainly on the Italian market and the impact of the competitive pressure on sale margins. The International Transport business recorded a drop in operating profit;
- the Engineering & Construction increased results (up euro 79 million, or 7.6%) were due to steady revenue flows and profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.

Finance income (expense)

2007 (euro million) 2008 2009 Change

(412	)	Finance income (expense) related to net borrowings	(824	)	(673	)	151
(703	)	Finance expense on short and long-term debt	(993	)	(753	)	240
236		Net interest due to banks	87		33		(54	)
55		Net income from receivables and securities for non-financing operating activities	82		47		(35	)
155		Income (expense) on derivatives	(427	)	(4	)	423
(51	)	Exchange differences, net	206		(106	)	(312	)
174		Other finance income and expense	169		9		(160	)
188		Income from equity instruments	241		163		(78	)
127		Net income from receivables and securities for financing operating activities and interest on tax credits	99		43		(56	)
(186	)	Finance expense due to the passage of time (accretion discount)	(249	)	(218	)	31
45		Other	78		21		(57	)
(134	)		(876	)	(774	)	102
180		Finance expense capitalized	236		223		(13	)
46			(640	)	(551	)	89

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In 2009, net finance expenses decreased by euro 89 million to euro 551 million from 2008, mainly due to lower finance charges on finance debt due to lower interest rates on both euro-denominated (down 3.4 percentage points) and dollar loans (down 2.2 percentage points). Increased exchange differences losses (up euro 312 million) were offset by gains recognized in connection with fair value evaluation through profit and loss of certain derivative instruments on exchange rates (up euro 423 million). The main financial gains amounting to euro 163 million, related to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft, calculated until April 24, 2009, when Gazprom paid for the call option exercised on April 7, 2009. The gain also included the recovery of certain collateral operating expenses and other charges for a total amount of euro 172 million ($229 million at the exchange rate of the payment date).

Net income from investments
The table below sets forth the breakdown of net income from investments by division:

2009
(euro million) Exploration
& Production Gas
& Power Refining
& Marketing Engineering
& Construction Othersegments Group

Share of gains (losses) from equity-accounted investments	142	310		(70	)	50		(39	)	393
Dividends	110	13		39		2				164
Gains on disposal	3	2		1		10				16
Other income (expense), net	1	(3	)			(3	)	1		(4	)
	256	322		(30	)	59		(38	)	569

Net income from investments amounted to euro 569 million and related to: (i) Eni’s share of profit of entities accounted for with the equity method (euro 393 million), mainly in the Gas & Power and Exploration & Production divisions. Gains also comprised an equity gain on the 60% interest in Artic Russia (euro 100 million) due to the divestment of a 51% stake in OOO Severenergia to Gazprom based on the call option exercised by the Russian company; (ii) dividends received by entities accounted for at cost (euro 164 million), mainly related to Nigeria LNG Ltd. The table below sets forth a breakdown of net income/loss from investments for 2009:

2007 (euro million) 2008 2009 Change

773	Share of gains (losses) from equity-accounted investments	640	393		(247	)
170	Dividends	510	164		(346	)
300	Gains on disposal	217	16		(201	)
	Other income (expense), net	6	(4	)	(10	)
1,243		1,373	569		(804	)

The decrease of euro 804 million from 2008 related to lower profit and dividends from equity or cost-accounted entities in the Gas & Power and Exploration & Production divisions driven by an unfavorable trading environment, as well as the circumstance that in 2008 a net gain of euro 190 million on the divestment of certain interests was recorded in the Engineering & Construction segment.

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Income taxes

2007 (euro million) 2008 2009 Change

	Profit before income taxes
5,849	Italy	1,894	2,403	509
14,179	Outside Italy	17,356	9,670	(7,686	)
20,028		19,250	12,073	(7,177	)
	Income taxes
1,798	Italy	313	1,190	877
7,421	Outside Italy	9,379	5,566	(3,813	)
9,219		9,692	6,756	(2,936	)
	Tax rate (%)
30.7	Italy	16.5	49.5	33.0
52.3	Outside Italy	54.0	57.6	3.6
46.0		50.3	56.0	5.7

Income taxes were euro 6,756 million, down euro 2,936 million, or 30.3%, mainly reflecting lower income taxes currently payable by subsidiaries in the Exploration & Production division operating outside Italy due to lower taxable profit. Reported tax rate increased by 5.7 percentage points due to:
(i) the impact of recently enacted tax regulations that provided a one-percentage point increase in the tax rate applicable to Italian companies in the energy sector and the enactment of a supplemental tax rate to be added to the Italian statutory tax rate resulting in higher taxes currently payable, amounting to euro 239 million in the full year;
(ii) the recognition of a non-recurring item which is not considered for fiscal purposes represented by a charge amounting to euro 250 million that was estimated on the base of the possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section "Legal Proceedings" in the notes to the consolidated financial statements;
(iii) the payment of a balance for prior-year income taxes amounting to $310 million (or euro 230 million) in Libya as new rules came into effect which reassessed revenues for tax purposes;
(iv) a write-down of certain deferred tax assets associated with upstream properties to factor in expected lower profitability (down euro 72 million);
(v) a lower capacity for Italian companies to deduct the cost of goods sold associated with lower gas inventories at year end (down euro 64 million);
(vi) the circumstance that in 2008 certain tax gains associated with an adjustment to deferred taxation amounting to euro 733 million were recorded as new tax provisions came into effect pertaining to both Italian and foreign subsidiaries.
These higher tax expenses were partly offset by recognition of a positive adjustment to deferred taxation following alignment of the tax base of certain oil and gas properties to their higher carrying amounts by paying a one-off tax, as part of the reorganization of upstream activities in Italy, and lower income taxes currently payable as new rules came into effect providing for the partial deduction of an Italian local tax from taxable income, also applying to previous fiscal years (for a total positive impact of euro 222 million). Adjusted tax rate, calculated as ratio of income taxes to net profit before taxes on an adjusted basis, was 53.6% (51.4% in 2008). Minority interest
Minority interest’s share of profit was euro 950 million and related mainly to Snam Rete Gas SpA (euro 369 million) and Saipem SpA (euro 567 million).

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Divisional performance¹

Exploration & Production ^(a)

2007 (euro million) 2008 2009 Change % Ch.

13,433		Operating profit	16,239		9,120		(7,119	)	(43.8	)
337		Exclusion of special items	983		364
		of which:
(11	)	Non-recurring items
348		Other special items:	983		364
226		- asset impairments	989		618
		- gains on disposals of assets	4		(270	)
6		- provision for redundancy incentives	8		31
74		- re-measurement gains/losses on commodity derivatives	(18	)	(15	)
42		- other
13,770		Adjusted operating profit	17,222		9,484		(7,738	)	(44.9	)
60		Net finance income (expense) (b)	70		(23	)	(93	)
176		Net income (expense) from investments (b)	609		243		(366	)
(7,678	)	Income taxes (b)	(10,001	)	(5,826	)	4,175
54.8		Tax rate (%)	55.9		60.0		4.1
6,328		Adjusted net profit	7,900		3,878		(4,022	)	(50.9	)
		Results also include:
5,574		amortizations and depreciations	7,488		7,365		(123	)	(1.6	)
		of which:
1,777		exploration expenditures	2,057		1,551		(506	)	(24.6	)
1,370		- amortizations of exploratory drilling expenditure and other	1,577		1,264		(313	)	(19.8	)
407		- amortizations of geological and geophysical exploration expenses	480		287		(193	)	(40.2	)

(a)	From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit following restructuring of Eni’ regulated gas businesses in Italy that was approved by the Company’s Board of Directors and is expected to close by mid-year. Prior period results have been restated accordingly.
(b)	Excluding special items.

In 2009, the Exploration & Production division reported an adjusted operating profit of euro 9,484 million, a decrease of euro 7,738 million compared to 2008, or 44.9%, driven by lower oil & gas realizations in dollars (down 32.2% and down 29.8%, respectively) and lower sales volumes (down 9.2 mmboe). These negatives were partly offset by the depreciation of the euro over the dollar (approximately euro 500 million). Special charges excluded by adjusted operating profit amounted to euro 364 million and comprised impairments of proved and unproved mineral interests mainly due to downward reserve revisions and cost increases, mainly in the Gulf of Mexico. Gains were recorded on the divestment of certain exploration and production assets as part of the agreements signed with Suez, while re-measurement losses were recorded on fair value evaluation of the ineffective portion of certain cash flow hedges and provisions for redundancy incentives. In 2009 liquids and gas realizations decreased on average by 31.2% in dollar terms, driven by lower oil prices for market benchmarks (Brent crude price decreased by 36.6%), partly offset by a relative appreciation of the Eni equity basket (down 32.2%).
Eni’s average oil realizations were barely unchanged, due to the settlement of certain commodity derivatives relating to the sale of 42.2 mmbbl.
In the first nine months of the year, liquids realizations increased by $0.45 per barrel from the sale of 31.6 mmbbl at the hedged price. The gain was absorbed by the reduction on average by $1.46 per barrel from the sale of 10.6 mmbbl in the fourth quarter, reflecting the inversion in oil prices trends.
These derivatives were entered into to hedge exposure to variability in future cash flows expected from the sale of a portion of the Company’s proved reserves, in connection with the acquisition of oil and gas assets in Congo and in the Gulf of Mexico, for an original amount

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

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of approximately 125.7 mmbbl in the 2008-2011 period, decreasing to approximately 37.5 mmbbl by end of 2009. In 2009 average gas realizations were down 29.8%, driven by time-lags between movements in oil prices and their effect on gas prices provided in pricing formulae and weak spot prices. Liquids realizations and the impact of commodity derivatives were as follows:

Liquids 2008 2009

Sales volumes	(mmbbl)	364.3		373.5
Sales volumes hedged by derivatives (cash flow hedge)		46.0		42.2
Total price per barrel, excluding derivatives	($/bbl)	88.17		56.98
Realized gains (losses) on derivatives		(4.13	)	(0.03	)
Total average price per barrel	($/bbl)	84.05		56.95

Gas & Power^(a)

2007 (euro million) 2008 2009 Change % Ch.

4,465		Operating profit	4,030		3,687		(343	)	(8.5	)
44		Exclusion of inventory holding (gains) losses	(429	)	326
(95	)	Exclusion of special items:	(37	)	(112	)
		of which:
(61	)	Non-recurring items
(34	)	Other special items:	(37	)	(112	)
15		- environmental provisions	12		19
		- asset impairments	1		27
		- gains on disposals of assets	7		(6	)
		- risk provisions			115
38		- provisions for redundancy incentives	20		25
(16	)	- re-measurement gains/losses on commodity derivatives	(74	)	(292	)
(71	)	- other	(3	)
4,414		Adjusted operating profit	3,564		3,901		337		9.5
2,284		Marketing	1,309		1,721		412		31.5
1,685		Regulated business in Italy	1,732		1,796		64		3.7
445		International transport	523		384		(139	)	(26.6	)
(5	)	Net finance income (expense) (b)	(13	)	(15	)	(2	)
420		Net income (expense) from investments (b)	420		332		(88	)
(1,702	)	Income taxes (b)	(1,323	)	(1,302	)	21
35.2		Tax rate (%)	33.3		30.9		(2.4	)
3,127		Adjusted net profit	2,648		2,916		268		10.1

(a)

From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit, within the regulated businesses results, following restructuring of Eni regulated gas businesses in Italy. As of that date, the results of the regulated businesses in Italy therefore include results of the Transport, Distribution, Re-gasification and Storage activities in Italy. Results of the Power generation activity are reported within the Marketing business as it is ancillary to the latter. Prior period results have been restated accordingly.

(b)

Excluding special items.

In 2009 the Gas & Power division reported adjusted operating profit of euro 3,901 million, an increase of euro 337 million compared to 2008, up 9.5%, driven by a better operating performance of the Marketing activities (up euro 412 million, or 31.5%). This reflected gains recorded on the settlement of certain non-hedging commodity derivatives amounting to euro 218 million, associated with future sales of gas and electricity. Under IFRS, the Company is required to recognize fair value accounting effects on those derivatives in profit or loss because hedge accounting is not followed. However, in assessing the underlying performance of the Marketing business, management calculates the EBITDA pro-forma adjusted as an alternative measure of performance, by bringing forward the impact of the settlement of those derivatives to future reporting periods where the associated revenues are expected to be recognized. Management believes that disclosing

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this internally-used measure is helpful in assisting investors to understand these business trends (see below). When measured against this performance indicator, the Marketing business confirmed the achievement of positive results driven by a favorable trading environment related to energy parameters and exchange rates, the improved results of the subsidiary Distrigas and the achievement of synergies on integration, as well as the impact of the renegotiation of certain long-term supply contracts. These positives were partly offset by lower sales volumes, mainly on the Italian market and the impact of rising competitive pressures. The International Transport business recorded a drop in operating profit. Special items excluded from the adjusted operating profit amounted to euro 112 million and mainly regarded a provision in the LNG business and re-measurement impacts recorded on fair value evaluation of certain non-hedging commodity derivatives (euro 292 million) in the Marketing business, as well as provisions for redundancy incentives. Adjusted net profit was euro 2,916 million, increasing by euro 268 million from 2008 (up 10.1%) due to an improved operating performance and offset in part by lower earnings reported by equity accounted entities. Marketing
The Marketing business reported adjusted operating profit of euro 1,721 million, an increase of euro 412 million from 2008, or 31.5%. This mainly reflected gains on the settlement of certain non-hedging commodity derivatives amounting to a euro 218 million gain associated with future sales of gas and electricity. Net of this effect, the Marketing business showed a positive performance despite the sharp decline in sales volumes in Italy, down by approximately a fourth (down 12.8 bcm) and the impact of competitive pressures on margins. An improved scenario for energy parameters, the contribution of the acquisition of Distrigas in terms of integration synergies and improved performance together with the impact of the renegotiation of long-term supply contracts were the main positive trends for the year. Regulated businesses in Italy
Regulated businesses in Italy reported adjusted operating profit of euro 1,796 million, up euro 64 million, or 3.7% from 2008, due to an improved performance reported by Distribution activities (up euro 72 million) driven by a positive impact associated with a new tariff regime set by the Authority for Electricity and Gas. This positive was partly offset by weaker results reported by Transport activities (down euro 52 million), caused by a decline in gas demand in Italy, despite the recognition of new investments in tariffs. The Storage business reported an increased adjusted operating profit from a year ago (euro 227 million and euro 183 million in 2009 and 2008, respectively). International Transport
This business reported adjusted operating profit of euro 384 million, representing a decrease of euro 139 million from 2008, or 26.6%, mainly due to the recognition of higher amortization charges related to the upgrading of the TTPC pipeline and costs incurred to repair and restore to full capacity the TMPC pipeline which was damaged in an accident occurred in December 2008. Other performance indicators
Follows a breakdown of the pro-forma adjusted EBITDA by business:

2007 (euro million) 2008 2009 Change % Ch.

5,029		Pro-forma EBITDA adjusted	4,310	4,403		93		2.2
3,061		Marketing	2,271	2,392		121		5.3
(64	)	of which: +/(-) adjustment on commodity derivatives	119	(133	)
1,248		Regulated businesses in Italy	1,284	1,345		61		4.8
720		International transport	755	666		(89	)	(11.8	)

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 impact associated with certain derivatives instruments as discussed below. This performance indicator includes the adjusted EBITDA of Eni’s wholly owned subsidiaries and Eni’s share of adjusted EBITDA generated by certain associates which are accounted for under the equity method for IFRS purposes. Snam Rete Gas’ EBITDA is included according to Eni’s share of equity (55.57%

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as of December 31, 2009, which takes into account the amount of own shares held in treasury by the subsidiary itself) although this Company is fully consolidated when preparing consolidated financial statements in accordance with IFRS, due to its listed company status. Italgas SpA and Stoccaggi Gas Italia SpA results are also included according to the same share of equity as Snam Rete Gas, due to the closing of the restructuring deal which involved Eni’s regulated business in the Italian gas sector, whereby the parent company Eni SpA divested the entire share capital of the two subsidiaries to Snam Rete Gas. In order to calculate the EBITDA pro-forma adjusted, the adjusted operating profit of the Marketing business is 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. Those are entered into by the Company in view of certain amounts of gas and electricity that the Company expects to supply at fixed prices in future periods. The impact of those derivatives is allocated to the EBITDA pro-forma adjusted relating to the reporting periods during which those supplies at fixed prices are recognized. Management believes that the EBITDA pro-forma adjusted is an important alternative measure to assess the performance of Eni’s Gas & Power division, taking into account evidence that this division is comparable to European utilities in the gas and power generation sector. This measure is provided in order to assist investors and financial analysts in assessing the Eni Gas & Power divisional performance 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.

Refining & Marketing

2007 (euro million) 2008 2009 Change % Ch.

686		Operating profit	(988	)	(102	)	886		(89.7	)
(658	)	Exclusion of inventory holding (gains) losses	1,199		(792	)
264		Exclusion of special items	369		537
		of which:
35		Non-recurring items	(21	)
229		Other special items:	390		537
128		- environmental provisions	76		72
58		- asset impairments	299		389
		- gains on disposals of assets	13		(2	)
9		- risk provisions			17
31		- provisions for redundancy incentives	23		22
6		- re-measurement gains/losses on commodity derivatives	(21	)	39
(3	)	- other
292		Adjusted operating profit	580		(357	)	(937	)	..
		Net finance income (expense) (a)	1				(1	)
126		Net income (expense) from investments (a)	174		75		(99	)
(124	)	Income taxes (a)	(234	)	85		319
29.7		Tax rate (%)	31.0		..		..
294		Adjusted net profit	521		(197	)	(718	)	..

(a) Excluding special items.

In 2009 the Refining & Marketing division reported an adjusted operating loss of euro 357 million, reversing a prior year profit of euro 580 million. The marked decrease (down euro 937 million from 2008) was mainly driven by sharply lower refining margins as a result of an unfavorable trading environment, due to narrowing price differentials between heavy and light crude and excess finished products, in particular diesel oil, whose spread on raw material reached historical lows in the fourth quarter. Full year results were also affected by lower operating performance delivered by the Marketing activities. An improved performance was delivered in the first nine months reflecting market share gains posted by the Italian retailing activities supported by effective marketing campaigns and pricing initiatives, which were more than offset by lower marketed volumes affected by weak demand on wholesale markets in Italy and retail European markets.

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Special charges excluded from adjusted operating profit amounted to euro 537 million and mainly related to asset impairment charges recorded in the light of the negative outlook for the refining industry and a downsizing of the growth expectations on certain markets. In particular, impairment charges affected low complexity refineries, including refineries participated by Eni, goodwill recognized on marketing assets acquired in Central-Eastern Europe, marketing assets in Europe and capital expenditures for the period on assets impaired in previous reporting periods. Other special charges mainly related to environmental and other risk provisions and re-measurement losses recorded on fair value evaluation of certain non-hedging commodity derivatives. Full-year adjusted net loss was euro 197 million (down euro 718 million, reversing a prior year profit of euro 521 million), mainly due to a lower operating performance (down euro 937 million) and decreased earnings reported by equity-accounted entities.

Petrochemicals

2007 (euro million) 2008 2009 Change % Ch.

100		Operating profit	(845	)	(675	)	170		20.1
(6	)	Exclusion of inventory holding (gains) losses	166		121
22		Exclusion of special items	281		128
		of which:
(2	)	Non-recurring items
24		Other special items:	281		128
		- asset impairments	278		121
		- gains on disposals of assets	(5	)
24		- provisions for redundancy incentives	8		10
		- re-measurement gains/losses on commodity derivatives			(3	)
116		Adjusted operating profit	(398	)	(426	)	(28	)	(7.0	)
1		Net finance income (expense) (a)	1				(1	)
1		Net income (expense) from investments (a)	(9	)			9
(44	)	Income taxes (a)	83		86		3
74		Adjusted net profit	(323	)	(340	)	(17	)	(5.3	)

(a) Excluding special items.

The Petrochemical division reported an adjusted operating loss of euro 426 million, an increase of euro 28 million from 2008, due to a prolonged weakness in industry fundamentals reflecting lower end-markets demand and high competitive pressures.
Special charges excluded from adjusted operating loss of euro 128 million related mainly to impairment of assets, in particular the Porto Marghera and Sicily plants for the production of olefins, aromatics and polyethylene, due to an expected unfavorable trading environment in terms of margins/volumes, affected by lower petrochemical products demand and higher competitive pressures, in connection with new available capacity in the Middle-East.

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Engineering & Construction

2007 (euro million) 2008 2009 Change % Ch.

837		Operating profit	1,045		881		(164	)	(15.7	)
3		Exclusion of special items	(4	)	239
		of which:
(4	)	Non-recurring items			250
7		Other special items:	(4	)	(11	)
		- asset impairments			2
		- gains on disposals of assets	(4	)	3
7		- provisions for redundancy incentives
		- re-measurement gains/losses on commodity derivatives			(16	)
840		Adjusted operating profit	1,041		1,120		79		7.6
		Net finance income (expense) (a)	1				(1	)
80		Net income (expense) from investments (a)	49		49
(262	)	Income taxes (a)	(307	)	(277	)	30
28.5		Tax rate (%)	28.1		23.7		(4.4	)
658		Adjusted net profit	784		892		108		13.8

(a) Excluding special items.

The Engineering & Construction division reported an adjusted operating profit increasing by euro 79 million or 7.6%, to euro 1,120 million, reflecting steady revenue flows and profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle.
Special charges excluded from adjusted operating profit related mainly to a non-recurring item represented by a charge amounting to euro 250 million that was estimated on the basis of the possible resolution of the investigation related to the TSKJ consortium based on the current status of the ongoing discussions with U.S. Authorities. The matter is fully disclosed in the section "Legal Proceedings" in the notes to the consolidated financial statements.
Adjusted net profit amounted to euro 892 million, an increase of euro 108 million from 2008.

Other activities

2007 (euro million) 2008 2009 Change % Ch.

(444	)	Operating profit	(346	)	(382	)	(36	)	(10.4	)
237		Exclusion of special items	102		124
		of which:
61		Non-recurring items
176		Other special items:	102		124
210		- environmental provisions	101		153
6		- asset impairments	5		5
		- gains on disposals of assets	(14	)	(2	)
13		- risk provision	4		(4	)
18		- provisions for redundancy incentives	4		8
(71	)	- other	2		(36	)
(207	)	Adjusted operating profit	(244	)	(258	)	(14	)	(5.7	)
(8	)	Net financial income (expense) (a)	(39	)	12		51
5		Net income (expense) from investments (a)	4		1		(3	)
(210	)	Adjusted net profit	(279	)	(245	)	34		12.2

(a) Excluding special items.

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Corporate and financial companies

2007 (euro million) 2008 2009 Change % Ch.

(312	)	Operating profit	(743	)	(474	)	269		36.2
117		Exclusion of special items	461		132
		of which:
(10	)	Non-recurring items
127		Other special items:	461		132
12		- environmental provisions	120		54
		- gains on disposals of assets	(9	)
32		- provisions for redundancy incentives	28		38
83		- re-measurement gains/losses on commodity derivatives	52
		- other	270		40
(195	)	Adjusted operating profit	(282	)	(342	)	(60	)	(21.3	)
(25	)	Net financial income (expense) (a)	(661	)	(525	)	136
4		Net income (expense) from investments (a)	5				(5	)
154		Income taxes (a)	406		123		(283	)
(62	)	Adjusted net profit	(532	)	(744	)	(212	)	(39.8	)

(a) Excluding special items.

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Non-GAAP measures

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

Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses and special items. Further more, finance charges on finance debt, interest income, gains or losses deriving from 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 of 34% is applied to finance charges and income (33% in previous reporting periods). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or U.S. GAAP. Management includes them in order to facilitate a comparison of base business performance across periods and allow financial analysts to evaluate Eni’s 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 transaction, 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 management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives, including the ineffective portion of cash flow hedges. 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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2009

(euro million) E&P G&P R&M Petrochemicals Engineering
& Construction Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	9,120		3,687		(102	)	(675	)	881		(382	)	(474	)			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	)	124		132				1,162
- environmental charges			19		72						153		54				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		124		132				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:
- Adjusted net profit of minority interest																	950
- Eni's adjusted net profit																	5,207
Eni's reported net profit																	4,367
Exclusion of inventory holding (gains) losses																	(191	)
Exclusion of special items:																	1,031
- non-recurring (income) charges																	250
- other special (income) charges																	781
Eni's adjusted net profit																	5,207

(a) Excluding special items.

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2008

(euro million) E&P G&P R&M Petrochemicals Engineering
& Construction Other activities Corporate and financial companies Impact of unrealized intragroup profit elimination Group

Reported operating profit	16,239		4,030		(988	)	(845	)	1,045		(346	)	(743	)	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	)	102		461				2,176
- environmental charges			12		76						101		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	)	102		461				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:
- Adjusted net profit of minority interest																	631
- Eni's adjusted net profit																	10,164
Eni's reported net profit																	8,825
Exclusion of inventory holding (gains) losses																	723
Exclusion of special items:																	616
- non-recurring (income) charges																	(21	)
- other special (income) charges																	637
Eni's adjusted net profit																	10,164

(a) Excluding special items.

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2007

(euro million) E&P G&P R&M Petrochemicals Engineering
& Construction 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:
- Adjusted net profit of minority interest																	624
- Eni's adjusted net profit																	9,569
Eni's reported net profit																	10,011
Exclusion of inventory holding (gains) losses																	(499	)
Exclusion of special items:																	57
- non-recurring (income) charges																	35
- other special (income) charges																	22
Eni's adjusted net profit																	9,569

(a) Excluding special items.

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Breakdown of special items

2007 (euro million) 2008 2009

8		Non-recurring charges (income)	(21	)	250
		of which:
		- estimated charge of the possible resolution of the TSKJ matter			250
(83	)	- curtailment recognized of the reserve for post-retirement benefits for Italian employees
91		- provisions and utilizations against proceedings	(21	)
877		Other special charges (income):	2,176		1,162
365		- environmental charges	309		298
290		- asset impairments	1,572		1,162
		- gains on disposal of assets	(8	)	(277	)
22		- risk provisions	4		128
156		- provision for redundancy incentives	91		134
147		- re-measurement gains/losses on commodity derivatives	(61	)	(287	)
(103	)	- other	269		4
885		Special items of operating profit	2,155		1,412
(23	)	Net financial (expense) income
(321	)	Net income from investments	(239	)	179
		of which, gain on divestment of:
(290	)	- Haldor Topsøe AS and Camom SA
		- GTT (Gaztransport et Technigaz SAS)	(185	)
(658	)	Income taxes	(1,402	)	(560	)
		of which:
		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	)
(394	)	adjustment to deferred tax for Italian subsidiaries
		adjustment to deferred tax for Libyan assets	(173	)
		impairment of deferred tax assets E&P			72
(50	)	other special items	(46	)	(192	)
(214	)	taxes on special items of operating profit	(623	)	(413	)
(117	)	Total special items of net profit	514		1,031
		attributable to:
(174	)	- Minority interest	(102	)
57		- Eni	616		1,031

Breakdown of impairments

2007 (euro million) 2008 2009 Change

207	Tangible and intangible asset impairments	1,349	993	(356	)
	Goodwill impairments	44	58	14
207	Sub total	1,393	1,051	(342	)
83	Impairment losses on current and non-current assets	179	111	(68	)
290	Impairments	1,572	1,162	(410	)

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Summarized Group Balance Sheet

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

Summarized Group Balance Sheet ^(a)

(euro million) Dec. 31, 2008 Dec. 31, 2009 Change

Fixed assets
Property, plant and equipment	59,255		63,177		3,922
Inventories - compulsory stock	1,196		1,736		540
Intangible assets	7,697		8,057		360
Equity-accounted investments and other investments	5,881		6,244		363
Receivables and securities held for operating purposes	1,219		1,261		42
Net payables related to capital expenditures	(787	)	(749	)	38
	74,461		79,726		5,265
Net working capital
Inventories	6,082		5,495		(587	)
Trade receivables	16,444		14,916		(1,528	)
Trade payables	(12,590	)	(10,078	)	2,512
Tax payables and provision for net deferred tax liabilities	(5,323	)	(1,988	)	3,335
Provisions	(9,506	)	(10,319	)	(813	)
Other current and non-current assets and liabilities (b)	(4,544	)	(3,968	)	576
	(9,437	)	(5,942	)	3,495
Current investments	2,741				(2,741	)
Provisions for employee post-retirement benefits	(947	)	(944	)	3
Net assets held for sale including related net borrowings	68		266		198
CAPITAL EMPLOYED, NET	66,886		73,106		6,220
Shareholders' equity:
- Eni	44,436		46,073		1,637
- Minority interest	4,074		3,978		(96	)
	48,510		50,051		1,541
Net borrowings	18,376		23,055		4,679
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	66,886		73,106		6,220

(a)	For a reconciliation to the statutory balance sheet see the paragraph "Reconciliation of summarized group balance sheet and summarized group cash flow statement to statutory schemes".
(b)	Include receivables and securities for financing operating activities for euro 339 million (euro 410 million at December 31, 2008) and securities covering technical reserves of Eni's insurance activities for euro 284 million (euro 302 million at December 31, 2008).

The appreciation of the euro, in particular versus the US dollar, from December 31, 2008 (the EUR/USD exchange rate was 1.441 as of December 31, 2009, as compared to 1.392 as of December 31, 2008, up 3.5%) reduced net capital employed, net equity and net borrowings by euro 894 million, euro 869 million and euro 25 million, respectively, as a result of translation differences. At December 31, 2009, net capital employed totaled euro 73,106 million, representing an increase of euro 6,220 million from December 31, 2008. Fixed assets
Fixed assets amounted to euro 79,726 million, representing an increase of euro 5,265 million from December 31, 2008, reflecting capital expenditures incurred in the period

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ENI ANNUAL REPORT / FINANCIAL REVIEW AND OTHER INFORMATION

(euro 13,695 million) and the recognition of the share of goodwill associated with the buy-out of the Distrigas minorities (euro 903 million), partly offset by depreciation, depletion, amortization and impairment charges (euro 9,813 million). The item intangible assets included among fixed assets, increased by euro 360 million to euro 8,057 million mainly due to the completion of the Distrigas acquisition whereby goodwill increased by the amount of goodwill pertaining to Distrigas minorities (euro 903 million) following the buyout, thus increasing the total amount of goodwill recognized on the acquisition to euro 2,148 million. In order to test the recoverability of its carrying amount, the Distrigas goodwill has been allocated to the group of cash generating unit forming the European gas market cash generating unit that is expected to benefit from synergies of the acquisition. Net working capital
At December 31, 2009, net working capital amounted to a negative euro 5,942 million, representing an increase of euro 3,495 million from December 31, 2008, mainly due to:
- lower tax payables and provisions for net deferred tax liabilities (up euro 3,335 million) related to lower income taxes accrued for the period, reflecting lower taxable profit;
- lower trade payables partly offset by a corresponding reduction in trade receivables, reflecting the impact of lower prices and volumes of commodities, resulting in an increase of euro 984 million;
- a reduction in the item other liabilities net (up euro 576 million) associated with (i) the derecognition of the put option awarded to Publigaz Scrl in 2008 as accounted in Eni 2008 financial statements (euro 1,495 million) following Publigaz tendering its 31.25% share in Distrigas to Eni as part of Eni’s mandatory buy-out of Distrigas minorities. This put option was carried at the same price provided in the public tender offer; (ii) a deferred cost classified as non current assets in the statutory balance sheet which related to amounts of gas which were collected below minimum take quantities for the year provided by take-or-pay clauses contained in certain long-term gas purchase contracts. Those volumes were recorded contra a trade payable for an amount of euro 255 million based on the contractual purchase price formula provided in the relevant contractual arrangements and the contractual percentage of advance, as aligned to their net realizable value as of year end. The Company expects to collect the underlying gas volumes over a period longer than the next twelve months.
These increases in net working capital have been partly offset by: - a decrease in gas inventories as a result of gas off-takes made during winter time (down euro 587 million);
- environmental and operational provisions, legal proceeding provisions and oil & gas asset decommissioning provisions accrued in the year, including the impact of lower interest rates in evaluating the discount factor of future obligations, for a total amount of euro 813 million;
- the negative change of euro 502 million (from a negative euro 28 million to a negative euro 530 million; respectively down euro 28 million and euro 312 million net of taxes) in fair value of certain derivative instruments Eni entered into to hedge exposure to variability in future cash flows deriving from the sale in the 2008-2011 period of approximately 2% of Eni’s proved reserves as of December 31, 2006 corresponding to 125.7 mmboe, decreasing to 37.5 mmboe as of end of December 2009 due to transactions settled in the year. These hedging transactions were undertaken in connection with acquisitions of oil and gas assets in the Gulf of Mexico and Congo in 2007. The effective portion of changes in fair value of these hedges is recognized directly in equity, whilst the ineffective portion is recognized in profit and loss. The line item equity instruments decreased by an amount corresponding to the book value of a 20% interest in Gazprom Neft (euro 2,741 million at the 2008 balance sheet date) as on April 7, 2009 the Russian company Gazprom exercised its call option on the whole interest based on the arrangements in place with Eni. On April 4, 2007, Eni acquired the 20% interest in OAO Gazprom Neft, following finalization of a bid as part of the Yukos liquidation procedures. At that time, Eni granted Gazprom a call option on the entire 20% to be exercisable by Gazprom within 24 months from the acquisition date, at a price of $3.7 billion equaling the bid price, as modified by subtracting dividends distributed, a contractual remuneration of 9.4% on the capital employed and financing collateral expenses. Total cash consideration amounting to euro 3,070 million ($4.06 billion, increasing to approximately euro 3.16 billion or $4.2 billion when including the 2008 dividend) was paid by Gazprom on April 24, 2009. Net assets held for sale including related liabilities (euro 266 million) mainly related to the divestment of certain mineral properties in Italy which were contributed in kind to two newcos Società Padana Energia SpA and Società Adriatica Idrocarburi SpA as well as the company Gas Brasiliano Distribuidora SA operating in marketing and distribution of natural gas in Brazil, whose disposal to third parties is under negotiation.

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Return On Average Capital Employed (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 minority interest, 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% effective from January 1, 2009. The capital invested as of period-end used for the calculation of net average capital invested is obtained by deducting inventory gains or losses as of 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 division specific tax rate).

December 31, 2009 (euro million) Exploration
& Production Gas
& Power Refining
& Marketing Group

Adjusted net profit	3,878	2,916	(197	)	6,157
Exclusion of after-tax finance expenses/interest income	-	-	-		283
Adjusted net profit unlevered	3,878	2,916	(197	)	6,440
Adjusted capital employed, net:
- at the beginning of period	30,362	22,547	7,379		66,886
- at the end of period	32,455	25,024	7,560		72,915
Adjusted average capital employed, net	31,409	23,786	7,470		69,901
Adjusted ROACE (%)	12.3	12.3	(2.6	)	9.2

December 31, 2008 (euro million) Exploration
& Production Gas
& Power Refining
& Marketing Group

Adjusted net profit	7,900	2,648	521	10,795
Exclusion of after-tax finance expenses/interest income	-	-	-	335
Adjusted net profit unlevered	7,900	2,648	521	11,130
Adjusted capital employed, net:
- at the beginning of period	23,826	21,333	7,675	59,194
- at the end of period	30,362	22,273	8,260	67,609
Adjusted average capital employed, net	27,094	21,803	7,968	63,402
Adjusted ROACE (%)	29.2	12.2	6.5	17.6

December 31, 2007 (euro million) Exploration
& Production Gas
& Power Refining
& Marketing Group

Adjusted net profit	6,328	3,127	294	10,193
Exclusion of after-tax finance expenses/interest income	-	-	-	174
Adjusted net profit unlevered	6,328	3,127	294	10,367
Adjusted capital employed, net:
- at the beginning of period	17,783	19,713	5,631	47,966
- at the end of period	23,826	21,364	7,149	58,695
Adjusted average capital employed, net	20,805	20,539	6,390	53,331
Adjusted ROACE (%)	30.4	15.2	4.6	19.4

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Leverage and net borrowings

Leverage is a measure used by management to asses the Company’s level of indebtedness. It is calculated as 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 minority 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.

(euro million) Dec. 31, 2008 Dec. 31, 2009 Change

Total debt	20,837		24,800		3,963
- Short-term debt	6,908		6,736		(172	)
- Long-term debt	13,929		18,064		4,135
Cash and cash equivalents	(1,939	)	(1,608	)	331
Securities held for non-operating purposes	(185	)	(64	)	121
Financing receivables for non-operating purposes	(337	)	(73	)	264
Net borrowings	18,376		23,055		4,679
Shareholders' equity including minority interest	48,510		50,051		1,541
Leverage	0.38		0.46		0.08

Net borrowings at December 31, 2009 amounted to euro 23,055 million and increased by euro 4,679 million from December 2008.
Total debt amounted to euro 24,800 million, of which euro 6,736 million were short-term (including the portion of long-term debt due within 12 months for euro 3,191 million) and euro 18,064 million were long-term.
The ratio of net borrowings to shareholders’ equity including minority interest – leverage – increased to 0.46 with respect to 0.38 recorded at the end of 2008.

Comprehensive income

2007 (euro million) 2008 2009

10,809		Net profit (loss)	9,558		5,317
		Other items of comprehensive income:
(1,980	)	- foreign currency translation differences	1,077		(869	)
(2,237	)	- change in fair value of cash flow hedge derivates	1,969		(481	)
(6	)	- change in fair value of available-for-sale securities	3		1
		- share of "Other comprehensive income" on equity-accounted entities			2
869		- taxation	(767	)	202
(3,354	)	Other comprehensive income	2,282		(1,145	)
7,455		Total comprehensive income	11,840		4,172
		Attributable to:
6,708		- Eni	11,148		3,245
747		- minority interest	692		927

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Changes in shareholders’ equity

(euro million)

Shareholders' equity at December 31, 2008			48,510
Total comprehensive income	4,172
Dividends paid to Eni shareholders	(4,166	)
Dividends paid by consolidated subsidiaries to minorities	(350	)
Acquisition of Distrigas minorities	(1,146	)
Cancellation of Publigaz put option	1,495
Share capital increase subscribed by Snam Rete Gas minorities	1,542
Rights cancelled stock option - 2006 plan	(7	)
Current cost of assigned options	13
Other contributions from payments of shareholders	18
Other changes	(30	)
Total changes			1,541
Shareholders' equity at December 31, 2009			50,051
Attributable to:
- Eni			46,073
- Minority Interest			3,978

The Group’s total equity including minorities increased by euro 1,541 million to euro 50,051 million, reflecting (i) comprehensive income for the period (euro 4,172 million) as a result of net profit for the period (euro 5,317 million), losses on fair value evaluation of certain cash flow hedges placed in reserve and foreign currency translation effects; (ii) closing of the mandatory public takeover bid on the minorities of Distrigas which determined an increase in shareholders’ equity due to derecognition of the put option awarded to Publigaz SCRL in 2008 (euro 1,495 million); (iii) Snam Rete Gas share capital increase subscribed by minorities for euro 1,542 million. These increases were partly offset by: (i) dividend payments to Eni shareholders (euro 4,166 million) as well as minority shareholders of certain consolidated subsidiaries (euro 350 million); (ii) elimination of the book value, including their respective share of profit for the period, of the Distrigas minorities who tendered their shares to the public offer (euro 1,146 million).

Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity

Net profit Shareholders’ equity

(euro million) 2008 2009 Dec. 31, 2008 Dec. 31, 2009

As recorded in Eni SpA's financial statements	6,745		5,061		30,049		32,144
Difference between the equity value of individual accounts of consolidated subsidiaries with respect to the corresponding book value in the statutory accounts of the parent company	4,140		158		18,999		17,464
Consolidation adjustments:
- difference between purchase cost and underlying book value of net equity	(330	)	(213	)	5,161		5,068
- elimination of tax adjustments and compliance with group account policies	(1,373	)	(113	)	(2,852	)	(1,062	)
- elimination of unrealized intercompany profits	216		117		(3,127	)	(4,582	)
- deferred taxation	159		378		(15	)	1,175
- other adjustments	1		(71	)	295		(156	)
	9,558		5,317		48,510		50,051
Minority interest	(733	)	(950	)	(4,074	)	(3,978	)
As recorded in the Consolidated Financial Statements	8,825		4,367		44,436		46,073

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Summarized Group cash flow statement and change in net borrowings

Eni’s summarized Group cash flow statement derives from the statutory statement of cash flows. It enables investors to understand the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred in the 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; (ii) changes 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 ^(a)

2007 (euro million) 2008 2009 Change

10,809		Net profit	9,558		5,317		(4,241	)
		Adjustments to reconcile to cash generated from operating profit before changes in working capital:
6,346		- amortization and depreciation and other non monetary items	11,388		9,847		(1,541	)
(309	)	- net gains on disposal of assets	(219	)	(226	)	(7	)
8,850		- dividends, interest, taxes and other changes	9,080		6,687		(2,393	)
25,696		Net cash generated from operating profit before changes in working capital	29,807		21,625		(8,182	)
(1,667	)	Changes in working capital related to operations	2,212		(1,769	)	(3,981	)
(8,512	)	Dividends received, taxes paid, interest (paid) received during the period	(10,218	)	(8,720	)	1,498
15,517		Net cash provided by operating activities	21,801		11,136		(10,665	)
(10,593	)	Capital expenditures	(14,562	)	(13,695	)	867
(9,665	)	Investments and purchase of consolidated subsidiaries and businesses	(4,019	)	(2,323	)	1,696
659		Disposals	979		3,595		2,616
(35	)	Other cash flow related to capital expenditures, investments and disposals	(267	)	(295	)	(28	)
(4,117	)	Free cash flow	3,932		(1,582	)	(5,514	)
(479	)	Borrowings (repayment) of debt related to financing activities	911		396		(515	)
8,761		Changes in short and long-term financial debt	980		3,841		2,861
(5,836	)	Dividends paid and changes in minority interests and reserves	(6,005	)	(2,956	)	3,049
(200	)	Effect of changes in consolidation and exchange differences	7		(30	)	(37	)
(1,871	)	NET CASH FLOW FOR THE PERIOD	(175	)	(331	)	(156	)

Changes in net borrowings

2007 (euro million) 2008 2009 Change

(4,117	)	Free cash flow	3,932		(1,582	)	(5,514	)
(244	)	Net borrowings of acquired companies	(286	)			286
		Net borrowings of divested companies	181				(181	)
637		Exchange differences on net borrowings and other changes	129		(141	)	(270	)
(5,836	)	Dividends paid and changes in minority interests and reserves	(6,005	)	(2,956	)	3,049
(9,560	)	CHANGE IN NET BORROWINGS	(2,049	)	(4,679	)	(2,630	)

(a) For a reconciliation to the statutory statement of cash flows see the paragraph "Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to statutory schemes".

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Main cash inflows for the year were: (i) net cash provided by operating activities (euro 11,136 million); (ii) cash proceeds of euro 3,070 million associated with the divestment of a 20% interest in Gazprom Neft following the exercise of a call option agreement by Gazprom, plus the first tranche of the proceeds from the sale of a 51% interest in OOO SeverEnergia (Eni’s share 60%) for euro 155 million (including repayment of financing); (iii) the subscription by Snam Rete Gas minorities of a share capital increase amounting to euro 1,542 million; (iv) further cash proceeds of euro 370 million mainly associated with the divestment of certain non strategic assets in the Exploration & Production division, following agreements signed with Suez in 2008. These inflows were used to partially fund capital expenditures of euro 13,695 million, completion of a mandatory takeover bid on the Distrigas minorities, including the squeeze-out procedure for a total cash consideration of euro 2,045 million, payment of dividends to Eni shareholders (euro 4,166 million of which euro 1,811 million as interim dividend for the year 2009) as well as dividend payments to minorities (euro 350 million) in particular relating to Snam Rete Gas and Saipem (euro 335 million). Net borrowings increased by euro 4,679 million from a year ago to euro 23,055 million.

Capital expenditures

2007 (euro million) 2008 2009 Change % Ch.

6,480		Exploration & Production	9,281		9,486	205		2.2
1,511		Gas & Power	2,058		1,686	(372	)	(18.1	)
979		Refining & Marketing	965		635	(330	)	(34.2	)
145		Petrochemicals	212		145	(67	)	(31.6	)
1,410		Engineering & Construction	2,027		1,630	(397	)	(19.6	)
59		Other activities	52		44	(8	)	(15.4	)
108		Corporate and financial companies	95		57	(38	)	(40.0	)
(99	)	Impact of unrealized profit in inventory	(128	)	12	140
10,593		Capital expenditures	14,562		13,695	(867	)	(6.0	)

In 2009, capital expenditures amounted to euro 13,695 million (euro 14,562 million in 2008), of which 86% related to the Exploration & Production, Gas & Power and Refining & Marketing divisions. Main expenditures were the following ones:
- oil & gas development activities were euro 7,478 million and were deployed mainly in Kazakhstan, the United States, Egypt, Congo, Italy and Angola;
- exploration projects were euro 1,228 million of which 97% were carried out outside Italy, primarily in the United States, Libya, Egypt, Norway and Angola;
- acquisition of proved and unproved properties amounting to euro 697 million mainly related to the acquisition of a 27.5% interest in assets with gas shale reserves from Quicksilver Resources Inc and extension of the duration of oil and gas properties in Egypt following the agreement signed in May 2009;
- development and upgrading of Eni’s natural gas transport network in Italy amounted to euro 919 million. Distribution network upgrades were euro 278 million, and further euro 282 million were invested to develop and increase storage capacity;
- projects aimed at improving the conversion capacity and flexibility of refineries amounted to euro 436 million. Building and upgrading service stations in Italy and outside Italy absorbed euro 172 million;
- upgrading of the fleet used in the Engineering & Construction division amounted to euro 1,630 million. Investments and purchases of consolidated subsidiaries and businesses (euro 2,323 million) mainly related to the completion of the acquisition of Distrigas NV. Disposals amounted to euro 3,595 million and mainly related to the divestment of a 20% interest in Gazprom Neft following exercise on April 7, 2009 of the call option by Gazprom (euro 3,070 million). The exercise price of the call option is equal to the bid price ($3.7 billion) as adjusted by subtracting dividends distributed and adding the contractual annual remuneration of 9.4% on capital employed and certain financial collateral expenses. In addition a 51% stake in the joint venture OOO SeverEnergia (Eni 60%) was divested to Gazprom. Eni’s share of the transaction is worth $940 million of which $230 million were collected as of year end, which corresponded to euro 155 million at the exchange rate of the transaction date. The remaining $710 million were collected on March 31, 2010 (euro 526 million at exchange rate of 1.35).

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Other disposals related to non strategic oil & gas properties following agreements signed with Suez. Dividends paid and changes in minority interests and reserves amounting to euro 2,956 million mainly related to: (i) cash dividends to Eni shareholders (euro 4,166 million, of which euro 2,355 million pertained to the payment of the balance of the dividend for fiscal year 2008 and euro 1,811 million pertained to the payment of an interim dividend for fiscal year 2009); (ii) dividend payment for fiscal year 2008 from certain consolidated subsidiaries to minorities (euro 350 million) mainly relating to Snam Rete Gas and Saipem (euro 335 million). These outflows were partly offset by the subscription by Snam Rete Gas minorities of a share capital increase amounting to euro 1,542 million as part of Eni’s reorganization of its regulated businesses in Italy.

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Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes

Summarized Group Balance Sheet

(euro million) December 31, 2008 December 31, 2009

Items of Summarized Group Balance Sheet
(where not expressly indicated, the item derives directly from the statutory scheme) Notes to the consolidated
financial statements Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme

Fixed assets
Property, plant and equipment				59,255				63,177
Inventories - compulsory stock				1,196				1,736
Intangible assets				7,697				8,057
Equity-accounted investments and other investments				5,881				6,244
Receivables and securities held for operating activities	(see Note 3 and 12)			1,219				1,261
Net payables related to capital expenditures, made up of:				(787	)			(749	)
- receivables related to capital expenditures/disposals	(see Note 3)	149				82
- receivables related to capital expenditures/disposals	(see Note 14)	780				710
- payables related to capital expenditures	(see Note 16)	(1,716	)			(1,541	)
Total fixed assets				74,461				79,726
Net working capital
Inventories				6,082				5,495
Trade receivables	(see Note 3)			16,444				14,916
Trade payables	(see Note 16)			(12,590	)			(10,078	)
Tax payables and provisions for net deferred tax liabilities, made up of:				(5,323	)			(1,988	)
- income tax payables		(1,949	)			(1,291	)
- other tax payables		(1,660	)			(1,431	)
- deferred tax liabilities		(5,784	)			(4,907	)
- other tax liabilities	(see Note 24)	(254	)			(52	)
- current tax assets		170				753
- other current tax assets		1,130				1,270
- deferred tax assets		2,912				3,558
- other tax assets	(see Note 14)	112				112
Provisions				(9,506	)			(10,319	)
Other current assets and liabilities:
Other, made up of:				(4,544	)			(3,968	)
- securities held for operating purposes	(see Note 2)	310				284
- receivables for operating purposes	(see Note 3)	402				339
- other receivables	(see Note 3)	4,805				4,825
- other (current) assets		1,870				1,307
- other receivables and other assets	(see Note 14)	989				1,116
- advances, other payables	(see Note 16)	(6,209	)			(7,555	)
- other (current) liabilities		(3,863	)			(1,856	)
- other payables and other liabilities	(see Note 24)	(2,848	)			(2,428	)
Total net working capital				(9,437	)			(5,942	)
Current investments	(see Note 2)			2,741
Provisions for employee post-retirement benefits				(947	)			(944	)
Net assets held for sale including related net borrowings, made up of:				68				266
- assets held for sale		68				542
- liabilities directly associated to assets held for sale						(276	)
CAPITAL EMPLOYED, NET				66,886				73,106

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continued Summarized Group Balance Sheet

(euro million) December 31, 2008 December 31, 2009

Items of Summarized Group Balance Sheet
(where not expressly indicated, the item derives directly from the statutory scheme) Notes to the Consolidated
Financial Statements Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme

CAPITAL EMPLOYED, NET			66,886			73,106
Shareholders' equity including minority interest			48,510			50,051
Net borrowings
Total debt, made up of:			20,837			24,800
- long-term debt		13,929			18,064
- current portion of long-term debt		549			3,191
- short-term financial liabilities		6,359			3,545
less:
Cash and cash equivalents			(1,939	)		(1,608	)
Securities held for non-operating purposes	(see Note 2)		(185	)		(64	)
Financing receivables for non-operating purposes	(see Note 3)		(337	)		(73	)
Total net borrowings (a)			18,376			23,055
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			66,886			73,106

(a) For details on net borrowings see also Note 20 to the consolidated financial statements.

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Summarized Group Cash Flow Statement

(euro million) December 31, 2008 December 31, 2009

Items of Summarized Group Cash Flow Statement
and confluence/reclassification of items in the statutory scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme

Net profit			9,558				5,317
Adjustments to reconcile to cash generated from operating profit before changes in working capital:
Depreciation, depletion and amortization and other non monetary items:			11,388				9,847
- depreciation, depletion and amortization	8,422				8,762
- net impairments (write-ups)	2,560				495
- net changes in provisions	414				574
- net changes in the provisions for employee benefits	(8	)			16
Net gains on disposal of assets			(219	)			(226	)
Dividends, interest, income taxes and other changes:			9,080				6,687
- dividend income	(510	)			(164	)
- interest income	(592	)			(352	)
- interest expense	809				603
- exchange differences	(319	)			(156	)
- income taxes	9,692				6,756
Cash generated from operating profit before changes in working capital			29,807				21,625
Changes in working capital related to operations:			2,212				(1,769	)
- inventories	(801	)			52
- trade and other receivables	(974	)			(19	)
- other assets	162				(472	)
- trade and other payables	2,318				(1,201	)
- other liabilities	1,507				(129	)
Dividends received, taxes paid, interest (paid) received during the period:			(10,218	)			(8,720	)
- dividend received	1,150				576
- interest received	266				594
- interest paid	(852	)			(583	)
- income taxes paid	(10,782	)			(9,307	)
Net cash provided by operating activities			21,801				11,136
Capital expenditures:			(14,562	)			(13,695	)
- tangible assets	(12,312	)			(12,300	)
- intangible assets	(2,250	)			(1,395	)
Acquisition of investments and businesses:			(4,019	)			(2,323	)
- investments	(385	)			(230	)
- consolidated subsidiaries and businesses	(3,634	)			(25	)
- acquisition of additional interests in subsidiaries					(2,068	)
Disposals:			979				3,595
- tangible assets	318				126
- intangible assets	2				250
- consolidated subsidiaries and businesses	149
- investments	510				3,219
- sale of interests in subsidiaries
Other cash flow related to capital expenditures, investments and disposals:			(267	)			(295	)
- securities	(152	)			(2	)
- financing receivables	(710	)			(972	)
- change in payables and receivables relating to investments and capitalized depreciation	367				(97	)
reclassification: purchase of securities and financing receivables for non-operating purposes	173				38
- disposal of securities	145				164
- disposal of financing receivables	1,293				861
- change in payables and receivables	(299	)			147
reclassification: disposal of securities and financing receivables held for non-operating purposes	(1,084	)			(434	)
Free cash flow			3,932				(1,582	)

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continued Summarized Group Cash Flow Statement

(euro million) December 31, 2008 December 31, 2009

Items of Summarized Group Cash Flow Statement
and confluence/reclassification of items in the statutory scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme Partial amounts
from statutory
scheme Amounts
of the summarized Group scheme

Free cash flow			3,932				(1,582	)
Borrowings (repayment) of debt related to financing activities			911				396
reclassification: purchase of securities and financing receivables held for non-operating purposes	(173	)			(38	)
reclassification: sale of securities and financing receivables held for non-operating purposes	1,084				434
Changes in short and long-term finance debt:			980				3,841
- proceeds from long-term finance debt	3,774				8,774
- payments of long-term finance debt	(2,104	)			(2,044	)
- increase (decreases) in short-term finance debt	(690	)			(2,889	)
Dividends paid and changes in minority interests and reserves:			(6,005	)			(2,956	)
- net capital contributions/payments by/to minority shareholders	20				1,551
- dividends paid by Eni to shareholders	(4,910	)			(4,166	)
- dividends paid to minority interest	(297	)			(350	)
- net repurchase of treasury shares	(768	)
- treasury shares repurchased by consolidated subsidiaries	(50	)			9
Effect of changes in consolidation area and exchange differences:			7				(30	)
- effect of change in consolidation area	(1	)
- effect of exchange differences and other changes	8				(30	)
CHANGE IN CASH AND CASH EQUIVALENTS			(175	)			(331	)

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RISK FACTORS, UNCERTAINTIES AND TREND INFORMATION

Foreword The main risks that the Company is facing and actively monitoring and managing are the following: (i) the market risk deriving from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) the credit risk deriving from the possible default of a counterparty; (iii) the liquidity risk deriving from the risk that suitable sources of funding for the Group’s operations may not be available; (iv) the country risk in the upstream business; (v) the operational risk; (vi) the possible evolution of the Italian gas market; (vii) the specific risks deriving from exploration and production activities.
Financial risks are managed in respect of guidelines defined by the parent company, targeting to align and coordinate Group companies policies on financial risks. Market risk Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of conducting finance, treasury and risk management operations based on separate entities: the parent company’s (Eni SpA) finance department, Eni Coordination Center and Banque Eni which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk and Eni Trading & Shipping that has the mandate to manage and monitor solely commodity derivative contracts. In particular Eni SpA and Eni Coordination Center manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative financial contracts are managed by the parent company as well as the activity of trading certificates according to the European Union Emission Trading Scheme. The commodity risk is managed by each business unit with Eni Trading & Shipping ensuring the negotiation of hedging derivatives. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to changes in exchange rates and interest rates and to manage exposure to commodity prices fluctuations. Eni does not enter into derivative transactions on a speculative basis. The framework defined by Eni’s policies and guidelines prescribes that measurement and control of market risk be performed on the basis of maximum tolerable levels of risk exposure defined in accordance with value-at-risk techniques. These techniques make a statistical assessment of the market risk on the Group’s activity, i.e., potential gain or loss in fair values, due to changes in market conditions taking account of the correlation existing among changes in fair value of existing instruments. Eni’s finance departments define maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates, pooling Group companies risk positions. Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with established banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the company. Eni’s guidelines prescribe that Eni’s Group companies minimize such kinds of market risks. With regard to the commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at the optimization of core activities and the pursuing of preset targets of industrial margins. The

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maximum tolerable level of risk exposure is pre-defined in terms of value-at-risk in connection with trading and commercial activities, while the strategic risk exposure to commodity prices fluctuations – i.e. the impact on the Group’s business results deriving from changes in commodity prices – is monitored in terms of value-at-risk, albeit not hedged in a systematic way. Accordingly, Eni evaluates the opportunity to mitigate its commodity risk exposure by entering into hedging transactions in view of certain acquisition deals of oil and gas reserves as part of the Group’s strategy to achieve its growth targets or ordinary asset portfolio management. The Group controls commodity risk with a maximum value-at-risk limit awarded to each business unit. Hedging needs from business units are pooled by Eni Trading & Shipping which also manages its own risk exposure. The three different market risks, whose management and control have been summarized above, are described below. Exchange rate risk
Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly in the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro (translation risk). Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice-versa. Eni’s foreign exchange risk management policy is to minimize economic and transactional exposures arising from foreign currency movements. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance departments which match opposite positions within Group companies, hedging the Group net exposure through the use of certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value on the basis of market prices provided by specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. The VAR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period. Interest rate risk
Changes in interest rates affect the market value of financial assets and liabilities of the company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. Borrowing requirements of the Group’s companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be accounted for under the hedge accounting method in accordance with IAS 39. Value at risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, with a 99% confidence level and a 20-day holding period. Commodity risk
Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil and gas prices generally has a negative impact on Eni’s results of operations and vice-versa. Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable margins. In order to accomplish this, Eni uses derivatives traded on the organized markets of ICE and NYMEX (futures) and derivatives traded over the counter (swaps, forward, contracts for differences and options) with the underlying commodities being crude oil, refined products or electricity. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable evaluation techniques. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. Value at risk deriving from

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commodity exposure is measured daily on the basis of a historical simulation technique, with a 95% confidence level and a one-day holding period. The following table shows amounts in terms of value at risk, recorded in 2009 (compared with 2008) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. Var values are stated in U.S. dollars, the currency used in oil products markets.

(Exchange and interest rate: Value at Risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

2008 2009

(euro million) High Low Avg At period end High Low Avg At period end

Interest rate	12.31	0.73	4.17	6.54	6.85	1.65	3.35	1.98
Exchange rate	1.48	0.09	0.48	0.47	1.22	0.07	0.35	0.31

(Commodity risk: Value at Risk - historic simulation method; holding period: 1 day; confidence level: 95%)

2008 2009

($ million) High Low Avg At period end High Low Avg At period end

Area oil, products	46.48	3.44	19.88	5.43	37.51	4.74	17.65	6.64
Area Gas & Power (*)	67.04	24.38	43.53	32.07	51.62	28.01	40.97	38.26

(*) In 2008, amounts relating to the Gas & Power business also include Distrigas' contribution, since the acquisition date.

Credit risk

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 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. The monitoring activity of credit risk exposure is performed at the Group level according to set guidelines and measurement techniques that establish counterparty limits and systems to monitor exposure against limits and report regularly on those exposures. Specifically, credit risk exposure to multi-business clients and exposures higher than the limit set at euro 4 million are closely monitored. Monitoring activities do not include retail clients and public administrations. The assessment methodology assigns a score to individual clients based on publicly available financial data and capital, profitability and liquidity ratios. Based on those scores, an internal credit rating is assigned to each counterparty who is accordingly allocated to its proper risk category. The Group risk categories are comparable to those prepared by the main rating agencies on the marketplace. The Group’s internal ratings are also benchmarked against ratings prepared by a specialized external source.
With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into 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 Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions. Those are the sole Group entities entitled to be party to financial transactions due to 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. Eni has not experienced material non-performance by any counterparty. As of December 31, 2009, Eni had no significant concentrations of credit risk.

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Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the market place as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks. The actions implemented as part of Eni’s financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. In particular in 2009, Eni issued bonds addressed to institutional investor and to the retail market for euro 3 billion and euro 2 billion, respectively. The above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short-term commitments and due obligations also preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit particularly the committed ones. 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.
As of December 31, 2009, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 11,774 million, of which euro 2,241 million were committed, and long-term committed unused borrowing facilities of euro 2,850 million. These facilities were under interest rates that reflected market conditions. Fees charged for unused facilities were not significant.
Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which euro 9,211 million were drawn as of December 31, 2009.
The Group has debt ratings of AA- and A-1+ respectively for long (outlook negative) and short-term debt assigned by Standard & Poor’s and Aa2 and P-1 (outlook negative) assigned by Moody’s.
The tables below summarize the Group main contractual obligations for finance debt repayments, including expected payments for interest charges, and trade and other payables maturities.

Current and non current finance debt

Maturity year

(euro million) 2010 2011 2012 2013 2014 2015 and thereafter Total

Non current debt	3,191	1,342	3,660	1,967	2,487	8,608	21,255
Current financial liabilities	3,545						3,545
Fair value of derivative instruments	1,371	517	133	46	14	98	2,179
	8,107	1,859	3,793	2,013	2,501	8,706	26,979
Interest on finance debt	654	570	545	510	426	1,159	3,864
Guarantees to banks	377						377

Trade and other payables

Maturity year

(euro million) 2010 2011-2014 2015 and thereafter Total

Trade payables	10,078			10,078
Advances, other payables	9,096	31	23	9,150
	19,174	31	23	19,228

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In addition to finance debt and trade payables presented in the financial statements, the Group has in place a number of contractual obligations arising in the normal course of the business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations are certain arrangements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company obligations consist of off-taking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

Expected payments by period under contractual obligations and commercial commitments

Maturity year

(euro million) 2010 2011 2012 2013 2014 2015 and thereafter Total

Operating lease obligations (1)	886	889	561	470	415	1,034	4,255
Decommissioning liabilities (2)	79	55	112	161	1,640	9,280	11,327
Environmental liabilities	293	259	257	214	193	687	1,903
Purchase obligations (3)	14,845	14,151	13,923	14,634	14,651	175,888	248,092
Gas
- Natural gas to be purchased in connection with take-or-pay contracts	13,986	13,365	13,123	13,827	13,838	169,268	237,407
- Natural gas to be transported in connection with ship-or-pay contracts	546	538	545	559	567	3,658	6,413
Other take-or-pay and ship-or-pay obligations	162	154	139	133	131	1,068	1,787
Other purchase obligations (4)	151	94	116	115	115	1,894	2,485
Other obligations	21	4	3	3	3	152	186
of which:
- Memorandum of intent relating Val d’Agri	21	4	3	3	3	152	186
	16,124	15,358	14,856	15,482	16,902	187,041	265,763

(1)	Operating leases primarily regarded assets for drilling activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2)	Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)	Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(4)	Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.

In the 2010-2013 four-year period management plans to invest euro 52.8 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at December 31, 2009. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown.

Capital expenditure commitments

Maturity year

(euro million) 2010 2011 2012 2013 2014 and subsequent years Total

Committed on major projects	4,119	3,793	2,829	1,928	11,357	24,026
Other committed projects	9,330	5,284	3,467	3,640	7,489	29,210
	13,449	9,077	6,296	5,568	18,846	53,236

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Country risk Substantial portions of Eni’s hydrocarbons reserves are located in countries outside the EU and North America, certain of which may be politically or economically less stable than EU or North American. At December 31, 2009, approximately 80% of Eni’s proved hydrocarbons reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2009, approximately 60% of Eni’s domestic supply of natural gas came from such countries. Developments in the political framework, economic crisis, social unrest can compromise temporarily or permanently Eni’s ability to operate or to economically operate in such countries, and to have access to oil and gas reserves. Further risks associated with activities in those countries are represented by: (i) lack of well established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws and regulations leading to expropriation of Eni’s titles and mineral assets, changes in unilateral contractual clauses reducing the value of Eni’s assets; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases; (v) civil and social unrest leading to sabotages, acts of violence and incidents. While the occurrence of these events is unpredictable, it is possible that they can have a material adverse impact on Eni’s financial condition and results of operations. Eni periodically monitors political, social and economic risks of approximately 60 countries where it has invested, or, with regard to upstream projects evaluation, where Eni is planning to invest in order to assess returns of single projects based also on the evaluation of each country’s risk profile. Country risk is mitigated in accordance with guidelines on risk management defined in the procedure "Project risk assessment and management". In the most recent years, unfavorable developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America.
Operational risk Eni’s business activities conducted in and outside Italy are subject to a broad range of laws and regulations, including specific rules concerning oil and gas activities currently in force in countries in which it operates. In particular, those laws and regulations require the acquisition of a license before exploratory drilling may commence and compliance with health, safety and environment standards. Environmental laws impose restrictions on the types, quantities and concentration of various substances that can be released into the environment and on discharges to surface and subsurface water. In particular Eni is required to follow strict operating practices and standards to protect biodiversity when exploring for, drilling and producing oil and gas in certain ecologically sensitive locations (protected areas). Breach of environmental, health and safety laws exposes employees to criminal and civil liability and in the case of violation of certain rules regarding safety on the workplace also companies can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with Law Decree No. 231/2001.
Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations and expenses and liabilities that Eni may incur in relation to compliance with environmental, health and safety laws and regulations are expected to remain material to the Group’s results of operations or financial position in future years. Recently enacted regulations on safety and health in the workplace in Italy impose a new array of obligations to the Company operations, particularly regarding contractors. New regulations prescribe that a company adopts certified operational and organizational systems whereby the Company can discharge possible liabilities due to a violation of health and security standards on condition that adopted operational systems and processes worked properly and were effective.
Eni has adopted guidelines for assessing and managing health, safety and environmental (HSE) risks, with the objective of protecting Eni’s employees, the populations involved in its activity, contractors and clients, and the environment and being in compliance with local and international rules and regulations. Eni’s guidelines prescribe the adoption of international best practices in setting internal principles, standards and solutions. The ongoing process for identifying, evaluating and managing HSE operations in each phase of the business activity is performed through the adoption of procedures and effective pollution management systems tailored to the peculiarities of each business and industrial site and on steady enhancement of plants and process. Additionally, coding activities and procedures on operating phases allow to reduce the human component in the plant risk management. Operating emergencies that may have an adverse impact on assets, people and the environment are managed by the business units for each site. These units manage the HSE risk

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in a systematic way that involves having emergency response plans in place with a number of corrective actions to be taken that minimize damage in the event of an incident. In the case of a major crisis, Divisions/Entities are assisted by the Eni Unit of Crisis to deal with the emergency through a team which has the necessary training and skills to coordinate in a timely and efficient manner resources and facilities. The integrated management system of health, safety and environmental matters is supported by the adoption of Eni’s Model of HSE operations in all the Division and companies of the Eni Group. This is a procedure based on an annual cycle of planning, implementation, control, review of results and definition of new objectives. The model is directed towards the prevention of risks, the systematic monitoring and control of HSE performance, in a continuous improvement cycle (Deming cycle).
Eni is reaching the goal of total certification of its plants. Industrial and commercial sites of the R&M segment have been certified as ISO 14001, and six of them are EMAS certified; in the petrochemical segment facilities are certified under ISO 14001, EMAS and OHSAS 18001. EniPower power stations are EMAS certified, while in other segments facilities are mainly certified under ISO 14001 and OHSAS 18001.
The system for monitoring HSE operational risks is based on the monitoring of HSE indicators at quarterly intervals and on an audit plan addressed to three levels: HSE Corporate, HSE business unit and at site level consisting of:
- internal audits of management systems (performed by Eni employees or external consultants);
- audits for the confirmation or renewal of certification of management systems performed annually by external certifying entities;
- control of compliance with existing HSE regulations;
- specific audits on relevant issues (e.g. following events/accidents/reported failures).
Eni provides a program of specific training and development to its HSE staff in order to:
- promote the execution of behaviors consistent with guidelines;
- drive people’s learning growth process by developing professionalism, management and corporate culture;
- support management knowledge and control of HSE risks.
Possible evolution of the Italian gas market Detailed information is furnished in the paragraph "Risk factors" - Operating Review of the Gas & Power division. Specific risks associated with exploration and production of oil and natural gas Exploration and production of oil and natural gas requires high levels of capital expenditure and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or natural gas fields. Exploratory activity involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. Developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning relating facilities. As a consequence, rates of return of such long- lead-time projects are exposed to the volatility of oil and gas prices and the risk of an increase in developing and lifting costs, resulting in lower rates of return. This set of circumstances is particularly important to those projects intended to develop reserves located in deep water and harsh environments, where the majority of Eni’s planned and ongoing projects is located. Risks associated with the cyclicality of the oil and gas sector The global economic downturn and the associated reduction in industrial output recorded in 2008 and for most of 2009 triggered a sharp decline in worldwide demand for energy, resulting in significantly lower commodity prices.
In spite of weak fundamentals (level of global demand and level of inventories), international oil prices have shown a steady upward trend since the second half of 2009 driven by expectations for a global economic recovery and OPEC production cuts, settling by year end in a range of 70-80 $/bbl.
Volatile oil prices pose a critical issue to the sustainability of capital plans of oil and gas companies, considering that they are engaged in long-lead-time projects. Such projects normally require lengthy and complex activities for assessing all technical and commercial aspects and developing and marketing hydrocarbons. As a consequence, return rates of projects are exposed to the volatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was made, resulting in lower rates of return. The Company, likewise other players in the industry, assesses its

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oil & gas projects based on long-term scenarios for oil prices, which reflect management’s best assumptions about the underlying fundamentals of global demand and offer. The adoption of long-term prices in assessing capital projects support the achievement of the planned rates of return.
Eni plans to invest euro 52.8 billion in the 2010-2013 four-year period, at the Company’s long-term price for Brent crude of $65/barrel (in real terms 2013). Of these, euro 37.7 billion, or 71%, will be dedicated to execute projects for exploring and developing oil and gas reserves. The plan shows an increase of 8% from the previous plan that was approved when the trading environment was particularly depressed. The main drivers which explain the increase are: (i) planned expenditures for developing new upstream projects, particularly those associated with reserves development in Iraq, Venezuela and certain fields offshore Angola; (ii) the circumstance that the Company is forecasting steady trends in costs for materials and sector specific services which have fallen far less than what management has anticipated due to the fast recovery in international oil prices, and the impact of the decision on part of most oil companies to maintain their spending patterns substantially unchanged. In the previous plan, management assumed a decline in those costs. These increasing trends will be partially offset by the impact of the US dollar depreciation versus the euro.
Volatile oil prices also influence the reserve replacement ratio. Changes in oil prices normally trigger two opposite impacts in proved reserves revisions. On one side, a larger or smaller amount of reserves is booked in connection with production sharing agreements and similar contractual schemes. Under such contracts, the Company is entitled to receive a portion of the production, the sale of which should cover expenditures incurred and earn the Company a share of profit. Accordingly, the higher the reference prices for crude oil used to determine production and reserves entitlements, the lower the number of barrels to cover the same dollar amounts hence the amounts of booked reserves; and vice versa. On the other side, downward revisions of reserves occur for those marginal amounts of reserves that are no longer economically producible based on oil prices that are significantly lower than those at which they were originally assessed and sanctioned; and the opposite occurs in case of higher oil prices. In the Gas & Power division, Eni’s outlook for the year 2010 factors in a modest improvement in Italian and European gas demand, recovering from the sharp decline suffered in 2009. Eni also expects that the gas market will be well supplied as new import capacity to Europe and Italy is available in light of recent facility start-ups and upgrades of the main import pipelines made by Eni and other operators. Those trends, together with the recently enacted gas release programs in Italy, represent risk factors to the Company’s ability to maintain its margins in the marketing business also taking into account the take or pay clauses of certain long-term supply contracts which require the Company to collect minimum predetermined volumes of gas or, in case of failure, to pay the price, or a portion of it, for uncollected volumes. Under take-or- pay clauses the Company is entitled to collect pre-paid volumes of gas in future years, assuming a stronger recovery in gas demand.
For more information see the specific risk paragraph in the "Operating Review" of the Gas & Power section in this annual report.
The Refining & Marketing and the Petrochemical divisions are particularly exposed to the volatility of the economic cycle, as their respective industries continue to be plagued by excess capacity, intense competitive pressure, low entry barriers and commoditized products. These industries are also exposed to movements in oil prices and the speed at which the prices of refined products and petrochemicals products adjust to reflect change in the cost of oil-based feedstock. Normally, a time lag occurs between movements in oil prices and those of refined and petrochemical products. As a consequence, in a period of rapidly escalating feedstock costs, margins on refined and petrochemical products are negatively affected.
For 2010, Eni’s management does not expect any appreciable recovery in the main trends that negatively affected the performances of these businesses last year. In 2009 Eni’s realized refining margins were sharply lower mirroring the environment for Brent margins (down 50%), while margins on a mix of light and heavy crude were further lower, down by 60%, both under break-even. A number of negative factors contribute to the reduction. Firstly, significantly compressed light-heavy crude differentials due to a reduction in heavy crude availability on the market place negatively affected the profitability of Eni’s complex refineries. Secondly, the industry continued to be plagued by weak fundamentals due to excess capacity, high inventory levels and stagnant demand affecting end-prices, while feedstock costs have been on an upward trend since the beginning of the second half. Finally, middle-distillates prices plunged to historical lows in terms of spread versus the cost of oil. At the moment,

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management does not expect a reversal in those trends on the short-term.
In its Petrochemical division, management has been pursuing a number of initiatives designed to reduce fixed operating expenses and to realign the industrial set-up of Eni’s petrochemical operations with a view of enhancing areas of competitive advantage. In spite of all this, the achievement of the operating break-even in this segment depends on a global recovery in the economy that is uncertain at least in the short-term.
The Engineering & Construction segment followed a different trend, maintaining a steady order backlog and economic returns, thanks to a business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. The start of operations of new distinctive assets in 2010 and 2011 coupled with the size and quality of the backlog and the strong operating performance on projects, underpin expectations for a further significant strengthening of Saipem’s competitive position in the medium-term.

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OUTLOOK

In what remains an uncertain energy environment, Eni forecasts a modest improvement in global oil demand and a Brent price of 65 $/bbl in 2010. Gas demand in Europe and Italy is expected to recover gradually from the steep decline suffered in 2009, which mainly impacted the industrial and power generation sectors at a time when new import capacity was coming on line. The Company faces a challenging refining environment, excluding any significant recovery in industry fundamentals that will entail prolonged weakness in refinery margins.
- Production of liquids and natural gas is forecast to achieve a level not lower than in 2009, when production came in at 1.769 million boe/d, based on the Company’s scenario for a Brent price of 65 $/bbl for the full year, OPEC restrictions at the same level as 2009 and asset disposals underway. Growth will be driven by continuing field start-ups, mainly in Congo, Norway and marginally the Zubair project in Iraq, and production ramp-up at the Company’s recently started fields, mainly in Nigeria, Angola and the USA. These additions will be offset by mature field declines. Production growth will resume at a strong rate in the coming years.
- Natural gas sales are expected to remain flat compared to 2009 (approximately 104 bcm were achieved in 2009). Increasing competitive pressures, mainly in Italy, will be offset by an expected recovery in European gas demand. Other positive trends include a benefit associated with integrating Distrigas operations and the optimization of supply portfolio, including re-negotiation of long-term supply contracts. - Regulated businesses in Italy will benefit from the pre-set, regulatory return on new capital expenditures and cost savings from integrating the whole chain of transport, storage and distribution activities.
- Refining throughputs on Eni’s account are planned to be in line with 2009 (actual throughputs in 2009 were 34.55 mmtonnes). Volumes processed at wholly-owned refineries are expected to increase, resulting in a higher capacity utilization rate, due to a reduction in volumes on third party refineries reflecting the Company’s decision to terminate certain processing agreements. Efficiency improvement actions will partly offset the unfavorable trading environment.
- Retail sales of refined products in Italy and the rest of Europe are expected to be unchanged from 2009 (12.02 mmtonnes in 2009) reflecting weak demand. New marketing initiatives are planned in order to strengthen Eni’s leadership on the Italian retail market and to develop its market share in European markets.
- The Engineering & Construction business is expected to see solid results due to a robust order backlog. In 2010, management plans to make capital expenditures broadly in line with 2009 (euro 13.69 billion were invested in 2009). Capital expenditures will mainly be directed to the development of oil and natural gas reserves, exploration projects, the upgrading of construction vessels and rigs, and the upgrading of natural gas transport infrastructure. Management has planned a number of measures designed to ensure the achievement of a ratio of net borrowings to total equity (leverage) which will adequately support a strong credit rating.

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Other information

Continuing listing standards provided by Article No. 36 of Italian exchanges regulation about issuers that control subsidiaries incorporated or regulated in accordance with laws of extra-EU countries
Certain provisions have been recently enacted regulating continuing Italian listing standards of issuers controlling subsidiaries that are incorporated or regulated in accordance with laws of extra-EU countries, also having a material impact on the consolidated financial statements of the parent company.
Regarding the aforementioned provisions, the Company discloses that:
- as of December 31, 2009, the provisions of Article No. 36 of Italian exchanges regulation in accordance with Italian continuing listing standards apply to Eni’s subsidiaries Burren Energy (Bermuda) Ltd, Eni Congo SA, Eni Norge AS, Eni Petroleum Co Inc, NAOC-Nigerian Agip Oil Co Ltd, Nigerian Agip Exploration Ltd, Trans Tunisian Pipeline Co Ltd e Burren Energy (Congo) Ltd which fell within the scope of the regulation as of September 30, 2009, as well as the following subsidiary Eni Finance USA Inc;
- the Company has already adopted adequate procedure to ensure full compliance with the regulation.
Subsequent events Subsequent business developments are described in the operating review of Eni’s business segment.

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Corporate Governance and Shareholding
Structure Report

This Report is intended to provide a general and complete overview of the corporate governance system adopted by Eni.
Fulfilling the applicable legal and regulatory duties¹, in accordance with the guidelines and recommendations of Borsa Italiana SpA ("Borsa Italiana") – the company responsible for the organization and management of the Italian stock exchange – and the most representative trade associations, the Report contains information regarding ownership structures and compliance with the Corporate Governance Code promoted by Borsa Italiana, giving reasons for the choices made in the application of corporate governance principles, as well as practices actually applied.
Borsa Italiana’s Corporate Governance Code is accessible to the public at www.borsaitaliana.it².
The text of this Report is also available at the registered office, published in the "Corporate Governance" section of the Company’s website³ and forwarded to Borsa Italiana according to the procedures and by the deadlines required by applicable regulations.
The information contained in this Report relates to the financial year 2009 and has been updated, in respect of certain matters, as of March 11, 2010, the date of the Board of Directors’ meeting that approved it together with the Directors’ report, the consolidated financial statements and the draft financial statements for the financial year 2009. Eni: profile, structure and values Profile
Eni is an integrated energy company with operations in more than 77 countries and a workforce of approximately 78,400 people. It operates in industries ranging from oil and natural gas to the generation and sale of electricity, from petrochemicals and engineering to construction, all of them sectors in which it has excellent skills and strong global market positions.
All of Eni’s actions are characterized by a strong commitment to sustainable development: making the most of people’s skills, contributing to the development and well-being of the communities in which it works, respecting the environment, investing in technical innovation, pursuing energy efficiency and lowering the risks of climate change are objectives shared by the corporate bodies, management and employees.
All of Eni’s men and women have a passion for challenges, continuous improvement and excellence, and above all they believe in the fundamental role played by the individual, the environment, integrity and the values established by the Code of Ethics.
Because of this, constant attention is paid to ensuring good governance.
Integrity and transparency are the principles which Eni pursues in formulating an administration and control structure that is suited to its size, complexity and operating structure, in adopting an effective internal control system, and in communicating with shareholders and other stakeholders, particularly by reviewing and updating the information available on its website.

(1)	Article 123-bis of Legislative Decree No. 58/1998 ("Consolidated Law on Finance") and Article 89-bis of Consob Resolution No. 11971/1999 and subsequent amendments ("Consob Regulations on Issuers").
(2)	At the following address: http://www.borsaitaliana.it/borsaitaliana/ufficio-stampa/comunicati-stampa/2006/ codiceautodisciplina.en_pdf.htm
(3)	At the following address: http://www.eni.com/en_IT/governance/report-on-corporate-governance/report-on-corporate-governance.shtml

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Governance structure
The corporate governance structure of Eni follows the traditional model, which assigns corporate management to the Board of Directors, the linchpin of the organizational system, supervisory functions to the Board of Statutory Auditors and auditing of the accounts to the audit firm appointed by the Shareholders’ Meeting.
In compliance with the provisions of the By-laws, the Board appoints a Chief Executive Officer (CEO), to whom it assigns the management of the Company, with the exception of some matters which it reserves for itself, and assigns proxies to the Chairman to identify and promote integrated projects and strategically important international agreements.
The chosen model therefore establishes a clear distinction between the functions of the Chairman and those of the CEO, pursuant to Article 25 of the By-laws, both of them retain representative powers for the Company.
The Board of Directors has created three internal committees with consulting and advisory functions: the "Internal Control Committee", "Compensation Committee" and "Oil-Gas Energy Committee". Furthermore, on a proposal made by the CEO, in agreement with the Chairman, it has appointed three General Managers (Chief Operating Officers) to head the three operating Divisions of Eni⁴.
The Board of Directors, on a proposal made by the CEO, in agreement with the Chairman, subject to the prior approval of the Board of Statutory Auditors, has appointed the Company’s Chief Financial Officer as the Officer in charge of preparing financial reports.
The Chief Operating Officers and the Chief Financial Officer, together with the Chief Corporate Operations Officer and the Executives which directly report to the CEO (Senior Executive Vice President of the Company) are permanent members of the Management Committee, which advises and supports the CEO.
Some of the organizational and management choices highlighted in the Report have been made in order to fulfill US legal requirements, with which the Company has been required to comply following its listing on the New York Stock Exchange ("NYSE"). Code of Ethics
The Board of Directors believes it is fundamentally important that the values and principles which guide Eni are clearly defined, both internally and externally, in order to ensure that all company activities are implemented in compliance with the relevant laws and in a context of fair competition, honesty, integrity, fairness and good faith as well as in accordance with the legitimate interests of all the stakeholders with which Eni comes into contact on a daily basis: shareholders, employees, suppliers, customers, commercial and financial partners, as well as local communities and institutions within the countries in which Eni operates.
These values are embedded in the new Eni Code of Ethics, approved by the Board of Directors at its meeting held on March 14, 2008 to replace the previous Business Conduct Code of 1998. The Code of Ethics fulfils the evolution of the regulatory framework, expands on the issues of human rights and sustainability, ensures compliance with international best practices and updates references in relation to Eni’s new organizational structure. Everyone working for Eni, from the corporate bodies and management downwards, is specifically committed to complying and ensuring compliance with these principles in the context of their duties and responsibilities. Under no circumstances may the conviction that one is acting for the benefit of Eni justify behavior which conflicts with these principles. The Guarantor of the Code of Ethics defends and promotes these principles and presents a report on the implementation of the Code, on a half-yearly basis, to the Internal Control Committee as well as to the Board of Statutory Auditors, the Chairman and the CEO, who in turn report to the Board. With specific reference to corporate governance issues, the new Code refers to the main corporate governance rules contained in the Corporate Governance Code adopted by Eni⁵, highlighting relations with shareholders and the market and defining the general principles to be applied when disseminating company information and in relations with the media.
The Code is also a general unwaivable principle of Model 231, of which it is an integral part: the synergies between the Code of Ethics and the Model are also emphasized by the allocation of Guarantor functions with respect to the Code of Ethics to the Eni Watch Structure, the latter being established by Model 231, with responsibility for promoting and verifying its implementation.
The Code of Ethics applies to all subsidiaries which are directly and indirectly controlled in Italy and abroad by Eni. Subsidiaries which are listed on the stock exchange and those of the gas sector which are subject to so-called unbundling regulations adopt the Code and adjust it as necessary, in accordance with their own

(4)	"Exploration& Production", "Gas& Power" and "Refining& Marketing" Divisions.
(5)	For further details, see the paragraph entitled "Compliance with the Corporate Governance Code of Borsa Italiana and Eni Code".

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company peculiarities and the principle of managerial autonomy. Each subsidiary assigns Guarantor functions with respect to the Code of Ethics to its own Watch Structure.
The representatives specified by Eni in the corporate bodies of other investee companies, as well as in consortia and joint ventures, promote the principles and contents of the Code within their respective areas of responsibility.
Eni’s commitment to disseminating the principles of the Code is further underlined by the creation, under the responsibility of the Guarantor of the Code of Ethics, of a specific "Code of Ethics Promotion Team". The Team’s task is to promote knowledge and facilitate the implementation of the Code providing all the tools required to interpret and understand it. For this purpose, it promotes a variety of initiatives depending on the stakeholders involved. These initiatives also aim to stimulate observations on the Code so that it can be constantly updated to fulfill the needs of the social context in which Eni operates.
In particular, through a specific Promotion Plan, the Code of Ethics Promotion Team realized in 2009 various initiatives concerning dissemination and communication, training and participation of stakeholders.
For further details regarding dissemination and communication activities relating to the Code, see the "Sustainability" Section of the Eni website and the Sustainability Report⁶. Sustainability
Sustainability is an integral part of Eni’s governance model and is driving a process of improvement centered on issues identified through dialogue with stakeholders and discussions about future energy scenarios.
Each Sustainability objective is pursued through projects and initiatives defined by Eni and its Subsidiaries and included in specific short and medium- term action plans. Planning, implementation and control is a process shared with the Business Units and Areas and approved by the company’s highest decision-making bodies. The Board of Directors also has a key role in defining sustainability policies and approving the Sustainability Report, which is also submitted to the Shareholders’ Meeting. The audit firm certifies the Sustainability Report, verifying the correctness of the planning and management process for the activity as a whole and of the flow of data supplied by operating sites, which are subsequently consolidated and audited at level of Country, Company, Division, Corporate Management and Sustainability Unit. This certification process complies with the requirements of the ISAE 3000 standard, issued in 2004 by the International Auditing and Assurance Standard Board (IAASB), the same body that is assigned to issuing auditing principles.
The most significant initiatives carried out by Eni in recent years to ensure the sustainability of the governance system include in particular encouraging shareholders to participate in the life of the company, raising awareness among shareholders and the Board about issues connected with the model of sustainability and diversity in particular, as well as disseminating good governance practices according to the principles of the Code of Ethics.
Eni’s commitment to sustainable development is also recognized by the leading financial Sustainability indexes. In 2009, the company’s place was reconfirmed in the Dow Jones Sustainability Index and STOXX, where it has been since 2007. The company is also included in the FTSE4GOOD index and had its second place in the Accountability Rating Italy 2009 reconfirmed.
Moreover, Eni came first both in the Italian and world CSR Online Awards 2009, ranks drawn up by the financial communication company Lundquist. Finally, in June 2009 in New York, Eni’s CEO was presented with the Foreign Policy Association’s Corporate Social Responsibility Award. For further details, see the Sustainability Report and the Sustainability section of the Eni website⁷.
Information about the shareholding structure⁸ Share capital structure and significant shareholdings
The share capital of Eni consists of ordinary registered shares. The shares are indivisible and each share gives

(6)	http://www.eni.com/en_IT/sustainability/sustainability_swf.page
(7)	http://www.eni.com/en_IT/sustainability/sustainability_swf.page
(8)	The information regarding the ownership structure is provided in accordance with Article 123-bis, paragraph 1, of the Testo Unico della Finanza (Consolidated Law on Finance). For information regarding: - the mechanism for the exercise of voting rights in any employee share scheme, where voting rights are not exercised directly by the employees, as required by letter e) of the aforementioned provision, see the paragraph entitled “Shareholders’ meeting and rights”; - agreements between companies and its Directors, which provide compensation in the event of a resignation or dismissal without just cause or if employment contracts are terminated following a takeover bid, as required by letter i) of the aforementioned provision, see the paragraph entitled “Directors’ Remuneration”; - rules applicable to the appointment and replacement of Directors, as required by letter l) of the aforementioned provision, see the paragraph entitled “Appointment of the Board of Directors”; - amendments to the By-laws required by letter l) of the aforementioned provision, see the paragraph entitled “Shareholders’ meetings and rights”.

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one voting right. Owners of Eni shares may vote in the ordinary and extraordinary shareholders’ meetings of the company and may, in any case, exercise the corporate and financial rights which are ascribed to them by current regulations, in compliance with the limits imposed by the latter and by the Company’s By-laws.
On December 31, 2009, the Company’s share capital was Euro 4,005,358,876, fully paid-up and represented by 4,005,358,876 ordinary registered shares, each with a nominal value of euro 1.00.
In 1995, Eni issued an ADR (American Depositary Receipt) program for the US market. The ADR identifies the stock certificates representing shares of foreign companies traded in stock exchanges of the United States. Each Eni ADR represents two ordinary shares and is listed on the New York Stock Exchange⁹.
Based on the information available and communications received in accordance with Article 120 of Legislative Decree No. 58/1998 (Testo Unico della Finanza - Italian Consolidated Law on Finance), Consob Resolution No. 11971/1999 (Regolamento Emittenti Consob - Consob Regulations on Issuers), on December 31, 2009 the shareholders who owned a more than 2% share of Eni’s capital were:

Main shareholders

Shareholders Shares held % of capital

Ministry of Economy and Finance	813,443,277	20.31
Cassa Depositi e Prestiti SpA (a)	400,288,338	9.99
Eni SpA (own shares)	382,952,240	9.56

(a) Cassa Depositi e Prestiti SpA is controlled by the Ministry of Economy and Finance.

Shareholders by area
Shareholders	Number of shareholders	Number of shares	% of capital (a)

Italy	340,489	2,246,718,828	56.09
UK and Ireland	998	188,379,015	4.70
Other UE	4,603	523,822,062	13.08
USA and Canada	1,701	394,799,891	9.86
Rest of world	1,175	241,943,718	6.04
Own shares at the dividend date		382,952,240	9.56
Other		26,743,122	0.67
Total		4,005,358,876	100.00

(a) As of September 24, 2009, payment date of the interim dividend for fiscal year 2009 (ex-dividend date, September 21, 2009).

Shareholders by amount of shares held
Shareholders	Number of shareholders	Number of shares	% of capital (a)

>10%	1	813,443,277	20.31
3%-10 (b)	2	551,813,303	13.78
2%-3%	-	-	-
1%-2%	8	431,214,800	10.77
0.5%-1%	6	168,306,301	4.20
0.3%-0.5%	13	190,695,057	4.76
0.1%-0.3%	36	254,058,897	6.34
< 0.1%	348,900	1,186,131,879	29.61
Own shares at the dividend date		382,952,240	9.56
Other		26,743,122	0.67
Total		4,005,358,876	100.00

(a)	As of September 24, 2009, payment date of the interim dividend for fiscal year 2009 (ex-dividend date, September 21, 2009).
(b)	Afterwards, Intesa San Paolo Group reduced the percentage of shares held from 3.78% to 1.39%.

(9) For further details on ADR program see the Eni website section relative to "FAQ":http://www.eni.com/en_IT/investor-relation/investor-tools/investor-faq/investor-faq.shtml

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Eni is not subject to management and coordination activities¹⁰. Shareholding limits and restrictions on voting rights
In accordance with Article 6 of the By-laws, and applying the special rules pursuant to Article 3 of Law Decree No. 332/1994, converted into Law No. 474 of 1994 (Law No. 474/1994), under no circumstances may any party own shares in the company which constitute a direct or indirect shareholding of more than 3% of the share capital. Exceeding this limit results in a ban on exercising the voting rights and any rights – other than property rights – relative to any shareholding that exceeds the limit.
Pursuant to Article 32 of the By-laws and the same laws mentioned above, shareholdings owned by the Ministry of the Economy and Finance, public bodies or organization controlled by them are exempt from this ban.
Finally, this special rule provides that the clause regarding shareholding limits will not apply if the limit is exceeded as a result of a take-over bid, provided that, as a result of the take-over, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors¹¹. Special powers of the State (Golden Share)
Pursuant to Article 6.2 of the By-laws and to the special rules set out in Law No. 474/1994, the Ministry of Economy and Finance, in agreement with the Ministry of Economic Development, holds special powers that can be exercised in accordance with the criteria set out in the Prime Ministerial Decree of June 10, 2004. These special powers are briefly the following:
a) objection to the purchase, by parties who are subject to the shareholding limit¹², of significant shareholdings, i.e. shareholdings that represent at least 3% of the share capital and consist of shares with the right to vote in ordinary shareholders’ meetings. The objection, duly justified, must be expressed if the transaction is deemed to be prejudicial to the vital interests of the State, within ten days of the date of the notification which Directors are required to send when a request is made for registration in the register of shareholders. During the period of time allowed for the right of objection to be exercised, the voting rights and any rights other than property rights connected with the shares that represent the significant shareholding remain suspended. In the event of the right of objection being exercised, by means of a duly justified decision based on the actual prejudicial effect caused by the transaction to the vital interests of the State, the assignee will be forbidden from exercising its voting rights and any rights other than property rights connected with the shares that represent the significant shareholding, and will be required to assign these same shares within one year. In the event of a failure to comply, the Court, at the request of the Ministry of Economy and Finance, will order the sale of the shares representing the significant shareholding according to the procedures set out in Article 2359-ter of the Civil Code;
b) objection to the signing of agreements, as defined in Article 122 of the Consolidated Law on Finance, in the event that at least 3% of the share capital consisting of shares with the right to vote in ordinary shareholders’ meetings is represented in the agreements. For the purpose of allowing the right of objection to be exercised, Consob will inform the Ministry of the Economy and Finance of any significant agreements of which it has been notified under the terms of the aforementioned Article 122 of the Consolidated Law on Finance. The right of objection must be exercised within ten days of the date of Consob’s notification. During the period of time allowed for the right of objection to be exercised, the voting rights and any rights other than property rights of the shareholders signing up to the agreement are suspended. If an objection decision is issued with due justification detailing the actual prejudicial effect of the aforesaid agreements to the vital interests of the State, the agreement will be null and void. If the conduct during the Shareholders’ Meeting of the shareholders bound by the agreement reveals that the undertakings given under an agreement pursuant to the aforesaid Article 122 of the Consolidated Law on Finance have been maintained, any resolutions passed with the casting vote of these same shareholders may be challenged;
c) vetoing, if duly justified by an actual prejudicial effect to the vital interests of the State, of resolutions to dissolve the Company, transfer the company, merge, demerge, transfer the registered office overseas, change the company purpose, amend the By-laws in a way that withdraws or modifies the powers detailed

(10)

Article 19, paragraph 6, of Law Decree No. 78/2009, converted into Law No. 102/2009, states that the term enti (entities) in the reference contained in Article 2497, paragraph 1, of the Civil Code, regarding management and coordination, should be understood to refer to "legal entities other than the State that own a shareholding in the context of their business activities or for economic or financial purposes".

(11)

According to Law No. 266 of 2005 (2006 Budget Law), to which a specific paragraph of this Report is dedicated, the same clause would cease to apply if rules regarding the issue of the shares or financial instruments for which the same law provides were included in the By-laws.

(12) These are the parties described in Article 6.1 of the By-laws, excluding those described in Article 32.2.

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in letters (a), (b), (c) and the subsequent letter (d);
d) appointment of a Director with no right to vote in Board meetings.
Decisions to exercise the powers detailed in letters a), b) and c) may be challenged within sixty days, by the parties entitled to do so, before the Regional Administrative Court of Lazio. Shares and participating financial instruments referred to in Law No. 266 of December 22, 2005
In order to "promote privatization and the spread of investment in shares" of companies in which the State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266/2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily controlled by the State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any such provision. Agreements between shareholders
The Company is not aware of any agreements under the terms of Article 122 of the Consolidated Law on Finance. Significant agreements that would become effective, be modified or be extinguished in the event of a change of control of Eni
Except as follows, Eni and its subsidiaries are not parties to any significant agreements that can be disclosed without causing serious prejudice to the Company and that would become effective, be modified or be extinguished in the event of a change in the identity of the shareholders who currently control Eni. Significant agreements are considered to be agreements that have been examined and approved by the Board of Directors because they come within its exclusive areas of responsibility, as stated below.
In particular, the agreements that come into this category relate to:
(i) the Shareholders’ Agreements between Eni, Amorim Energia and Caixa Geral de Depòsitos for the joint management of Galp Energia SGPS SA. The agreement provides that in case of change of control of any participating company, the other partners have a call option to purchase the Galp shareholding held by the party whose controlling entity has changed;
(ii) any expiry of the natural gas distribution license of the subsidiary Distribuidora de Gas Cuyana SA, due to the provisions of Article 34 of title VIII of Law 24.076 if the company were to be controlled by a shareholder that engages directly or through subsidiaries in the activities production, storage or distribution of natural gas in Argentina. Proxies for capital increases, power of Directors to issue participating financial instruments and authorizations to purchase treasury shares
There are no provisions for proxies to be granted to the Board of Directors to carry out share capital increases pursuant to Article 2443.
The Directors have no powers to issue participating financial instruments.
In a resolution approved on April 29, 2008, the Shareholders’ Meeting authorized the Board of Directors, pursuant to Article 2357 of the Civil Code, subject to prior revocation of the non-implemented part of the previous authorization, to purchase treasury shares on the Electronic Stock Market within 18 months of the date of the resolution, up to a maximum of 400 million shares, with a nominal value of euro 1, and up to a total amount of euro 7.4 billion, including shares held in portfolio as of the date of the Shareholders’ Meeting, for a price no lower than their nominal value and no higher than the reference price recorded on the day before each individual purchase plus 5%.
The authorization expired on October 29, 2009¹³. On December 31, 2009, the treasury shares in Eni’s portfolio amounted to 382,952,240, the equivalent of 9.56% of share capital of Eni.
Corporate Governance information¹⁴ Compliance with the Corporate Governance Code of Borsa Italiana and Eni Code
In a resolution of the Board of Directors approved on December 13, 2006, which conformed to a similar decision of January 20, 2000, Eni adhered to the new Corporate Governance Code for listed companies

(13)	For further information, go to http://www.eni.com/en_IT/governance/shareholders/treasury-shares/treasury-shares.shtml
(14)	The governance information is also provided in accordance with the requirements of Article 123-bis, paragraph 1, letters e), i), l), and paragraph 2, of the Consolidated Law on Finance.

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promoted by Borsa Italiana, according to the version issued on March 14, 2006 ("Code of Borsa Italiana")¹⁵.
In accordance with the Code of Borsa Italiana, Eni has adopted its own Corporate Governance Code (following the "Code" or "Eni Code") for the purpose of transposing its provisions, adapting them to the specific reality of Eni, clarifying some of them and at the same time enhancing and raising the general standards of governance of the Company.
The Eni Code is therefore a clear and comprehensive description of the Company’s governance system that complies with the provisions of the Code of Borsa Italiana and with the Company’s main documents.
In particular, the Code takes into account the fact that Eni is a parent company that is not controlled by any other company and is not subject to management or coordination by others. Equally, the Code takes into account the current provisions of the By-laws, which establish a traditional administration and control system (therefore eliminating the provisions regarding the single and dual models contained in the Code of Borsa Italiana), separating the posts of Chairman and CEO (which avoids the need for a lead independent Director to be appointed) and establishing specific provisions for the appointment and composition of the Board of Directors and the Board of Statutory Auditors.
In order to ensure greater transparency and intelligibility, the Eni Code deals directly with the various options envisaged by the Code of Borsa Italiana, without therefore referring to later documents (e.g. with regard to the decision not to redistribute or modify the functions of the Board’s internal committees, to provide for a single Officer in charge of internal control, to provide for this Officer also to report to the CEO, not to assign Internal Auditing to external parties).
The provisions of the Code of Borsa Italiana that refer to the responsibilities of the Shareholders’ Meeting have been included as hopes or recommendations, since the Board cannot guarantee compliance with them.
Some of the generic recommendations of the Code of Borsa Italiana have been made specific, particularly those relating to the independence of Directors, adopting specific terms which identify "additional remunerations" that prejudice their independence and which define "close family members".
Finally, provisions have been included that raise the standard of governance proposed by the Code of Borsa Italiana and in particular:
- the interest of all stakeholders has been established as a benchmark for Directors: Directors act and decide in an informed manner and autonomously, pursuing the primary objective of creating value for shareholders, taking into account the interest of other stakeholders;
- the minimum reporting frequency to the Board on the part of Directors with proxies has been reduced from three to two months;
- for the purposes of the self-assessment of the Board (board review), it is possible to utilize the services of a specialized external consultant in order to ensure that the implemented work is objective;
- the commitment of Directors and Auditors to stay in office until they are capable of ensuring sufficient time for implementing their tasks has been emphasized;
- it has been established that the internal Committees of the Board required by the Eni Code (with specific reference to the Committee for Internal Control and Compensation Committee) shall not consist of a number of Directors that represent a majority of the Board, so as not to alter the process for Board resolutions;
- provision has been made for an opinion to be issued by the Internal Control Committee in relation to rules for ensuring transparency as well as substantive and procedural fairness during transactions with related parties – and transactions involving interests on the part of Directors. The Committee has also been ascribed a significant role in the preliminary phase of operations with related parties, in compliance with sector principles and best practices;
- for the appointment of the Officer in charge of internal control, the Board’s proposal is made by the CEO in agreement with the Chairman. In a resolution approved on October 30, 2008, the Board of Directors provided for the proposal to be made after having also heard from the Internal Control Committee and for these appointment procedures also to apply to the Senior Executive Vice President of Internal Audit; it therefore appointed the latter, with the agreement of the Committee, as Eni’s Officer in charge of internal control¹⁶;
- provision has been made for at least two members of the Internal Control Committee to have adequate experience in the accounting and financial fields (the Code of Borsa Italiana only requires one).
As of December 13, 2006, the Board of Statutory Auditors has expressly complied with the relevant provisions of the Code.
Following the adoption of the Eni Code, the Board of Directors also approved a number of resolutions implementing and specifying the provisions it contains.

(15)	The Code of Borsa Italiana is available to the public on the www.borsaitaliana.it website at: http://www.borsaitaliana.it /borsaitaliana/ufficio-stampa/comunicati-stampa/2006/codiceautodisciplina.en_pdf.htm
(16)	The Board thus confirmed a previous resolution of March 16, 2007.

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In particular:
- the functions of the Board of Directors have been redefined. The Board maintains an absolutely central position with respect to the corporate governance system of the Company and retains wide-ranging responsibilities, particularly in terms of Company and Group organization and the internal control system;
- the most significant operations of the Company and its subsidiaries have been defined and presented for approval by the Board, which is required to pay particular attention to situations in which the Directors have personal or third party interests as well as to transactions with related parties;
- the Board of Directors also has a key role in defining sustainability policies and approving the Sustainability Report, which are also submitted to the Shareholders’ Meeting;
- subsidiaries that are of strategic importance (Snam Rete Gas SpA, Saipem SpA, Polimeri Europa SpA and Eni International BV) have been identified;
- the guidelines on the maximum number of offices held by Directors in other companies have been defined in order to ensure that Directors dedicate the time required to perform their duty effectively; the provisions set for the Executive Director are extended to cover the General Managers as well;
- the principle has been established of respect for the managerial independence of listed subsidiaries (currently, in Italy, Saipem SpA and Snam Rete Gas SpA) and the commitment on the part of Eni to comply with the provisions of the Code that relate to the shareholders of issuers. This principle has been subsequently extended, as a result of developments in the legal framework, to cover companies that are subject to separate administration and accounting systems (known as "unbundling") as required by specific regulation applicable (in addition to Snam Rete Gas SpA, for Italy, Italgas SpA and Stogit SpA¹⁷).
At its meeting on April 23, 2009, the Board of Directors also established the general governance principles that Eni applies, in its position as the shareholder, to its investee companies in Italy and overseas. For this purpose, it has issued Guidelines, complemented by specific implementation rules, aimed at establishing general principles, roles and organizational responsibilities for identifying governance and control systems and for the composition of company bodies and the respective appointment criteria. In particular, the governance model chosen for the Italian companies is that of the joint-stock company with a traditional administration and control system, while for overseas companies provision has been made for the adoption of legal forms that are similar to that of a joint-stock and/or limited liability company under Italian law. The auditing of investee companies in Italy and overseas must be entrusted to an audit firm. In order to ensure adequate representation of diversity in company bodies, particularly gender diversity, a monitoring project in Eni scenery has been launched.
The Eni corporate governance system therefore complies with the requirements of the Code of Borsa Italiana and also contains provisions that improve the standard of corporate governance. Further details of the implementation of the respective provisions will be provided in the rest of this Report.
The Eni Code is published in the Corporate Governance section of the Eni website¹⁸. In order to avoid making the text too burdensome to read, the "Comment" contained in the Code of Borsa Italiana does not appear but it is borne in mind by Eni in applying the Principles and Criteria.
Shareholders’ Meetings and rights¹⁹ The Shareholders’ Meeting, whether ordinary or extraordinary, has the power to pass resolutions according to the procedures and on the matters stated in the law and in the By-laws. In particular, the Ordinary Shareholders’ Meeting appoints and dismisses Directors and Statutory Auditors, determines their remuneration, approves the financial statements (closed on December 31 of each year) and appoints the audit firm and determines its remuneration. The Extraordinary Shareholders’ Meeting passes resolutions on changes to the By-laws and operations of an extraordinary nature, such as capital increases, mergers and demergers.
As regards the rules applicable to amendments to the By-laws, Eni complies with ordinary legislation, with the exception of the terms of the paragraph relating to the special powers of the State contained in this Report, to which reference should be made. It is also worth noting that Article 23.2 of the By-laws provides for the Board of Directors to pass resolutions regarding the adaptation of provisions in the By-laws to legal requirements.
The By-laws have also assigned the Board of Directors, pursuant to Article 2365, paragraph 2, of the Civil Code, responsibility for passing resolutions on mergers

(17) With effect from July 2009, Eni sold its shareholding in the two companies to Snam Rete Gas SpA.

(18)	At the following address: http://www.eni.com/en_IT/governance/governance-model-policies/eni-corporate-governance-code/eni-corporate-governance-code.shtml
(19)	Information provided pursuant to Article 123-ii, paragraph 1, letters e) and l) with reference to changes to the By-laws, and paragraph 2, letter c), of the Consolidated Law on Finance.

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by incorporation and proportional demergers of companies at least 90% of whose shares or units are owned by the Company, as well as on the establishment and closure of secondary offices.
In order to promote the attendance of shareholders at Shareholders’ Meetings, until the new provisions become effective²⁰, the convocation will be sent out by notice addressed to Borsa Italiana and published on the website and in the Gazzetta Ufficiale, as well as, in accordance with Article 13 of the By-laws and current legislation, in the daily newspapers Il Sole 24 Ore, Corriere della Sera and The Financial Times. Convocation notices must state the provisions of the By-laws that are relevant to the meeting, including, in particular, instructions on how to obtain proxy forms.
In order to speak at a Shareholders’ Meeting, notice must be submitted, at least two working days before the date of first convocation of the Shareholders’ Meeting, by an authorized financial broker. The entitled person may withdraw this notice, through the financial broker, thus losing the right to speak at the meeting.
In order to facilitate attendance by shareholders, the By-laws provide for votes to be cast by mail and establish specific facilities for collecting proxies.
Votes sent by mail, within the period established by law, may be revoked by means of an explicit declaration made known to the Company at least one day before the Shareholders’ Meeting. Anyone intending to attend the Shareholders’ Meeting as the legal or voluntary representative of shareholders or other persons entitled to attend must submit documentation that demonstrates their powers to the relevant department of the Company according to the terms and procedures stated in the convocation notice.
Furthermore, pursuant to Article 14 of the By-laws, in order to facilitate the collection of proxies from shareholders who are employees of the Company and its subsidiaries, and who are members of shareholders’ associations that fulfill the requirements of current relevant legislation, the associations in question are provided, according to terms and procedures agreed by their legal representatives, with spaces to be used for communication purposes and for the collection of proxies.
In accordance with the law and the By-laws, within five days of the convocation notice being published, shareholders who, whether jointly or individually, represent at least one fortieth of the share capital may submit a request for the list of additional matters to be discussed. The request must state the proposed matters (which must exclude any matters that may only be proposed by the Directors or are based on plans or reports drawn up by the Directors).
In order to ensure the orderly and efficient running of Shareholders’ Meetings and allow each shareholder to contribute to the matters being discussed, on December 4, 1998, the Shareholders’ Meeting approved the regulations for its meetings, which are available on the Eni website²¹.
Shareholders’ Meetings are chaired by the Chairman of the Board of Directors or, in his stead, by the individuals named in the By-laws.
As part of the initiatives launched to stimulate the interest of shareholders and a greater degree of involvement, at the last Annual Shareholders’ Meeting (April 29-30, 2009) an interactive animation and a Shareholders’ Handbook were produced, available on the website²², in order to provide clear and immediate information on the attendance procedures and the rights that can be exercised at these events which are so important for the life of the Company and its shareholders. Eni also intends to extend these initiatives to the Shareholders’ Meeting that will be convened to approve the financial statements for 2009, paying more attention, also communicative, to the relation with its shareholders.
During the Shareholders’ Meetings, the Board strives to ensure the greatest transparency of the matters discussed by shareholders, who are granted the opportunity to ask for information about the matters included in the agenda, this information being subsequently provided in accordance with the rules regarding inside information.
Board of Directors²³ Composition
In accordance with Article 17 of the By-laws, the members of the Board of Directors vary between a minimum of three and a maximum of nine. The Ordinary Shareholders’ Meeting determines the number of members within these limits.
The By-laws state that minority shareholders may appoint a number of their own representatives on the Board that corresponds to three tenths of the total.

(20) For shareholders’ meetings whose convocation notices will be published after October 31, 2010, the new provisions will apply which transpose Directive 2007/36/EC on the convocation, contribution and voting rights of shareholders.

(21)	At the following address: http://www.eni.com/en_IT/governance/shareholder-meeting/meeting-regulation/meeting-regulation.shtml
(22)	At the following address: http://www.eni.com/en_IT/governance/shareholders/initiatives/initiatives.shtml
(23)	Information also provided pursuant to Article 123-bis, second paragraph, letter d) of the Consolidated Law on Finance.

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The Shareholders’ Meeting of June 10, 2008, set the number of Directors at nine, appointing the Board of Directors and Chairman of the Board for three financial years or in any case until the date of the Shareholders’ Meeting convened to approve the financial statements for the financial year 2010. On June 11, 2008 the Board of Directors appointed Paolo Scaroni Chief Executive Officer of Eni.
The Board consists of Roberto Poli (Chairman of the Board), Paolo Scaroni (Chief Executive Officer), Alberto Clô, Paolo Andrea Colombo, Paolo Marchioni, Marco Reboa, Mario Resca, Pierluigi Scibetta and Francesco Taranto.
Roberto Poli, Paolo Scaroni, Paolo Andrea Colombo, Paolo Marchioni, Mario Resca and Pierluigi Scibetta were elected on the basis of the list submitted by the Ministry of the Economy and Finance, which owns 20.31% of the share capital.
Alberto Clô, Marco Reboa and Francesco Taranto were elected on the basis of the list submitted by the institutional investors, which owned a total of 1.10% of the share capital at the time.
Roberto Ulissi, Corporate Affairs and Governance Senior Executive Vice President of the Company was confirmed as Secretary of the Board of Directors.
Information is provided below on the personal and professional lives of the elected Directors. ROBERTO POLI
Born in 1938. Chairman of Eni SpA since May 2002. Holds the post of Chairman of Poli e Associati SpA, a consultancy company in the fields of corporate finance, extraordinary operations, company acquisitions and restructuring plans. He is a Director of Mondadori SpA, Fininvest SpA, Coesia SpA, Maire Tecnimont SpA and Perennius Capital Partners SGR SpA. Between 1966 and 1998, he lectured in corporate finance at Università Cattolica del Sacro Cuore, in Milan. He has worked as extraordinary operations advisor for some of Italy’s largest industrial groups. He was Chairman of Rizzoli-Corriere della Sera SpA and Publitalia SpA. PAOLO SCARONI
Born in 1946. CEO of Eni SpA since June 2005. Director of Assicurazioni Generali SpA, LSEG plc (London Stock Exchange Group), Veolia Environnement (Paris), Board of Overseers of Columbia Business School, New York, and Director of the Teatro alla Scala Foundation. After graduating in Economics and Trade in 1969 at Bocconi University, Milan, and gaining initial work experience at Chevron for three years, he gained a Master’s Degree in Business Administration from Columbia University, New York, and continued his career at McKinsey. In 1973, he joined the Saint Gobain Group, where he performed numerous managerial tasks in Italy and overseas until he was appointed President of the Glass Division in Paris in 1984. Between 1985 and 1996, he was Vice President and CEO of Techint and managed the privatizations of the subsidiaries SIV, Italimpianti and Dalmine. In 1996, he moved to the UK and joined Pilkington, working as CEO until May 2002. Between May 2002 and May 2005, he was CEO and General Manager of Enel. Between 2005 and July 2006 he was Chairman of Alliance Unichem (UK). In November 2007, he was honored by France as an Officer of the Legion of Honor. ALBERTO CLÔ
Born in 1947. Director of Eni SpA since June 1999. Currently Director of Atlantia SpA, Italcementi SpA and De Longhi SpA Graduated in Political Sciences at the University of Bologna. Lecturer in Industrial Economics and Public Service Economics at the University of Bologna. In 1980, he founded the journal "Energia", of which he is editor. Author of books and over 100 essays and articles on the problems of the industrial economy and energy. Contributor to various daily newspapers and financial journals. Between 1995 and 1996 he was Minister of Industry and ad interim Minister of Foreign Trade and President of the Council of Industry and Energy Ministers of the European Union during the six-month Italian presidency. In 1996, he received the honor of "Cavaliere di Gran Croce" of the Republic of Italy. PAOLO ANDREA COLOMBO
Born in 1960. Director of Eni SpA since June 2008. Graduated in Business Administration in 1984 at the Bocconi University, Milan. Qualified as a professional accountant in 1985 and Auditor. Lecturer in the Accounting Department of the Bocconi University, Milan. Founding partner of Borghesi Colombo & Associati, a specialized consultancy firm on corporate finance operations – including taxation and business consultancy in the context of extraordinary operations – as well as strategic and corporate governance consultancy. Director of Mediaset SpA, Ceresio SIM SpA and Versace SpA; Chairman of the Board of Statutory Auditors of Aviva Vita SpA and Interbanca SpA; Statutory Auditor of Sirti SpA, A. Moratti Sapa, Humanitas Mirasole SpA, Credit Agricole Assicurazioni Italia SpA and Iniziativa Gestione Investimenti SGR SpA. Between May 2002 and May 2005, he worked as Effective Statutory Auditor of Eni SpA. Between May 2005 and May 2008, he was Chairman of the Board of Statutory Auditors.

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PAOLO MARCHIONI
Born in 1969. Director of Eni SpA since June 2008. Lawyer specialized in criminal and administrative law, counsel for defense in the Italian Supreme Court and superior jurisdictions. Advisor of public organizations, and commercial companies in matters of commercial, corporate, administrative and local government law. Mayor of the town of Baveno (VB) between April 1995 and June 2004. President of the Assembly of Mayors of Con.Ser.Vco between September 1995 and June 1999 and member of the Assembly of Mayors of ASL14, the management committee of the Verbano Health District, the Assembly of Mayors of the Waste Water Consortium of the Val d’Ossola and the Assembly of Mayors of the Social Services Consortium of Verbano until June 2004. Councilor of the Municipality of Stresa (VB) between April 2005 and January 2008. Between October 2001 and April 2004, he was a Director of C.i.m. SpA, Novara (Goods Interport Centre) and, between December 2002 and December 2005, Director and member of the Executive Committee of Finpiemonte SpA. Between June 2005 and June 2008 he was a Director of Consip. Since June 2009, he has been Vice President of the Province of Verbano-Cusio-Ossola and provincial alderman for budgeting, property, legal affairs and production activities. MARCO REBOA
Born in 1955. Director of Eni SpA since May 2005. Graduated in Business Administration at the Bocconi University, Milan. Professional Accountant and Auditor. Professor at the Faculty of Law of the Carlo Cattaneo University - LIUC - Castellanza, and author of numerous publications regarding corporate governance, economic assessment and budgeting. Works in Milan and is editor of the Rivista dei Dottori Commercialisti, an accountancy journal. Director of Luxottica Group SpA and Interpump Group SpA. Chairman of the Board of Statutory Auditors of Mediobanca SpA, Auditor of Gruppo Lactalis Italia SpA, Egidio Galbani SpA and Big Srl. MARIO RESCA
Born in 1945. Director of Eni SpA since May 2002. In 2008, he was appointed by the government as General Director for the enhancement of Italian museums within the Italian Ministry for Cultural Heritage and Activities. Chairman of Confimprese and Finbieticola Casei Gerola SpA. Director of Mondadori SpA. Graduated in Economics and Trade at the Bocconi University, Milan. Hired after graduating by Chase Manhattan Bank, in 1974 he was appointed Manager of Saifi Finanziaria (Fiat Group) and between 1976 and 1991 he was a partner in Egon Zehnder. During this period he served as a Director of Lancôme Italia, companies in the RCS Corriere della Sera Group and the Versace Group. Between 1995 and 2007, he was Chairman and CEO of McDonald’s Italia. He has also been Chairman of Sambonet SpA, Kenwood Italia SpA, founding partner of Eric Salmon & Partners and President of the American Chamber of Commerce. In June 2002, he received the honor of Cavaliere del Lavoro. PIERLUIGI SCIBETTA
Born in 1959. Director of Eni SpA since May 2005. Graduated in Economics and Business at La Sapienza University, Rome. Professional Accountant and Auditor, he has practiced at his own studio in Rome since 1990. He was Director of Gestore del Mercato Elettrico (GME) SpA, Istituto Superiore per la Previdenza e la sicurezza del lavoro (ISPESL), Nucleco SpA, FN SpA and Agenzia per l’innovazione tecnologica (AGITEC) SpA, as well as a former Deputy Extraordinary Commissioner and Director of Ente per le Nuove Tecnologie, l’Energia e l’Ambiente (ENEA) and Effective Statutory Auditor of Consorzio smantellamento impianti del ciclo del combustibile nucleare. FRANCESCO TARANTO
Born in 1940. Director of Eni SpA since June 2008. Currently Director of Cassa di Risparmio di Firenze SpA, Pioneer Global Asset Management SpA (Gruppo Unicredito) and Kedrios SpA Began his career in Milan, in 1959, at the offices of an exchange broker, subsequently working for Banco di Napoli between 1965 and 1982, where he held the post of deputy manager for the stock exchange and securities department. He has held numerous management posts in the asset management field, particularly as Director of securities funds at Eurogest, between 1982 and 1984, and general Director of Interbancaria Gestioni between 1984 and 1987. After moving to the Prime Group (1987-2000) he held the post of CEO of the parent company for many years. He is also a member of the steering council of Assogestioni and of the corporate governance committee for listed companies set up by Borsa Italiana. He was a Director of Enel between October 2000 and June 2008. Appointment²⁴
In order to ensure that the Board includes representatives of the minority shareholders, in accordance with the rules established by Law No.

(24) Information also provided pursuant to Article 123-bis, first paragraph, letter l) of the Consolidated Law on Finance.

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474/1994²⁵ and in compliance with the provisions of the Consolidated Law on Finance²⁶, the By-laws provide for Directors to be appointed by list voting. In particular, pursuant to Article 17 of the By-laws and by virtue of the provisions of Law No. 474/1994, lists may be presented both by shareholders, either individually or together with others, representing at least 1% of the share capital, or by the Board of Directors. Each shareholder may present or contribute towards presenting, and vote for, a single list. The entities that control it, the companies controlled by them and those that are jointly controlled are not allowed to present, or contribute to presenting, other lists or to vote for them, not even through a third party or trust company. The lists, which must expressly identify candidates who fulfill the independence requirements, must be deposited at the registered office at least ten days before the date for which the Shareholders’ Meeting is first convened (twenty days if presented by the Board of Directors) and published in at least three national Italian daily newspapers, two of them financial, according to the requirements of Law No. 474/1994. The lists will also be forwarded to market management companies and published on the company’s website. All candidates must fulfill the integrity requirements imposed by current laws. At the same time as each list is deposited, on pain of the list being considered inadmissible, the professional CV of each candidate must be presented together with statements in which they accept their candidacy and confirm that there are no reasons for ineligibility and incompatibility, and that they fulfill the honorability and any necessary independence requirements.
After the voting formalities have been completed, the appointment is implemented by drawing seven tenths of the Directors (rounded down to the nearest whole number in the event of a fraction), in the progressive order in which they are listed, from the list which won a majority of votes; the remaining ones being drawn from other lists which are not directly or indirectly connected with the shareholders that presented or voted for the list that came first in terms of the number of votes.
The list voting procedure only applies in the event of the whole Board of Directors being replaced.
For the appointment of Directors who were not elected by this method, for whatever reason, the Shareholders’ Meeting shall pass a resolution by the majority required by law in order to ensure that the composition of the Board complies with the law and the By-laws.
Pursuant to Article 6, paragraph 2, letter d) of the By-laws, in addition to the Directors appointed by the Shareholders’ Meeting, the Ministry of the Economy and Finance is entitled to appoint one non-voting Director in agreement with the Minister of Economic Development. This power has not be exercised. Independence requirements
The Consolidated Law on Finance establishes that at least one of the Directors, or two if the Board consists of more than seven members, must fulfill the independence requirements established for the Statutory Auditors of listed companies by Article 1, paragraph 3, of the same act, and, if required by the By-laws, the additional requirements established in the Code of Ethics.
Article 17.3 of the Eni By-laws improves on these legal requirements by providing for at least one Director, if the Board consists of no more than five members, or at least three Directors, if the Board consists of more than five members, to fulfill the aforesaid independence requirements. The same provision of the By-laws also establishes an additional mechanism to the ordinary election system that in any case ensures the existence on the Board of the minimum number of independent Directors. Eni has done this to strengthen the presence of independent Directors on the Board.
In addition to the requirements of the Consolidated Law on Finance, in accordance with the Code of Borsa Italiana, Article 3 of the Eni Code identifies further independence requirements. These requirements are the same as those set out in the Code of Borsa Italiana, specified in three separate points:
- "subsidiaries of strategic importance" of which the Director may have been a significant exponent are identified on the basis of an assessment by the Board of Directors²⁷;
- the "additional remuneration" which impairs independence is identified as being 30% of the "fixed" remuneration payable to the Company’s non-executive Directors²⁸;
- the "close family members" have been defined as family members and in-laws up to the second degree of kinship²⁹.
The Board of Directors takes into account all the above

(25)

Article 4 of Law 474/1994 provides for the Board to be elected by list voting and for at least one fifth of Directors with voting rights to be reserved for the minority lists, rounded up to the nearest whole number in case of a fraction. Shareholders’ meetings whose convocation notices will be published after October 31, 2010 will be subject to the new provisions that transpose Directive 2007/36/EC, according to which the provisions of Articles 125-bis, 147-ter and 148 of the Consolidated Law on Finance will apply to privatized listed companies, subject to the proviso that at least one fifth of Directors are drawn from the minority lists.

(26)

Article 147-ter of the Consolidated Law on Finance provides for the voting list mechanism and establishes that at least one of the members of the Board of Directors must be drawn from the minority list and that he/she must have won the majority of votes and is not connected directly or indirectly with the shareholders that presented or voted for the list which came first in terms of the number of votes.

(27)	Criterion 3.C.1.b).
(28)	Criterion 3.C.1.d).
(29)	Criterion 3.C.1.h).

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criteria in its periodic assessments of the independence of its non-executive members, prioritizing substance over than form.
Following the appointment, the non-executive Directors made the statements regarding fulfillment of the independence requirements and the Board verified that these existed, as required by current regulations and the Eni Code.
In accordance with the By-laws and the Eni Code, which require the fulfillment of independence requirements to be verified periodically, at its meeting on February 11, 2010, the Board of Directors confirmed, on the basis of the statements made and the information available to the Company, that the non-executive Directors Clô, Colombo, Marchioni, Reboa, Resca, Scibetta and Taranto are independent under the terms of the law and the By-laws, as well as the Eni Code³⁰. Director Clô was confirmed as being independent, under the terms of the Eni Code as well, even though he has held the position for over nine years³¹, because he has been appointed by the minority shareholders (specifically the institutional investors) and because of his recognized professional skills and independence of judgment.
The Board of Statutory Auditors has always verified, most recently at its meeting on February 11, 2010, the correct application of the criteria and procedures adopted by the Board for assessing the independence of its members.
The result of this assessment is summarized in the tables attached to this Report.
No lead independent Director has been appointed given the presence of a CEO and a Chairman with different roles. Integrity requirements, reasons for ineligibility and incompatibility
The Consolidated Law on Finance requires individuals who perform administration and management functions in listed company to fulfill the integrity requirements established for the members of control bodies by the Regulation of the Minister of Justice issued in accordance with Article 148 of the same act³². Article 17.3 of the By-laws transposes this provision and establishes that all candidates for the post of Director must fulfill the integrity requirements established by current legislation. Directors are also required to fulfill the additional specific requirements established by the special rules applicable to them.
The same provision also requires the Board periodically to assess both the fulfillment of independence and integrity requirements of Directors and to verify that no reasons for ineligibility and incompatibility exist.
Also under the terms of Article 17.3 of the By-laws, if one of the Directors should not fulfill or no longer fulfill the independence or integrity requirements declared and required by legislation, or if there are reasons for ineligibility or incompatibility, the Board will declare the dismissal of the Director and arrange for him to be replaced or ask for the reason for incompatibility to be removed within an established period of time, on pain of forfeiture of the post. Appointed Directors must inform the Company if they no longer fulfill the independence and integrity requirements or if reasons for ineligibility or incompatibility should arise.
Following the appointment, the non-executive Directors made the statements regarding fulfillment of the integrity requirements imposed by legislation and the Board verified their existence, as required by current regulations and the Eni Code.
In accordance with the instructions contained in the By-laws and the Eni Code, which require that the fulfillment of requirements is verified periodically by the Board, at its meeting on February 11, 2010, on the basis of the statements made and the information available to the Company, the Board of Directors verified that the integrity requirements were fulfilled and that there were no reasons for incompatibility and ineligibility affecting any of the Directors, not even in relation to the banking and financial subsidiaries. Guidelines of the Board of Directors on the maximum number of offices held by the Directors in other companies
By means of the resolution of June 11, 2008 (confirming the guidelines set by the previous Board) and as required by the Eni Code, the Board of Directors defined the general criteria pertaining to the maximum number of administration and control offices which can be held in other companies in order to ensure effective performance of the role of Director of Eni:
- an executive Director should not hold: (i) the office of executive Director in another listed company, whether Italian or foreign, or in a financial³³, banking or insurance company or in a company with net

(30)	Despite being a non-executive Director, the Chairman of the Board cannot be declared independent under a strict interpretation of the requirements of the Code of Borsa Italiana because he is a significant representative of the company (Application Criterion 3.C.2).
(31)	Director Clô was appointed for the first time in 1999.
(32)	Ministerial Decree No. 162 of March 30, 2000.

(33) For the purpose assessing the maximum number of offices, financial companies are considered to be the financial intermediaries referred to in Article 106 of Legislative Decree 385/1993 (Banking Consolidation Act) and the companies that perform investment or collective savings management services under the terms of the Consolidated Law on Finance.

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equity of over euro 10 billion and (ii) the office of non-executive Director or Statutory Auditor (or member of a controlling body) in more than three of the aforesaid companies;
- a non-executive Director, in addition to the office held in the company, should not hold: (i) the office of executive Director in more than one of the aforesaid companies and the office of non-executive Director or Statutory Auditor (or member of another controlling body) in more than three of the aforesaid companies, or (ii) the office of non-executive Director or Statutory Auditor in more than six of the aforesaid companies.
The limit on multiple offices excludes offices held in Eni Group companies.
If these limits are exceeded, the Directors will promptly inform the Board, which will assess the situation in light of the interests of the Company and will call upon the Director to take the consequent decisions. In any case, before taking up a post of Director or Statutory Auditor (or member of another controlling body) in another company that is not an investee company or a company which is directly or indirectly controlled by Eni, the executive Director must inform the Board of Directors, which will evaluate the compatibility of the office with the functions attributed to the executive Director and with the interests of Eni. The rules applicable to the executive Director also apply to Chief Operating Officers.
On the basis of the information supplied, following the appointments and at the meeting held on February 11, 2009, the Board of Directors verified that the Directors had complied with the aforementioned limits on multiple offices.
Detailed information about the number of offices held by the members of the Board with reference to the resolution on the number of offices that may be held is available in the table attached to this Report. Responsibilities
The Board of Directors has the widest powers for the ordinary and extraordinary administration of the Company in relation to its purpose.
In a resolution dated June 11, 2008, the Board appointed Paolo Scaroni as CEO and Chief Operating Officer³⁴, entrusting him with the widest powers for the ordinary and extraordinary administration of the Company, while exclusively reserving the most important strategic, operational and organizational powers in addition to those that cannot be delegated by law. These powers specify the role established for the management body in the Eni Code.
In more detail, the Board:
1. Defines the system and rules of corporate governance of the Company and the Group. In particular and after consulting the Internal Control Committee, it adopts rules which ensure transparency as well as substantive and procedural correctness in transactions with related parties and in transactions in which a Director retains a personal interest or an interest on behalf of third parties; in addition, it adopts a procedure for the handling and disclosure of corporate information, with specific reference to inside information.
2. Establishes the internal committees of the Board with advisory and consulting functions and appoints their members, while establishing their tasks and remuneration and approving their regulations.
3. Assigns and revokes proxies to the CEO and to the Chairman, defining the limits and modalities for exercising these proxies in addition to determining – after examining the proposals of the relative Committee and consulting with the Board of Statutory Auditors – the remuneration associated with these proxies. May impart directives to the delegated bodies and implement itself any operations falling under the proxy.
4. Defines the fundamental guidelines pertaining to the organizational, administrative and accounting structure of the company, including the internal control system, of the primary subsidiaries and of the Group. Assesses the adequacy of the organizational, administrative and accounting structure formulated by the CEO, particularly in reference to modalities for managing conflicts of interest.
5. Defines, in particular, after having examined the proposals of the Internal Control Committee, the guidelines of the internal control system in order to ensure the identification, measurement, management and monitoring of the primary risks of the company and its subsidiaries. Assesses, on an annual basis, the adequacy, efficacy and effective functioning of the internal control system that is supervised by the CEO.
6. Defines – on a proposal from the CEO – the strategic guidelines and objectives of the company and the Group, including sustainability policies. Examines and approves the strategic, industrial and financial plans of the company and the Group as well as agreements of strategic nature for the company. Examines and approves the plan for non-profit

(34) Paolo Scaroni was appointed CEO of the company for the first time on June 1, 2005.

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operations of the company and approves operations not included within the plan whose cost exceeds euro 500,000.
7. Examines and approves the annual budgets of the divisions as well as of the company and the consolidated Group budget.
8. Examines and approves the half-year financial report and the interim reports of the company and the Group, in accordance with currently effective regulations. Examines and approves the Sustainability Report which must be presented to the Shareholders’ Meeting.
9. Receives information from Directors with proxies – at the time of Board meetings – and in any case at least on a bi-monthly basis relative to activities implemented during the exercising of proxies as well as on activities of the Group and atypical or unusual operations or with related parties of the company which have not been presented for examination and approval to the Board. In particular, it periodically receives information on a half-year basis along with justification for any modifications applied to investment operations which were previously approved by the Board, in accordance with point 12, letter b) and c) and on the basis of criteria established by the Board itself.
10. Receives periodical half-year information from the internal committees of the Board.
11. Assesses the general management trends of the company and of the Group on the basis of information received from Directors with proxies while paying particular attention to conflicts of interest and comparing attained results – as reported in the financial statements and periodical accounting statements – with budget estimates.
12. Examines and approves the operations of the company and its subsidiaries which are significant from a strategic, economic and financial perspective, particularly with regards to situations in which one or more Directors retain personal or third party interests as well as related parties transactions; In the case of listed companies, as well as companies subject to unbundling regulations, the Board must guarantee the principle of managerial autonomy. These provisions are applicable without prejudice to compliance with confidentiality obligations pertaining to commercial relations between the subsidiary and Eni or third parties, thereby protecting the interests of the subsidiary.
The following operations are considered significant in nature:
a) acquisitions or sales of shareholdings, companies or company branches, mineral rights and real estate, company mergers, spin-offs and liquidations, whose value exceeds 100 million Euro and without prejudice to the provisions of Article 23.2 of the By-laws;
b) investments in fixed asset whose value exceeds euro 300 million or even of smaller amount if of particular strategic value or in the case of specific risks;
c) exploration initiatives and portfolio operations in the E&P sector in new countries;
d) purchase and sale of goods and services other than those allocated for investments and gas supplies, for an overall price exceeding euro 1 billion – excluding the purchase and sale of real estate and services included in ordinary administration – or whose duration exceeds 20 years; gas supply contracts, or amendments to such contracts, for a minimum of three billion cubic meters per year and a ten-year duration;
e) financing to parties other than subsidiaries: (i) for amounts exceeding euro 200 million if in proportion to the shareholding quota or (ii) in the case of any amount if provided in favor of non-subsidiaries or for amounts that are not proportional to the shareholding quota;
f) the issue of personal or real securities to parties other than subsidiaries: (i) for amounts exceeding euro 200 million, if in the interest of the company or of subsidiaries, or in the interest of non-subsidiary companies, so long as the security is proportional to the shareholding quota, or (ii) in the case of any amount if provided in the interest of non-controlled subsidiaries or if the security is not proportional to the shareholding quota. For the issue of the securities pursuant to point (i) whose amount ranges between euro 100 and 200 million, the Board grants a joint proxy to the CEO and the Chairman;
g) Eni SpA intermediary agreements.
13. Appoints and dismisses – on a proposal from the CEO and in agreement with the Chairman – the Chief Operating Officers and grants their powers. If the CEO is appointed as the Chief Executive Officer, the proposal is made by the Chairman.
14. Appoints and dismisses – on a proposal from the CEO, in agreement with the Chairman and following approval from the Board of Statutory Auditors – the Officer in charge of preparing financial reports and ensures that the Officer is equipped with adequate powers and means in order to exercise his legally ascribed tasks in addition to monitoring the effective compliance with the administrative and accounting procedures formulated by this Officer.
15. Appoints and dismisses – on a proposal from

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the CEO, in agreement with the Chairman and following a consultation from the Internal Control Committee – an Officer in charge of internal control and an Senior Executive Vice President of Internal Audit in addition to defining their remuneration in accordance with the compensation policies of the company as well as approving the guidelines for the activities of these two managers.
16. Ensures that a manager is appointed for the body which manages shareholder relations.
17. Defines – after having examined the proposals of the relative Committee – the criteria for remunerating the top management of the Company and of the Group in addition to implementing the compensation plans on the basis of stocks or financial instruments deliberated by the Shareholders’ Meeting.
18. Resolves – on a proposal from the CEO – on the exercise of voting rights and on the appointment of members of corporate bodies of the primary subsidiaries. In the case of listed companies, the Board must guarantee compliance with the provisions of the Corporate Governance Code falling under the competence of the Shareholders’ Meeting.
19. Formulates the proposals to present to the Shareholders’ Meeting.
20. Examines and resolves on other issues which Directors with proxies believe it is appropriate to present to the Board due to their particular relevance or sensitivity. In accordance with Article 23.2 of the By-laws, the Board also resolves: on merger by incorporation operations and proportional demergers operations of at least 90% directly owned subsidiaries; on the creation and closing of secondary offices; and on adjustments of the By-laws to regulatory requirements.
During the financial year, the Board may also resolve on the distribution to shareholders of advance interim dividends, as allowed by Article 29.3 of the By-laws.
At its meeting held on June 30, 2008, the Board granted proxies to the Chairman, Roberto Poli, to identify and promote integrated projects and international agreements of a strategic nature, in accordance with Article 24.1 of the By-laws. In accordance with Article 27 of the By-laws, the Chairman chairs the Shareholders’ Meeting, convenes and chairs meetings of the Board of Directors and verifies implementation of the resolutions passed by the Board. At its meeting held on June 11, 2008, the Board identified Saipem SpA, Snam Rete Gas SpA, Eni International BV and Polimeri Europa SpA as subsidiaries of strategic importance for the purposes of the approval of transactions pursuant to point 12 of the aforementioned powers.
At its meeting held on January 18, 2010, the Board of Directors confirmed the appropriateness of the organizational, administrative and accounting structure of the Company, the main subsidiaries and the Group.
At its meeting held on March 11, 2010, the Board of Directors confirmed the appropriateness, effectiveness and efficient operation of Eni’s internal control system as a whole. At the same meeting, pursuant to Article 154-bis of the Consolidated Law on Finance, the Board also verified compliance with the administrative and accounting procedures established by the Officer in charge of preparing financial report and also confirmed the appropriateness of the powers and resources assigned to him for the performance of his duties.
At its meeting held on February 12, 2009, with the approval of the Internal Control Committee, the Board approved the Guidelines on transactions involving interests of Directors (and Statutory Auditors) and those with related parties³⁵.
At its meeting held on February 25, 2010, the Board carried out a self-assessment of its composition and operation³⁶. Meetings and running of meetings
At its meeting on September 10, 2009, the Board of Directors approved the regulations that established the procedures for convening and running its meetings. In particular, the Board is convened by the Chairman who – in agreement with the CEO – draws up the agenda and sends it to the Directors, effective Statutory Auditors and the Judge of the Court of Auditors delegated with the task of financially auditing Eni; the notice must be sent at least five days before the date set for the meeting. In cases of necessity and urgency, the convocation notice is sent at least 12 hours before the date set for the meeting. The By-laws allow meetings of the Board to take place by videoconferencing or teleconferencing, these methods being specifically governed by the regulations.
Normally, at the same time as the convocation notice is sent out, and in any case no less than three days before the date of the meeting, the Directors, effective Statutory Auditors and the Judge of the Court of Auditors are provided with documentation on the

(35)	For further details see the paragraph of the Report specifically dedicated to this topic.
(36)	For further details see the paragraph of the Report specifically dedicated to this topic.

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matters included in the agenda, with the exception of price-sensitive information, which is not included in any prior communication. Managers of the company and its subsidiaries are typically invited to attend Board meetings in order to provide information on specific topics pertaining to the agenda. Specific information is also provided on the individual sectors in which the Company and the Group are operating.
In accordance with the provisions of Article 2391 of the Italian Civil Code and of the Eni Code, before each item on the agenda of the Board meeting is discussed, each Director is required to report any personal or third party interests that he/she may have in relation to the topics or issues under discussion, specifying their nature, terms, origin and scope. Transactions in which a Director (or Statutory Auditor) retains an interest or is a related party are regulated by the Guidelines relative to transactions involving interests of Directors (or Statutory Auditors) and related parties transactions, approved on February 12, 2009 by the Board of Directors following consultation with the Internal Control Committe.
During 2009, the Board of Directors met 17 times for an average of 3 hours and 17 minutes at a time. In 2009, an average of 98.7% of Directors attended Board meetings and, in particular, 98.3% of independent Directors. During the current financial year, as of March 11, 2010, 5 meetings have been held, including the one held on that date. A further 12 meetings are planned to take place before the end of the financial year.
The public is notified in advance, usually by the end of the financial year, of the dates of meetings of the Board of Directors to review the pre-final results, the financial statements and the intra-year accounting reports required by current legislation. These meetings also serve to determine the interim dividend payable for the year and to submit a proposal for balance of the dividend to the Shareholders’ Meeting along with the relative dates for dividend payment and detachment of the coupon. The financial calendar is available on the Eni website³⁷.
The Eni Code allows independent Directors to decide whether to meet in the absence of the other Directors for discussion of topics deemed relevant to the functioning of the Board. This express provision allowing such meetings to take place was requested by the independent Directors themselves in order to have greater flexibility to deal with actual requirements. In 2009, the independent Directors, in consideration of the frequency of the Board meetings, had numerous opportunities to meet, holding formal and informal meetings to hold discussions and exchange opinions.
The tables attached to this Report show each Director’s percentage of attendance at meetings of the Board of Directors and meetings of the committees of which they are members. Board Review
In accordance with international best practice and with the provisions of the Code of Borsa Italiana, as well as required by the Eni Code, for the fourth year running, the Board of Directors has launched a self-assessment program (board review) of the Board of Directors and the Board Committees.
The Board of Directors carried out the assessment, availing itself, as required by the Eni Code in order to ensure maximum objectivity to the assessment, of the assistance of a specialized external consultant: the company Spencer Stuart, appointed at the end of a formal tender.
Spencer Stuart’s work related to: (i) the size, composition, operation and efficiency of the Board and of the Committees; (ii) identifying any elements that might hinder or improve the operation and efficiency of the Board itself; (iii) the effectiveness of the improvements undertaken following the previous board review and verification of the satisfaction of Directors with their achievement; (iv) comparison of procedures and practices adopted by the Eni Board with the best practices used by leading Italian and foreign companies.
The Board Review was based on a questionnaire prepared by the consultant and on detailed individual interviews with the Directors, carried out by the consultant. The results were presented to the Board, which discussed at its meeting on February 25, 2010. First of all, the Board confirmed various areas of excellence, such as: (i) the proper size of the Board of Directors and constant attendance by Directors; (ii) the transparent presentation of topics during Board meetings, and the availability of management to provide all the required information during the meeting of the Board; (iii) satisfactory quantity and quality of the information provided, even in the period between the meetings of the Board, and the punctual updates received on legislative and regulatory developments; (iv) accurate minuting of meetings and decisions of the Board; (v) fruitful and accurate work carried out by committees, particularly the Internal Control Committee and the Oil-Gas Energy Committee.

(37) At the following address: http://www.eni.com/en_IT/investor-relation/financial-calendar/financial-calendar.shtml

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The Directors also convened to undertake, in a proper meeting, a detailed analysis of the results of the Board review and the comparison with the best practice, in particular in order to identify the most appropriate conditions to: (i) allow the Board to focus its attention on strategic and directive issues; and (ii) increase the value of contribution of non-executive Directors. Induction program of the Board of Directors
In accordance with the provisions of the Eni Code relative to the effective and conscious implementation of each Director’s role, Eni drew up, for the Board currently holding office, immediately after their appointment, an induction training plan (board induction) allowing the new Directors to acquire detailed knowledge of the activities and organization of the company, its industry and their role considering the specific characteristics of Eni. The program, which also involved the new members of the Board of Statutory Auditors, and to which the other members of the two company bodies were also invited, began on June 30, 2008, and was implemented by setting up a series of meetings dedicated to analyzing the identified themes in depth, with the involvement of senior managers and the participation of external speakers of acknowledged professionalism. The meetings covered the following topics: (i) responsibilities, duties, powers, composition and operation of the Board of Directors; (ii) the market and the relevant sector; (iii) organization; (iv) Group business; (v) business administration; (vi) sustainability and ethics of business administration; (vii) technological innovation. In 2009, more detailed examinations of business issues were carried out and are still under way. In this context, for example, Board meetings can be held in locations other than the registered offices of companies, even abroad, in order to increase knowledge of company operations. Remuneration report
General Criteria
The Eni Remuneration System is intended to strengthen values, skills and competencies that are consistent with the culture and strategy of the company, recognizing the responsibilities assigned, the results achieved, the quality of professional contributions and the potentiality of development of the resource in the context of the relevant international remuneration markets.
An important element of Eni’s remuneration policy is the variable incentive systems associated with the achievement of economic/financial, business development and operating targets established to ensuring the sustainability of results and the creation of value for shareholders over a medium to long-term period, in accordance with Eni’s Strategic Plan.
The remuneration system is complemented by benefits, which consist of goods and services primarily associated with supplementary social security and health care. Governance Rules
The remuneration of the Board Members is determined by the Shareholders’ Meeting.
Remuneration of the Board Members invested with particular powers (Chairman and Chief Executive Officer) is determined by the Board of Directors on proposal of the Compensation Committee after consultation with the Board of Statutory Auditors.
The general criteria for the remuneration of managers with strategic responsibilities³⁸ are approved by the Board of Directors, on proposal of the Compensation Committee, which examined the indications of the CEO. Remuneration structure
On June 10, 2008, the Shareholders’ Meeting confirmed the structure and amounts established in 2005, fixing the annual remuneration due to the Chairman (euro 265,000) and the Board Members (euro 115,000) and the variable remuneration determined according to Eni’s position in the reference year in terms of share performance, considering the dividend paid out, compared to that of the seven other largest international oil companies for market capitalization. The variable part of the remuneration is paid to the Chairman, in the amount of euro 80,000 or euro 40,000, and to the Board Members, in the amount of euro 20,000 or euro 10,000, depending on whether the performance of Eni shares is rated first or second or third or fourth in the reference year, respectively. In other cases, the variable part is not paid. On March 25, 2009, the Board of Directors verified that Eni rated fourth in 2008.
On June 11, 2008, the Board of Directors confirmed the structure and amounts established in 2006, deciding the remuneration of the Board Members attending the Committees established by the Board, excluding the Chairman and the CEO. For the Chairman of a Committee, the annual fee is euro 30,000, for the other members, the annual fee is euro 20,000. This amount decreases to euro 27,000 and euro 18,000 in case a member holds positions in more than one Committee.
On June 10, 2008, the Shareholders’ Meeting resolved

(38) Managers who have been members of the Eni’s Steering Committee, with the CEO and the General Managers of Eni’s Divisions, and Eni Senior Executive Vice Presidents who report directly to the CEO.

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that the Company continues to apply the insurance policy already authorized in May 25, 2006, in favor of the Board Members and Statutory Auditors for risks associated with the execution of the respective tasks.
The remuneration structure of the Chairman, in relation to the powers delegated to him, consists of a fixed part and a variable part associated with the achievement of specific company objectives established for the previous financial year.
The remuneration structure of the CEO consists of a fixed component, based on the powers delegated to him, and an annual variable component associated with the achievement of specific company objectives (economic/financial, operating and strategic) established for the previous financial year and a variable long-term component composed by two separate plans with different company performance conditions, established over a three-year period and measured both in absolute terms and in relative terms compared to an oil industry peer group.
The remuneration structure of managers with strategic responsibilities and other managerial resources consists of a fixed remuneration, determined according to the role and responsibilities assigned, with reference to the levels applied to equivalent positions in large national and international companies (oil, industrial and services sectors) and with annual adjustments according to merit (continuity of individual performance) or promotion (progression in terms of role/responsibility), and a variable annual remuneration associated with the achievement of specific economic, financial and operating targets, and a variable long-term remuneration associated with company performance, measured over a three-year period.
In 2009, the variable annual remuneration of the Chairman and CEO was determined in accordance with Eni’s objectives for 2008 as approved by the Board of Directors, on proposal of the Compensation Committee, defined in accordance with Eni’s Strategic Plan and annual budget in terms of adjusted EBITDA, divisional operating performance, reduction in company costs and maintaining of position in sustainability indexes. The company results, assessed on a constant scenario basis, have been verified by the Compensation Committee and approved by the Board of Directors and have set out the score of 120 on a scale of 85 (minimum) - 130 (maximum), used for the purpose of determining the variable remuneration to be paid.
On March 25, 2009, the Board of Directors resolved to eliminate the Eni Stock Option Plan for 2009 and to maintain the Deferred Monetary Incentive Plan for the three-year period 2009-2011. This Plan, which is aimed at all managerial resources and is focused on certain business growth and operating efficiency targets, provides for an incentive to be paid after a period of three years in an amount connected with the achievement of annual EBITDA objectives (actual results vs. budget, on a constant scenario basis) defined for the reference three-year period.
In order to adopt an alternative incentive scheme to Stock Option Plan, the Compensation Committee defined a new long-term incentive plan for critical managerial resources that will be approved by the Board of Directors in 2010. In 2009 the Board of Directors approved a plan with similar characteristics for the CEO; this plan provides for an incentive to be paid after a period of three years in an amount connected with the variation of the adjusted net profit + DD&A (Depletion, Depreciation & Amortization), measured over the three-year period 2009-2011 in relative terms compared to the other six largest international oil companies for market capitalization.
In 2009, the vesting period of the long-term incentive plan assigned in 2006 expired. This plan consisted of a Deferred Monetary Incentive Plan, aimed at managerial resources, and a Stock Option Plan, aimed only at managerial resources holding positions that are more directly responsible for results and are of strategic interest. The Board of Directors, on March 25, 2009, based on the results achieved in 2006-2008, as verified by the Compensation Committee, resolved that: (i) with reference to the Deferred Monetary Incentive Plan, a multiplier of 143% should be applied to the amount awarded in 2006, calculated on the basis of the performance achieved in terms of Eni’s EBITDA; (ii) with reference to the Stock Option Plan, a percentage of 47% of exercisable options, calculated on the basis of the performance achieved in terms of Eni’s relative TSR, should be applied to the total amount granted in 2006.
The CEO, in his quality of General Manager, participated in both Plans.

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In 2009, the remuneration structure of the Chairman, CEO, Divisional Chief Operating Officers and other managers with strategic responsibilities was the following:

(%)    Chairman CEO Divisional COO Other managers with strategic responsibilities

Fixed remuneration	66	22	46	50
Annual variable remuneration (linked to performance)	34	27	32	31
Long-term variable remuneration (linked to performance) (a)		51	22	19
Total	100	100	100	100

(a) Evaluation of the deferred monetary incentive (discounted) for target result.

Remuneration earned by members of the Board of Directors, Statutory Auditors, Chief Operating Officers, and other managers with strategic responsibilities
Pursuant to Article 78 of Consob Decision No. 11971 of May 14, 1999, and to its subsequent modifications, remuneration earned by members of the Board of Directors, Statutory Auditors, Chief Operating Officers and other managers with strategic responsibilities is reported in the table below. Remuneration earned by managers who held a position in 2009 for a fraction of the year is reported too.
Pursuant to Consob decisions:
- in the column "Emoluments for service at Eni SpA" are reported fixed fees paid to non-executive and executive directors, fixed fees paid to Directors attending the Committees formed by the Board of Directors, and fees paid to Statutory Auditors. Fixed fees earned by the Chairman and the CEO include also fees earned for the powers delegated to them by the Board; - in the column "Non-cash benefits" are reported amounts referring to all fringe benefits, including insurance policies;
- in the column "Bonuses and other incentives" are reported the portion of fees linked to performances which was awarded in the year to both non-executive directors and executive directors, and the portion of salaries linked to performances which was awarded in the year to the CEO, the Chief Operating Officers of Eni’s Divisions and other managers with strategic responsibilities;
- in the column "Salaries and other elements" are reported base salaries and elements associated to salary paid to the CEO, the Chief Operating Officers of Eni’s Divisions and other managers with strategic responsibilities, and indemnities paid upon termination of the employment contract. Referring to the Statutory Auditors, fees paid for positions held on the Board of Statutory Auditors in Eni’s subsidiaries are also reported.

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(euro thousand)
Name	Position	Term of office	Expiry date of the position (a)	Emoluments for service at Eni SpA	Non-cash benefits	Bonuses and other incentives (b)	Salaries and other elements	Total

Board of Directors
Roberto Poli	Chairman	01.01-12.31	04.2011	765		400		1,165
Paolo Scaroni	CEO	01.01-12.31	04.2011	430	1	2,824	1,017	4,272
Alberto Clô	Director	01.01-12.31	04.2011	162		10		172
Paolo Andrea Colombo	Director	01.01-12.31	04.2011	96		10		106
Paolo Marchioni	Director	01.01-12.31	04.2011	107		10		117
Marco Reboa	Director	01.01-12.31	04.2011	163		10		173
Mario Resca	Director	01.01-12.31	04.2011	162		10		172
Pierluigi Scibetta	Director	01.01-12.31	04.2011	96		10		106
Francesco Taranto	Director	01.01-12.31	04.2011	153		10		163
Board of Statutory Auditors
Ugo Marinelli	Chairman	01.01-12.31	04.2011	121				121
Roberto Ferranti (c)	Auditor	01.01-12.31	04.2011	84				84
Luigi Mandolesi	Auditor	01.01-12.31	04.2011	84				84
Tiziano Onesti (d)	Auditor	01.01-12.31	04.2011	84			40	124
Giorgio Silva	Auditor	01.01-12.31	04.2011	44				44
Divisional Chief Operating Officers
Claudio Descalzi	Exploration & Production	01.01-12.31			3	772	734	1,509
Domenico Dispenza	Gas & Power	01.01-12.31			1	1,002	745	1,748
Angelo Caridi	Refining & Marketing	01.01-12.31			2	648	642	1,292
Other managers with strategic responsibilities (e)					15	4,179	4,266	8,460
				2,551	22	9,895	7,444	19,912

(a)	The term of position ends with the Meeting approving financial statements for the year ending December 31, 2010.
(b)	Based on the annual incentive plan related to performance achieved in 2008 (euro 6,283 thousand) and payment of the deferred monetary incentive granted in 2006 (euro 3,612 thousand).
(c)	Compensation for the service is paid to the Ministry for Economy and Finance.
(d)	Includes the compensation obtained as Chairman of the Board of Statutory Auditors of AGI and Servizi Aerei.
(e)	Managers who, during the year, have been members of Eni’s Management Committee with the CEO and the Divisional Chief Operating Officers, and Eni Senior Executive Vice Presidents who report directly to the CEO (8 managers).

Long-Term Incentive Plan awarded to the CEO,
the Divisional Chief Operating Officers
and managers with strategic responsibilities 1. DEFERRED MONETARY INCENTIVE
The deferred bonus scheme approved for the 2009-2011 three-year period provides for the award of a basic monetary bonus to be paid after three years from grant according to a variable amount equal to a percentage ranging from 0 to 170% of the amount established for the target performance in relation to the performances achieved in a three-year period as approved by the Board of Directors. The following table sets out the basic bonus awarded in the year 2009 to the CEO and to the Divisional Chief Operating Officers, and the total amount awarded to the Company’s managers with strategic responsibilities.

(euro thousand)

Name Deferred bonus awarded

Paolo Scaroni	CEO and General Manager of Eni	787
Claudio Descalzi	COO of the E&P Division	340
Domenico Dispenza	COO of the G&P Division	350
Angelo Caridi	COO of the R&M Division	307
Other managers with strategic responsibilities (a)		1,612

(a) No. 8 managers.

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With reference to Eni Board of Directors’ resolution not to implement the Eni stock option Plan for 2009 and the relevant commitment to the CEO of adopting an alternative incentive scheme with the same financial effectiveness, has been approved a new long-term monetary incentive plan in behalf of CEO to replace and compensate the Eni stock option Plan for 2009, whose value and characteristics are comparable with those of the former plan.
Performance conditions of this plan are set in terms of variation of the Adjusted Net Profit + Depletion Depreciation & Amortization (DD&A) measured on 2009-2011 three-year period and compared, in relative terms, to that of the other six largest international oil companies for market capitalization.
The amount of incentive assigned in 2009 is euro 2,716,391 and it’ll be paid in 2012, after a three-year vesting period, in a percentage ranging from 0 to 130% of the amount assigned in 2009 in relation to the performance achieved in the reference three-year period. 2. STOCK OPTIONS
Following the decision of Eni’s Board of Directors to discontinue any stock option plans from 2009, information reported herein on Eni’s stock based compensation relates to plans adopted in previous years whereby options to purchase treasury shares were awarded for no consideration to managers of Eni and its subsidiaries as defined in the Article 2359 of the Civil Code holding positions of significant responsibility for achieving the Company’s profitability targets or are otherwise strategically important. The stock option scheme provided that grantees had the right to purchase treasury shares in a 1 to 1 ratio, with a strike price calculated as the arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding award or, if greater, as the average carrying cost of treasury shares held by Eni as of the date preceding the award.
The most recent stock option scheme covered the three-year period 2006-2008 and was approved on May 25, 2006, by the Shareholders’ Meeting that authorized the Board of Directors to dispose of a maximum amount of 30 million treasury shares (equal to 0.749% of the share capital) for the stock option plan. This stock option plan also provided a performance condition upon which options can be exercised. At the end of each vesting period with a three-year duration, the Board of Directors determined the number of exercisable options, in a percentage ranging from 0% to 100% of the total amount awarded for each year of the scheme, depending on the performance of Eni shares measured in terms of Total Shareholder Return as compared to that achieved by a panel of major international oil companies in terms of market capitalization. Options may be exercised upon fulfillment of all conditions after three years from the award and within the next three years.
At December 31, 2009, a total of 19,482,330 options were outstanding for the purchase of an equal amount of ordinary shares nominal value euro 1.00 of Eni SpA, carrying an average strike price of euro 23.576. The following is a summary of residual stock option activity as in 2009 there were no awards:

2008 2009

Number of shares Weighted average exercise price (euro) Market price ^(a) (euro) Number of shares Weighted average exercise price (euro) Market price ^(a) (euro)

Options as of January 1	17,699,625		23.822	25.120	23,557,425	23.540	16.556
New options granted	7,415,000		22.540	22.538
Options exercised in the period	(582,100	)	17.054	24.328	2,000	13.743	16.207
Options cancelled in the period	(975,100	)	24.931	19.942	4,073,095	23.374	14.866
Options outstanding as of December 31	23,557,425		23.540	16.556	19,482,330	23.576	17.811
of which exercisable at December 31	5,184,250		21.263	16.556	7,298,155	21.843	17.811

(a) Market price relating to new rights assigned, rights exercised in the period and rights cancelled in the period correspond to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of assignment; (ii) the date of the recording in the securities account of the managers to whom the options have been assigned; (iii) the date of the unilateral termination of employment for rights cancelled). Market price of shares referring to options as of the beginning and the end of the year, is the price recorded at December 31.

Further information on stock options is furnished in Note 31 to the Consolidated Financial Statements. The following table presents the amount of outstanding stock options awarded in past years to Eni’s CEO, Divisional Chief Operating Officers and other managers with strategic responsibilities.

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CEO and General Manager of Eni	COO of E&P Division	COO of G&P Division	COO of R&M Division	Other managers with strategic responsibilities (a)
Paolo Scaroni (b)	Claudio Descalzi	Domenico Dispenza	Angelo Caridi

Options outstanding at the beginning of the period:
- number of options		2,587,500	264,000	380,000	142,000	(c)	150,500	122,000	(d)	1,671,000	80,500	(e)
- average exercise price	(euro)	23.767	24.009	24.142	4.399		22.534	21.098		23.660	21.545
- average maturity in months		55	55	56	54		65	48		56	48
Options granted during the period:
- number of options
- average exercise price	(euro)
- average maturity in months
Options exercised at the end of the period:
- number of options											35,600	(e)
- average exercise price	(euro)										17.519
- average market price at date of exercise	(euro)										22.264
Options expired during the period:
- number of options		360,930	40,280	64,925				14,700	(d)	233,995	8,900	(e)
- average exercise price	(euro)	23.100	23.100	23.100				17.519		23.100	17.519
- average market price at date of exercise	(euro)	14.079	14.079	14.079				12.240		14.079	12.240
Options outstanding at the end of the period:
- number of options		2,226,570	223,720	315,075	142,000	(c)	150,500	107,300	(d)	1,437,005	36,000	(e)
- average exercise price	(euro)	23.875	24.173	24.357	4.399		22.534	21.588		23.751	26.521
- average maturity in months		45	46	46	42		53	36		46	43

(a)	No. 8 managers.
(b)	The assignment to the CEO have been integrated in 2007 with a monetary incentive to be paid after three years in relation to the performance of Eni shares, equal to 80,500 options with a strike price of euro 27.451. Relating to the attribution of this incentive for 2006, equal to 96,000 options with a strike price of euro 23.100, the conditions for its payment were not fulfilled, since the price of Eni share resulted lower to the exercise-price at the end of the three-year vesting period.
(c)	Options on Snam Rete Gas shares: assigned by the company to Domenico Dispenza who held the position of Chairman of Snam Rete Gas until December 23, 2005.
(d)	Options on Saipem shares: assigned by the company to Angelo Caridi who held the position of CEO of Snamprogetti until August 2, 2007.
(e)	Options on Saipem shares.

Indemnity upon termination
Upon expiry of the contract as employee of Eni, the CEO in his quality of General Manager of the parent company is entitled to receive an indemnity that is accrued along the service period. The indemnity is determined by taking into account social security contribution rates and post-retirement benefit computations applied to the CEO base salary and 50% of the bonuses earned as a Director.
In 2009 a provision of euro 244,435.07 has been accrued. In case the work contract of the CEO is terminated at or before the expiry of his office, the CEO will receive a termination payment, in addition to other termination elements, equal to euro 3,200,000 plus an amount corresponding to the average performance bonus earned in the three-year period 2008-2010 in lieu of notice thus waiving both parties from any obligation related to notice. This payment is not applicable in case the work contract is terminated upon due cause, death or resignation from office other than as a result of a reduction in powers currently attributed to the CEO. 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, general managers and other managers holding strategic responsibilities amounted to euro 35 million for 2009 consisting of: (i) fees and salaries for euro 20 million; (ii) post-employment benefits for euro 1 million; (iii) other long-term benefits for euro 10 million; and (iv) fair value of stock option for euro 4 million.

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Board Committees³⁹ The Board has set up three internal committees, two of which are required by the Code of Borsa Italiana, with consulting and advisory functions: a) the Internal Control Committee, b) the Compensation Committee and c) the Oil-Gas Energy Committee. The composition, tasks and operation of the committees are governed by the Board, according to specific regulations, in compliance with the criteria outlined in the Eni Code.
The committees required by the Code (Internal Control Committee and Compensation Committee) consist of no fewer than three members, although the number of members must not exceed the majority of members of the Board. All the committees must consist of non-executive Directors, the majority of whom must be independent.
In performing their functions, the committees retain the right to access any information and company departments that are necessary to carry out their tasks. They are also provided with adequate financial resources and retain the right to avail themselves of external consultants according to terms established by the Board of Directors. Meetings of the committees may also be attended by non-members expressly invited to attend with reference to individual items on the meeting agenda. Meetings of the Internal Control Committee are attended by the Chairman of the Board of Statutory Auditors or an Effective Auditor appointed by him. Committee meetings are minuted by the respective Secretaries.
At the meeting held on June 11, 2008, the following non-executive Directors, all of them independent, were appointed as members of the committees:
- Internal Control Committee: Marco Reboa (Chairman), Francesco Taranto, Pierluigi Scibetta and Paolo Marchioni.
- Compensation Committee: Mario Resca (Chairman), Francesco Taranto, Alberto Clô and Paolo Andrea Colombo.
- Oil-Gas Energy Committee (OGEC): Alberto Clô (Chairman), Marco Reboa, Mario Resca, Paolo Andrea Colombo and Pierluigi Scibetta.
In accordance with the Code of Borsa Italiana, the Eni Code provides for the Board of Directors to determine whether to set up an Appointments Committee, particularly in cases where the Board finds that it is difficult for shareholders to draw up proposals for appointment, as can happen in a listed company with a diversified shareholder base. No such Committee has ever been set up because of the nature of the Company’s shareholders and because, under the terms of the law and the By-laws, the Directors are appointed by the Shareholders’ Meeting on the basis of lists presented by shareholders.
The regulations of the three Committees are available on the Eni website. Internal Control Committee
During 2009, the Committee met 20 times, and the meetings were attended on average almost by 94% of its members⁴⁰.
The composition, appointment and operating procedures, tasks, powers and resources of the Committee are governed by a specific regulation, a new version of which was approved by the Board of Directors at the end of December 2009 in order to update its content to the provisions of other company documents published since the previous version, which was produced in March 2007.
The following is a summary of the main topics examined during the year:
(i) the final statement on Eni’s Internal Audit activities in 2008, the Integrated Audit Plan for 2009 and the Eni Internal Audit Budget for 2009, together with the respective periodic states of progress;
(ii) the final data for operations in 2008 and the 2009 Plan for Internal Auditing Functions of the subsidiaries Saipem and Snam Rete Gas;
(iii) the results of planned and non-planned audits issued by the Internal Audit Department of Eni as well as the outcomes from monitoring the state of execution of corrective actions planned by operational divisions for overcoming issues which emerged during the audit, including in-depth analysis of certain specific themes;
(iv) the results of audits implemented by the Internal Auditing Department of Eni in connection with specific requests made by Controlling Bodies;
(v) the periodic reports on reports, including anonymous ones, received by Eni and subsidiaries;
(vi) the report on Eni’s Internal Control System produced by the Officer in charge of internal control;
(vii) the Guidelines adopted by Eni regarding transactions involving interests of Directors and related parties transactions;
(viii) the periodic report on activities carried out by the Eni SpA Watch Structure, including information on the functions of the Guarantor of the Code of Ethics, after meeting the members of the Structure itself, as required by Eni Model 231;
(ix) reports relative to news/notifications of investigations on the part of bodies/authorities of the Italian or foreign governments with criminal jurisdiction or, in any case, retaining powers of

(39)	Information provided pursuant to Article 123-bis, second paragraph, letter d) of the Consolidated Law on Finance.
(40)	For further details of the tasks of the Internal Control Committee, see the "Internal Control System" paragraph of this Report.

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judicial investigation with reference to crimes which could, even potentially, involve Eni or its direct or indirect subsidiaries both in Italy and abroad, or on the part of its Directors and/or employees;
(x) reports on developments regarding disputes considered to be of particular interest, particularly as regards the appropriateness of documentation supporting assessments of the potential liabilities that may be connected with these proceedings and the text of the respective disclosures to the market in the context of the annual and half-yearly financial report;
(xi) the Reports of the Officer in charge of preparing financial reports on the administrative and accounting structure of Eni as of December 31, 2008 and as of June 30, 2009, verifying the appropriateness of the powers and resources made available to the Chief Financial Officer as the Officer in charge of preparing financial reports. In this respect, the examination is focused on the main organizational changes that took place at the end of the second half of 2009 in the CFO area, particularly as regards administrative activities;
(xii) the Reports of the relevant Officer in charge of internal controls contained in the financial statement on December 31, 2008 and on June 30, 2009, and the update on November 30, 2009;
(xiii) the essential aspects of the Statutory and consolidated financial statements as of December 31, 2009, holding meetings with the most senior member of Eni’s administrative functions, its main subsidiaries and the companies subject to so-called unbundling rules for this purpose, as well as the Chairmen or other members of the Board of Statutory Auditors of each company and the partners of the Auditing Company instructed to express an opinion on the individual financial statements; the representation in the financial statements of specific transactions and/or shareholdings; the draft consolidated half-year financial report as of June 30, 2009, with particular reference to the application of the IAS 36 international accounting standard to the assets of Eni’s main areas of business; the reports of the audit firm on the Annual Financial Report for 2008 and the Half-Year Financial Report for 2009;
(xiv) the main aspects of the Annual Report on Form 20-F 2008 and the new developments associated with application of the International Financial Reporting Interpretation Committee (IFRIC) 12, the statement on the implementation of SOA activities and update on the 2009 Fraud Prevention Program;
(xv) the draft of the Report on Operations of the Directors pursuant to Article 2433-bis of the Italian Civil Code and relative to the interim dividends for the year 2009;
(xvi) the chapter on the Internal Control System to be inserted within the Corporate Governance Report of the 2008 financial statements;(xvii) the report on the reports presented by the audit firms on the 2008 Financial Statements, the auditing approach and strategy used in 2008 and 2009 and the audit firm’s communication on the outcome of the auditing activities pertaining to the internal controls that oversee the process of drawing up Eni’s consolidated financial statements for 2008 in accordance with section 404 of the Sarbanes-Oxley Act;
(xviii) the report on the tender launched in the second half of 2009 to assign the task of auditing the financial statements and internal control system of the Eni group, in accordance with the Sarbanes-Oxley Act, for the nine-year period 2010-2018;
(xix) the organization and control model adopted by Eni for the purpose of ensuring fulfillment of the requirements of AEEG VIS Resolution No. 109/2008 of December 11, 2009 regarding the ban on passing on the charge imposed by Article 81 of Decree Law No. 112 of June 25, 2008⁴¹ ("Consumer Prices Control Model") in its prices;
(xx) the main aspects of the company’s organizational model regarding Health, Safety and the Environment;
(xxi) updating of the Eni Guidelines pertaining to the management and control of financial risks;
(xxii) the results of the "Unbundling Implementation Program" launched in 2007, with particular reference to the organizational activities carried out and the formalities required to comply with relevant national and European regulations;
(xxiii) the main features of Eni’s current regulatory system and the state of progress of improvements implemented by the company in mid-2009 to rationalize the management architecture and method, with a view to simplifying it and making it easier to use, while maintaining its effectiveness;
(xxiv) the main activities carried out by the working group on "Gas Metering Systems";
(xxv) the main aspects of Eni’s Security activities, with particular reference to the organization, procedures and operational costs of the dedicated company structure;

(41) Turned into Law No. 133 of August 6, 2008.

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(xxvi) the periodic Report on the disciplinary actions taken against illegal conduct on the part of employees drawn up by the relevant sections of the Human Resources and Organization departments in accordance with the company’s regulations;
(xxvii) the main features of the ICT operation processes and main initiatives currently under way to strengthen the security of information systems and prevent computer crime and illegal data processing under the terms of Legislative Decree 231/2001. Compensation Committee
Established by the Board of Directors in 1996, this committee advises the Board regarding the remuneration payable to Directors with proxies and to the members of the committees of Directors set up by the Board and, on instructions from the CEO, regarding: (i) Annual and long-term incentive plans; (ii) general criteria for the remuneration of executives with strategic responsibilities; (iii) objectives and results of the Performance and Incentive Plans.
During 2009, the Compensation Committee met 13 times, with a 96% attendance rate, and in particular it made proposals regarding: (i) Eni’s 2008 results and 2009 objectives for the purposes of the Annual and Long-Term Incentive Plans; (ii) the variable remuneration of the Chairman, CEO and Directors based on the results achieved in 2008; (iii) the criteria of the remuneration policy for executives with strategic responsibilities; (iv) establishment of the 2009 Long-Term Monetary Incentive Plan for the CEO, to replace and compensate for the Eni Stock Option Plan; (v) establishment of the 2010 Long-Term Incentive Plan, to replace the Stock Option Plan, for critical managerial resources; (vi) establishment of the 2009-2011 Deferred Monetary Incentive Plan for managerial resources; (vii) 2009 implementation of the Deferred Monetary Incentive Plan and its assignment to the CEO.
The composition, appointment and operating methods, tasks, powers and resources of the Committee are governed by an appropriate regulation approved by the Board of Directors⁴². Oil-Gas Energy Committee
The Oil-Gas Energy Committee (OGEC) was established by the Board of Directors in order to monitor trends and scenarios in the international energy markets and to analyze the competitive dynamics of these markets. OGEC has advisory and consulting functions with respect to the Board of Directors, particularly in relation to drafting of the Group’s Strategic Plans and verifying the consistency of operational policies adopted in the multi-year plans.
The OGEC met 10 times in 2009 with an 80% attendance rate on the part of its five member Directors. The meetings were also often attended by the Chairman and other Directors.
The Committee’s first meetings of the year were aimed at monitoring the effects of the economic and financial crisis on the national and international energy market, in order to allow the Board of Directors to assess the potential impacts on Eni and take appropriate and prompt countermeasures.
The OGEC spent a considerable amount of time examining the scenario of oil and natural gas prices, which is important for strategic corporate planning and the assessment of investments. The committee’s analysis of oil price formation mechanisms and the respective financial markets were particularly important.
During the year, the OGEC began to reflect on the fundamental challenges of the Strategic Master Plan, which are likely to have a very significant impact on market developments and therefore on Eni’s business. For this purpose, two meetings were dedicated to the evolution of the gas market in Europe, which is characterized by great uncertainty about supply and demand.
The composition, appointment and operating methods, tasks, powers and resources of the Committee are governed by an appropriate regulation approved by the Board of Directors⁴³.
Chief Operating Officers
of the Divisions In accordance with Article 24 of the By-laws, the Board of Directors can appoint one or more Chief Operating Officers⁴⁴, establishing their powers, on a proposal from the CEO, in agreement with the Chairman, subject to their fulfillment of the integrity requirements imposed by the law being verified. The Board periodically assesses the integrity of the Chief Operating Officers on the basis of statements made by the Managers themselves. Any failure to fulfill the requirements leads to dismissal from their post.
The Chief Operating Officers are also required to respect the instructions of the Board of Directors

(42)	http://www.eni.com/en_IT/governance/committees/committees.shtml
(43)	http://www.eni.com/en_IT/governance/committees/committees.shtml
(44)	For further details, see the section of the website that also contains the company’s organizational chart http://www.eni.com/en_IT/company/organisation-chart/organisation-chart.shtml

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regarding the number of posts they may hold, in accordance with the rules applicable to the CEO.
The Board of Directors has appointed three Chief Operating Officers responsible for Eni’s three operating divisions:
- Claudio Descalzi, Chief Operating Officer, Exploration & Production Division;
- Domenico Dispenza, Chief Operating Officer, Gas & Power Division;
- Angelo Caridi, Chief Operating Officer, Refining & Marketing Division.
At its meeting on February 10, 2010, the Board of Directors, based on the statements made, verified the fulfillment of the integrity requirements and also verified that the Chief Operating Officers complied with the rules on the maximum number of posts they may hold.
Board of Statutory Auditors Responsibilities
Pursuant to the Consolidated Law on Finance, the Board of Statutory Auditors oversees the following: (i) the compliance with the law and the By-laws; (ii) the observance of the principles for correct administration, the suitability of the company’s organizational structure, within each area of competence, the suitability of the internal control system and of the administrative-accounting system, as well as the accurate recording by the latter of the company’s operations; (iii) the methods for complying with corporate governance regulations set forth in the Code of Borsa Italiana to which the company adheres; (iv) the adequacy of the provisions imposed on the subsidiaries by the company, in order to guarantee full compliance with legal reporting requirements.
Pursuant to the Consolidated Law on Finance, the Board of Statutory Auditors submits a documented proposal to the Shareholders’ Meeting concerning the granting of auditing responsibilities as well as compensation for the audit firm. In accordance with Eni’s Code, the Board also monitors the independence of the audit firm, its compliance with all applicable regulatory provisions as well as the nature and size of non-auditing services provided to the Eni’s Group either directly or through companies within its network. The outcomes of this monitoring activity are included in the Report which shall be prepared pursuant to Article 153 of the Consolidated Law on Finance, and attached to the documentation accompanying the financial statements. On March 22, 2005, the Board of Directors, by virtue of the rights granted by the Stock Exchange Commission (SEC) to foreign issuers listed on the regulated US markets, has identified the Board of Statutory Auditors as the body that, since June 1, 2005, has been fulfilling, within the limits set forth by Italian laws, the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and by SEC regulations. On June 15, 2005, the Board of Statutory Auditors has approved the regulations concerning the fulfillment of the responsibilities assigned pursuant to the aforementioned U.S. regulations⁴⁵, the text of which is available on Eni’s website⁴⁶. Composition and appointments
In compliance with the provisions of the Consolidated Law on Finance, the Board of Statutory Auditors is composed of a minimum of three effective Statutory Auditors and two alternate Auditors.
Eni’s By-laws provide for the Board of Statutory Auditors to be composed of five Statutory Auditors and two alternates, appointed by the Shareholders’ Meeting for a period of three years and re-electable at the end of their term.
Similarly to the Board of Directors and consistent with the applicable provisions, the By-laws provide for the auditors to be appointed by proportional representation (so-called "voto di lista") where the candidates are listed according to a progressive numbering; two Statutory Auditors and one alternate Auditor are selected from among the candidates of minority shareholders.
More specifically, the shareholders who represent, on their own or jointly with others, at least 1% of the share capital have the right to submit a list. Each shareholder may submit, or contribute to the submission of, and vote for, a single list. The subjects that control it, the companies controlled by them and those that are jointly controlled are neither allowed to submit, nor contribute to the submission of, other lists or to vote for them, not even through a third party or trust companies.
Eni applies special provisions, concerning the methods and the timeline for submitting and filing the lists, as set forth in Law No. 474/1994, that are partially different from those contained in the Consob Regulations on Issuers. However, in order to guarantee the utmost transparency of its election process, Eni has adopted the regulations issued by Consob and not included in the aforementioned special provisions by voluntarily applying and expressly providing for them in the By-laws (Article 28).
The lists must be accompanied by the following:

(45)	These regulations were amended on March 30, 2007 in order to include the new provisions introduced by Legislative Decree 303/2006 to Article 159, paragraph 1 of the Consolidated Law on Finance, and by Eni’s Code, as well as to make the necessary adjustments based on the organizational changes that have occurred since June 15, 2005 when the original regulations were approved.
(46)	At the following address: http://www.eni.com/en_IT/governance/board-of-Statutory-auditors/board-of-Statutory-auditors.shtml

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information on the shareholder or shareholders who are submitting the list; a declaration, from each candidate, stating compliance with the legal independence, integrity and professional requirements; their personal and professional curricula.
The lists shall be filed with the registered office at least ten days prior to the date of the first call of the Shareholders’ Meeting and published in three Italian daily newspapers, two of them financial, with national circulation. The lists are also forwarded to the market management company and published on the company’s website.
The appointment procedure shall adopt the methods already described in the Board of Directors section.
The procedure of proportional representation (voto di lista) only applies in the event of the entire Board of Statutory Auditors being replaced. In the event of a replacement of an Auditor from the list that has received the majority of votes, the alternate Auditor from the same list fills the vacant position; in the event of a replacement of an Auditor from other lists, the alternate Auditor from those lists fills the vacant position.
Pursuant to Article 28.2 of the By-laws, in compliance with the provisions of the Consolidated Law on Finance, the Shareholders’ Meeting appoints as Chairman of the Board of Statutory Auditors one of the elected candidates from a list that did not receive the majority of votes.
On June 10, 2008, the Shareholders’ Meeting has appointed the following Auditors for a period of three years and in any case until the date when the Shareholders’ Meeting is convened to approve the 2010 financial statements: Ugo Marinelli, Chairman, Roberto Ferranti, Luigi Mandolesi, Tiziano Onesti and Giorgio Silva, effective Statutory Auditors, Francesco Bilotti and Pietro Alberico Mazzola, alternate Auditors. The Shareholders’ Meeting has also determined the pre-tax annual compensation for the Chairman of the Board of Statutory Auditors and of each Statutory Auditor, in the respective amounts of euro 115,000 and euro 80,000, in addition to reimbursement for any expenses incurred while performing auditing duties.
Roberto Ferranti, Luigi Mandolesi, Tiziano Onesti and Francesco Bilotti were elected from the list submitted by the Ministry of the Economy and Finances as holder of 20.30% of the share capital.
Ugo Marinelli, Giorgio Silva and Pietro Alberico Mazzola were elected from the list submitted by the institutional investors, holders of 1.10% of the share capital.
Personal and professional information on the Statutory Auditors is provided here below. UGO MARINELLI
Born in 1941. He holds a degree in Economics and Business from Luiss University, Rome. He lectures Corporate Auditing in the department of Economics "Federico Caffé" at Roma Tre University, Rome. He is also a Professional Accountant and Auditor. He spent a large part of his career (from 1965 to 2000) at Arthur Andersen, where he occupied positions with increasing responsibilities at both the domestic and international levels. Expert in international accounting principles, he was a member of EFRAG - European Financial Reporting Advisory Group – the technical advisory body of the European Commission for the endorsement of international accounting principles issued by IASB - International Accounting Standards Board. As a professional corporate business consultant, he specializes in risk management and internal control. He has held and continues to hold a number of positions in many companies. He is currently Chairman of the Board of Statutory Auditors of A.D. Moving SpA, of Società Energie Rinnovabili SpA and its subsidiary Società Energie Rinnovabili 1 SpA. He is also Chairman of Auditors of Civita and a member of the Board of Directors of Fingold SpA. Since June 2008, he has been Statutory Auditor and Chairman of the Board of Statutory Auditors of Eni. ROBERTO FERRANTI
Born in 1947. He holds a degree in Economics and Business from "La Sapienza" University, Rome. He is a Professional Auditor. In 1987, he was appointed Director of Division VI of the General Inspectorate for Budget Policies – General Accounting Office – and in 1992, Director of Division II of the General Inspectorate for Budget Policies. In 1994, he took over as interim head of the Public Finance office at the General Inspectorate for Budget Policies and, since 1997, he has been serving as Director of the Public Finance office. He has participated in workgroups in charge of drafting sections of the General Report on the Italian Economy, and of auditing the Treasury statements of accounts. He has held teaching positions at the Italian General Accounting office. He was appointed Chairman of the Board of Statutory Auditors of Equitalia Piacenza SpA and of Equitalia Spezia SpA, and Auditor on the Board of Statutory Auditors of SIMEST SpA. He currently holds the following positions: Chairman of the Board of Auditors of Agenzia Nazionale Sicurezza Volo; member of the Board of Auditors of Federazione Italiana Nuoto; Chairman of the Board of Auditors of Registro Italiano Navale; member of the Board of Directors of Equitalia Cerit SpA di Firenze. Since July 2009, he has been holding the position of Chief Inspector General at the General Inspectorate for Accounting and Public Finance. He has been a Statutory Auditor of Eni since 2008.

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LUIGI MANDOLESI
Born in 1943. After graduating in Economics and Business from Università La Sapienza di Roma, he took a position as a Certified Public Accountant and Accounting Specialist in 1966 and as a Certified Auditor in 1995. He was appointed Chairman of the Order of Accountants and Auditors of Rome, Rieti and Velletri and also held the position of Vice Chairman of the Order of Certified Public Accountants and Accounting Specialists of Rome, Rieti, Tivoli and Velletri. He is partner in the firm "Studio Commercialisti Associati Luigi e Massimo Mandolesi". He is Chairman of the Board of Auditors of Procter & Gamble Holding Srl, Finamca, Impreme, Albergo Centrale, Edev Italia and Edf en Italia; he is a Statutory Auditor of Altec, Pietro Mezzaroma e Figli, Larimart and Fondazione Luca Pacioli, and he is a member of the Board of Directors of Villa Margherita and Finconcordia. He has been a Statutory Auditor of Eni since 2008. TIZIANO ONESTI
Born in 1960. He is a Certified Public Accountant and Certified Auditor. He holds a teaching position in Business Economics at Università degli Studi di Roma Tre and he is also a professor of General and Applied Accountancy at Università LUISS "Guido Carli" in Rome. He is the author of several publications on accounting and business economics and carries out, on an on-going basis, research and advance education activities. He is currently the scientific coordinator of the master degree program in Public Administration (MIFAP) at Università degli Studi di Foggia, and is a member of the scientific and editorial committees for several prestigious national journals. He is a corporate consultant to a number of premier Italian and multinational companies, specializing in the evaluation of companies and of their branches, in extraordinary transactions, in civil balance sheets and IAS/IFRS; he also carries out, within the areas of his competence, technical advisory activities, upon appointments by the parties or by the court in civil or penal proceedings. He has held and still holds positions as a member of Boards of Directors, as Statutory Auditor, as external Auditor and liquidator. He is Chairman of the Board of Auditors of AGI SpA, NewCo Rai International SpA; PM&Partners SpA SGR, Servizi Aerei SpA, as well as Chairman of the Board of Auditors of Agenzia Autonoma per la gestione dell’Albo dei Segretari Comunali e Provinciali. He is also a Statutory Auditor of Euler Hermes Siac SpA and liquidator of American Express Company SpA. He is an independent advisor of Gruppo Editoriale L’Espresso SpA and of Fondo Pensione per il Personale della Banca di Roma. He has been a Statutory Auditor of Eni since 2008. GIORGIO SILVA
Born in 1945, he holds a degree in Economics and Business from Università Cattolica del Sacro Cuore in Milano; he has been registered in the Register of Certified Public Accountants of Busto Arsizio since July 4, 1975 and in the Register of Varese since May 3, 1989. He has been a Chartered Accountant since 1981 and a Certified Auditor since 1995 (Ministerial Decree 12/04/1995 published in Gazzetta Ufficiale n. 31 bis of 21/4/1955). He held executive administrative positions in primary industrial companies from 1965 to 1973. He assumed an executive role in the tax section of the audit firm Peat Marwick & Mitchell (currently KPMG) in Milan from 1973 to 1976. In 1977, he joined Studio legale Tributario L. Biscozzi - A. Fantozzi, currently Studio Legale e Tributario Biscozzi Nobili, of which he is a founding partner. He held positions of Board Director in listed companies such as Gemina SpA, from 1996 to May 3, 1999; of Chairman of the Board of Auditors in Impregilo SpA from 1999 to May 2, 2005, and in ATC Trevisan Cometal SpA until May 7, 2008. The positions he currently holds are: Chairman of the Board of Auditors of Kedrios SpA, TSP - Tecnologie e Servizi per il Pubblico Srl; Statutory Auditor of the listed RCS Mediagroup SpA, Statutory Auditor of: Alitalia Compagnia Aerea Italiana SpA, CAI Second SpA, Air One SpA, Air One Cityliner SpA, Air One Technic SpA, SIA - SSB SpA, Hewlett Packard Italiana Srl, Bolton Alimentari SpA (he also holds the position as Alternate Auditor in Autogrill SpA, CAI First SpA, Nuova Sidap Srl; Auditor in Fondazione Corriere della Sera; Auditor in Fondazione Candido Cannavò per lo sport, and Auditor for the Provincia di Varese). He is a speaker at conventions and the author of numerous articles and publications on the taxation system. He is a member of the Eni Watch Structure overseeing compliance with Legislative Decree 631/2001 of RCS Mediagroup SpA and Luxottica SpA. He has been a Statutory Auditor of Eni since May 2005. The personal and professional résumés of the Statutory Auditors are also available on Eni’s Website, in the Corporate Governance section. Independence, integrity and professional requirements, causes for ineligibility, incompatibility and dismissal
As stated in the Eni’s Code, the Statutory Auditors act with autonomy and independence also towards the shareholders who have appointed them.
Pursuant to the Consolidated Law on Finance, the Statutory Auditors must meet specific independence requirements, as well as professional and integrity

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requirements, as set forth in the regulations issued by the Ministry of Justice and the Ministry of Economy and Finance.
As for the professional requirements, Article 28 of the By-laws states that, as set forth in the aforementioned ministerial regulatory provisions, the requirements may be met also through a professional or teaching experience (of at least three years) in the business law, business economics and finance disciplines or through the exercise (for at least three years) of executive functions in the engineering end geology fields.
The Auditors in office must also be registered in the Registry of Certified Auditors.
The Statutory Auditors have stated for the first time, on the occasion of their appointment, to meet the requirements of independence, integrity and professionalism set forth in the applicable regulations, and the Board of Directors has completed the verification assignments conferred to them at the meeting of June 11, 2008. Subsequently and in compliance with the provisions of Eni’s Code, aimed at ensuring that the Statutory Auditors satisfy the prerequisites of independence, also in accordance with the criteria provided for in the same Code for the Board of Directors, the Board of Statutory Auditors has verified, at the meeting of January 21, 2009 and January 18, 2010, that its members meet the afore mentioned requirements (independence, integrity and professionalism) and the Board of Directors, at the meetings of February 26, 2009 and February 11, 2010 respectively, has completed the verification assignment received.
Finally, pursuant to all applicable laws, the subjects who hold the same position in five other issuer companies, are not allowed to assume the role of member of the auditing body in any other issuer company. They may however be assigned other administrative and control functions in Italian companies, within the limits set forth by Consob and in compliance with internal corporate regulations. In compliance with this policy, entered into effect on June 30, 2008, each Statutory auditor has forwarded to Consob, in September 2008, a communication stating compliance with the aforementioned restrictions. In July 2009, the Statutory Auditors have submitted to Consob their annual report on the number of offices held and on the ranking associated with such offices. Meetings attendance
The Statutory Auditors and the Directors are simultaneously provided with documentation on the items of the agenda to be discussed at the Board of Directors meeting, and the Board of Directors and the CEO shall report, at least every quarter or in any case, at the time of the Board of Directors meetings, on the activities performed and on the most relevant economic, financial activities and operations carried out by the company and by its subsidiaries, pursuant to Article 23.3 of the By-laws.
In compliance with the specifications of the Eni’s Code, the Statutory Auditors must inform the Board of Directors and the other Auditors of any interest they may retain on their own or on behalf of third parties with respect to specific transactions of the company. Corporate operations in which the Statutory Auditors retain an interest, or of which they are the related third parties, are regulated by specific Guidelines that were approved on February 12, 2009 by the Board of Directors following consultation with the Internal Control Committee.
The meetings of the Board of Statutory Auditors may be held by video or teleconference.
In 2008, the Board of Statutory Auditors met 26 times. The average duration of the meetings was approximately 3 hours and 48 minutes. In 2009, the average attendance at the meetings of the Board of Statutory Auditors was 91% of the members whereas the average attendance at the meetings of the Board of Directors was 95% of the members.
The tables attached to this report show the attendance of each Auditor at the meetings of the Board of Statutory Auditors and of the Board of Directors.
Internal Control System⁴⁷ The internal control system is a set of rules, procedures and organizational structures aimed at creating healthy and sound company management that is consistent with established goals, by means of an adequate process for the identification, measurement, management and monitoring of the main risks. An effective internal control system contributes towards guaranteeing the protection of the company’s assets as well as efficiency and efficacy of business transactions, reliability of financial reporting and compliance with laws and regulations.

(47) Information provided pursuant to Article 123-bis, second paragraph, letter b), of the Consolidated Law on Finance.

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The structure of the internal control system, is a part of the organizational and management model of the company and involves, in different roles, administrative bodies, watch structures auditing bodies⁴⁸, management and all personnel, in compliance with the principles of the Code of Borsa italiana and the framework of reference, "COSO Report"⁴⁹. Each specific structuring of this system is integrated with the provisions of the Code of Ethics which provides for the following as fundamental values: the formal and substantive legitimacy of the behaviors of members of corporate bodies and of employees at any organizational level; accounting transparency; and the promotion of a corporate culture based on internal controls.
Eni is aware that the investors rely on the commitment of the corporate bodies, management and employees to maintain full compliance with the rules set forth in the corporate internal control system. Within this scope, Eni manages, by means of a set of internal regulations and in compliance with the provisions set forth in the Sarbanes-Oxley Act, the receipt – through easily accessible communication channels – the analysis and the handling of the reports of issues, even in confidential or anonymous form (whistle blowing), that are received by Eni and its subsidiaries and related to internal control, financial reporting, company administrative responsibility, frauds or other types of concerns⁵⁰.
According to Eni, the so-called "culture of risk and related control" contributes to characterize and affect the management’s aptitude and choices in pursuing company objectives and reporting the outcomes. Eni is consistently committed to promote the development and pervasiveness by the company’s employees of an awareness regarding internal control issues.
For the purposes of ensuring an effective and sound management of corporate operations, in compliance with pre-set strategies and objectives, Eni supports a risk prevention approach and focuses its choices and management activities on the reduction of the probability of the occurrence of negative events and their potential impact. To this end, Eni adopts strategies of risk management, depending on their nature and type such as mainly financial and industrial risks, compliance/regulatory risks, as well as other strategic and operational risks, such as country risks in oil & gas activities, and other risks related to exploration for and production of hydrocarbon. The methods by which management identifies, assesses, handles and monitors the specific risks associated with the company operations, are regulated by internal guidelines, rules, procedures and organizational provisions within the company’s regulatory system, which being risk prevention-based, contribute to their containment. With specific regard to industrial⁵¹ and financial risks, special control measures have been set forth and special regulations have been issued or are being issued within the CEO‘s area of competence, which will be periodically updated in order to guarantee an effective and transversal management of these types of risks. In addition, the development of risk assessment programs in specific areas contributes to further developing the sensibility of management with respect to risk management and contributes to the improvement and efficacy of decision-making processes.
In 2009, in line with the evolution of the company organizational model and consistent with the company’s mission and values, Eni has undertaken initiatives to streamline and integrate its own regulatory system by simplifying it and easing its use for the purpose of higher overall efficacy. Similar initiatives were applied also to the ICT processes and are currently undergoing an assessment in terms of streamlining and integrating the risk management system.
The internal control system is subject, over time, to evaluation and updates in order to steadily guarantee its capacity to preside over the main areas of corporate risks, according to the typical issues of each operating segment and organizational structure, ready to take account of any new law or regulations. The main changes introduced in 2009 are part of a natural evolutionary process aimed at achieving "on-going improvements" of the efficacy and efficiency of the system itself. In particular, in response to the evolution of the applicable legislation, Model 231 was updated to include the types of offences recently added within the application scope of Legislative Decree No. 231 of

(48)	For further information on the supervisory activities performed by the Board of Statutory Auditors in regard to the adequacy of the internal control system and of the administrative-accounting system, also as Audit Committee under US laws, see the paragraph "Board of Statutory Auditors - Responsibilities" above and "Officer in charge of preparing financial reports and internal control system on financial reporting".
(49)	See CoSO - Committee of Sponsoring Organizations of the Treadway Commission (1992), Internal Control. Integrated Framework. The adoption by Eni of the CoSO Report is mentioned in several documents, among which the most relevant are: Eni’s organizational, management and control Model pursuant to Legislative Decree No. 231 of 2001 approved by the Board of Directors in the meetings of December 15, 2003, of January 28, 2004 and March 14, 2008; Guidelines on internal control system over corporate reporting – Rules and Methods – II Release approved by the Board of Directors on June 20, 2007, as well as all referenced best practices set forth by the Internal Audit.
(50)	Eni guarantees full confidentiality of the identity of the people who reports issues of concern in good faith, and communicates the results of the assessment carried out on report cases to the top management of the company as well as to the appropriate control and supervisory bodies.
(51)	The term "Industrial risks" refers specifically to risks that occurs from events which may cause damage to the company's asset (property) and/or to third parties, within the scope of their activities (causality), including damages suffered by the people involved in the production process.

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2001, as detailed hereinafter, and a specific Control Model was adopted in order to prevent the application, to consumer prices, of the charge associated with the income surtax introduced by Legislative Decree No. 112 of 2008 (Consumer Prices Control Model). Board of Directors
The Board of Directors retains a central role in internal control system by defining the basic principles to be applied to the organizational, administrative and accounting structure of the Company, of the main subsidiaries and of the Group; in this context, it defines, examined proposals submitted by the Internal Control Committee, the guidelines for the company’s internal control system aimed at identifying, measuring, managing and monitoring the main risks to which the company and its subsidiaries are exposed. In the definition of these guidelines, the Board applies sector regulations and takes into adequate consideration the referenced models and the best national and international practices.
Finally, the Board assesses annually, with the support of the Internal Control Committee, the adequacy, efficacy and efficiency of the overall internal control system with respect to Eni’s characteristics. In its meeting of March 11, 2010, the Board examined the Internal Control Committee’s 2009 Report (updated on March 10, 2010) as well as the observations included therein on the status of Eni’s internal control system and, at the conclusion of this review, the Board, also in consideration of the initiatives underway, assessed the overall internal control system adequate, effective and efficiently operating. Internal Control Committee
The Internal Control Committee, established within Eni in 1994, is entrusted with providing consulting and advisory services to the Board of Directors as regards the internal control system. It is exclusively made up of non-executive, independent Directors provided with the professional qualification required by the responsibilities entrusted to them⁵², and reports to the Board of Directors both on its activities and on the adequacy of the internal control system, at least once every six months, at the time of approval of the annual and half-year financial statements. The periodical reports, to be submitted to the Board of Directors, are prepared by the Committee and must keep into consideration the content of the periodical reports prepared by the Officer in charge of preparing financial reports, the Officer in charge of Internal Control and the Eni Watch Structure and, in general, must be based on the evidence acquired while performing its activities, which are:
- examining and assessing – in conjunction with the Officer in charge of preparing financial reports and the Audit firm – the correct utilization of accounting principles and their homogeneity for the drafting of the annual and half-year financial statements before approval by the Board of Directors;
- assisting the Board in defining the guidelines for the internal control system;
- providing an evaluation – upon request by the CEO – on specific aspects concerning the process used to identify the main risks related to the Company as well as on the planning, implementation and management of the internal control system;
- overseeing the activities of Internal Audit and of the Officer in charge of Internal Control; furthermore within this area of responsibility, the Committee examines: the proposal of the Audit Plan and its potential amendments during the financial year; the annual budget of the Internal Audit Department; the periodical reports and performance indicators on the activities of the Internal Audit Department;
- examining and assessing the following: (i) the outcomes of internal audit reports as well as any evidence on related monitoring activities on improvement actions on control system, planned after the audits are performed; (ii) evidence resulting from the periodical reports on the outcomes of the monitoring activities conducted on the internal control system over financial reporting, on its adequacy and actual application, as well as the adequacy of the powers and means assigned to the Officer in charge of preparing financial reports; (iii) communications and information received from the Board of Statutory Auditors and its members regarding the internal control system, also in reference to the outcomes of preliminary inquiries conducted by the Internal Audit department following reports received also in anonymous form (whistle blowing); (iv) evidence emerging from the reports and management letters submitted by the Audit Firm⁵³; (v) periodical reports issued by Eni Watch Structure, also in its capacity as Guarantor of the Code of Ethics; (vi) evidence emerging from the periodical reports submitted by the Officer in charge of preparing financial reports and by the Officer in Charge of internal control; (vii) information on the internal control system as it relates to the company’s

(52) Unlike to the Code of Borsa Italiana, the Eni Code requires that at least two (and not only one) Committee members have adequate expertise in accounting and financial matters, to be assessed by the Board of Directors at the time of their appointment.

(53) Eni entrusted to the Board of Statutory Auditors, as set forth in the Code of Borsa Italiana, the role of Audit Committee under the SOA and therefore the task of reviewing the proposals submitted by Audit Firm in order to obtain the auditing mandate and monitor the efficacy of the accounting auditing process.

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structure, also through periodical meetings with management, as well as enquiries and reviews carried out by third;
- performing other specific activities aimed at formulating analyses and opinions on topics falling under its competence and based on the Board’s request for details, and in particular, providing an opinion on the rules concerning the transparency and substantial and procedural correctness of operations carried out with related third parties, as well as transactions where a Director of the Board retains a personal interest or an interest on behalf of third parties, and finally carrying out any additional task assigned within this scope, including the review and evaluation of specific types of transactions.
The activities performed by the Committee in 2009 are described in the dedicated paragraph above. Chief Executive Officer
The Chief Executive Officer (CEO) is entrusted by the Board of Directors with overseeing the functioning of the internal control system. To this end, he identifies the main company risks and, in implementing the guidelines on to the internal control system approved by the Board, provides to their design, implementation and management. The CEO is also entrusted with monitoring the overall adequacy, efficiency and efficacy of the internal control system and ensuring that it is adjusted to Company’s operations and applicable laws. With reference to the internal control system applied to financial reporting, these tasks are performed in compliance with the tasks assigned, by law, to the Officer in charge of preparing financial reports⁵⁴. Eni’s people - Management
As set forth in the Code of Ethics, the responsibility to implement an effective internal control system applies to all levels of Eni’s organizational structure; therefore all Eni’s people, according to their function and responsibilities are committed to define and actively participate in the correct functioning of the internal control system. The CEO and/or the Chief Operating Officers of Eni’s Divisions, by exercising the powers entrusted to them by the Board of Directors, assigned to the managers responsible of their respective areas task, responsibilities and powers for ensuring an effective and efficient internal control in the performance of their respective activities and in the pursuit of related business objectives. Officer in charge of internal control and internal audit A primary role in monitoring and assessment process of the internal control system is performed by the Officer in charge of Internal Control, a position which, in Eni, is held by the Senior Executive Vice President of Internal Audit (Rita Marino), given the substantial identity of operational areas and the consequent strong link between the two roles. Officer in charge of Internal Control
The Officer in charge of Internal Control is entrusted with the main task of (i) verifying that the internal control system is always adequate, fully operational and correctly functioning and (ii) providing evaluation on its adequacy.
The Officer in charge of Internal Control is appointed by the Board of Directors, on proposal of the CEO, in agreement with the Chairman of the Board of Directors, and after opinion of the Internal Control Committee⁵⁵. The Board determines the compensation of the Officer in charge of Internal Control, in compliance with corporate policies and following consultation with the Internal Control Committee.
The Officer in charge of Internal Control is not responsible for any specific operational area, has direct access to information which may be useful for carrying out her tasks, is provided with the necessary tools for fulfilling her tasks, and reports, through the Internal Control Committee, to the Board of Directors, the Board of Statutory Auditors and the CEO by means of periodical reports.
On March 4, 2010, the Officer in charge of Internal Control has released its Annual Report on the internal control system (for the period between January 1 and December 31, 2009, updated as at the release date) and has also provided an evaluation on its adequacy based on the outcomes of the monitoring activities carried out in the relevant period by the Internal Audit Department, by the Officer in charge of Internal Control of the listed subsidiaries and by the Internal Audit Departments of the subsidiaries that are under the supervision of the Bank of Italy. Internal Audit Department
The Internal Audit Department is entrusted with the task of providing the following to the CEO and, through the Internal Control Committee, to the Board of Directors and to the Board of Statutory

(54) To this end, please see details in the following paragraph describing the responsibilities assigned to the Officer in charge of preparing financial reports.

(55) The Officer in charge of internal control was appointed for the first time in the meeting of March 16, 2007 and later reconfirmed by a resolution issued on October 30, 2008.

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Auditors in its capacity as "Audit Committee" in accordance with US law: audits, analyses, assessments and recommendations pertaining to the design and functioning of, as well as compliance with, the internal control system of the company and of the Group, in order to promote its efficiency, and efficacy. The Internal Audit Department performs the activities, within its own area of responsibility, as regards Eni SpA and the subsidiaries in which ENI retains majority voting rights, with the exception of those with listed shares or those under the supervision of the Bank of Italy. Those subsidiaries have their own Internal Audit Departments.
The Senior Executive Vice President of Internal Audit, reports to the CEO who is entrusted with overseeing the functioning of the internal control system; the Internal Control Committee oversees the activities carried out by the Internal Audit which reports also to the Board of Statutory Auditors, in its capacity as "Audit Committee", pursuant to the laws of the Unites States. The methods for appointing/revoking the Senior Executive Vice President of Internal Audit are compliant with the provisions set forth in the Code of Ethics, as regards the Internal Control Manager, given the synergy between the two roles. The Internal Control Committee evaluates annually the upholding of the characteristics of honorability, competence and expertise of the Senior Executive Vice President of Internal Audit, as well as the absence of any causes of incompatibility, and provides the Board of Directors with its opinion on the compensation to be paid to the Senior Executive Vice President of Internal Audit upon proposal by the CEO in accordance with corporate policies. Tasks, powers and means of the Internal Audit Department and information flows
Objectives, areas of intervention and functioning methods pertaining to the Internal Audit Department are defined in the "Internal Audit Charter", approved by the Board of Directors at the end of 2008 in line with the best practices.
The Internal Audit Department is entrusted with the powers and means adequate for performing its tasks in full operational independence – also in terms of expenditure autonomy, availability of an adequate number of professionally competent resources, and access to information, data, archives and assets held by the company and by its subsidiaries.
According to this organizational model, the Internal Audit Department, by ensuring the preservation of the necessary conditions of independence, as well as of the required professional objectivity, skills and diligence in compliance with the set forth international standards for professional practices and the Code of Ethics, performs the following main activities:
(i) Executes audit activities (operational, financial and compliance audit, with particular attention given to the provisions of Legislative Decree No. 231 of 2001), thus implementing the Annual Audit Plan formulated with a top-down risk based approach and approved by the Board of Directors together with the budget of the resources and, for the relevant aspects as set forth in Legislative Decree No. 231 of 2001, by the Eni Watch Structure.
(ii) Performs unplanned internal audit activities, upon request by the primary stakeholders of the internal control system and/or by the top management.
(iii) Monitors the implementation of corrective actions defined on the basis of audit activities.
(iv) Organizes and oversees the development and management of the information flows set up for receiving the reports, also in anonymous form, of which it keeps an updated archive, and conducts preliminary audits in compliance with applicable corporate procedures.
(v) Performs monitoring activities, as provided for in the 231 Model of Eni SpA. Within this specific area, the Internal Audit Department has started, in 2009, monitoring activities pertaining to HS, which, in compliance with the aforementioned Internal Audit Charter, provide for conducting independent assessments on the auditing, measurement and reporting activities, to be carried out by the competent HSE units.
(vi) Carries out independent monitoring activities performed for financial reporting, according to a plan communicated by the CFO and, starting in 2009, performs also independent monitoring activities for relevant operations in terms of "Consumer Prices Control Model", based on the Plan formulated by the General Manager of each Division.
(vii) Participates in corporate training regarding internal control issues.
The Internal Audit department ensures systematic and periodical reporting (quarterly summary reports and half-year reports) on the outcomes of its activities which are forwarded to the control and supervisory bodies and to upper management in order to enable them to perform their duties, in terms of control and assessment of the internal control system; in addition, it promptly informs the CEO and the control and supervisory bodies about serious deficiencies identified in the internal control system and about any circumstance that may compromise its own prerequisites of independence.

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Officer in charge of preparing financial reports and internal control system applied to financial reporting Officer in charge of preparing financial reports
Pursuant to Article 24 of the By-laws, in compliance with the provisions of Article 154-bis of the Finance Consolidation Act, the Officer in charge of preparing financial reports (Appointed Officer - AO) is appointed by the Board of Directors, upon proposal submitted by the CEO in agreement with the Chairman and upon favorable opinion issued by the Board of Statutory Auditors. The AO must be selected, in accordance with the provisions of the By-laws, from among subjects with at least three years of experience with the following:
(a) administration, control or management activities carried out at companies that are listed in the Italian, in other European Union states and in OECD countries’ regulated markets, and with a share capital of at least euro 2 million, or
(b) auditing activities carried out at the same types of companies listed under letter a), or
(c) professional activities with, or university teaching experience in, financial or accounting disciplines, or
(d) management experience developed at public or private enterprises operating in the financial, accounting or auditing sectors. Tasks, powers and means of the Appointed Officer
In compliance with law provisions, the AO is responsible, within the internal control system, for the financial reporting and to this end, he/she sets forth the administrative and accounting procedures for drafting the periodical accounting documentation and any other financial reporting, certifying – in accordance with the CEO and by means of a report on the financial statements of the year, on the half-year summary financial statements and on the consolidated financial statements – the adequate and actual application of the Internal Control over the period to which these accounting documents refer. The Board of Directors oversees these activities, pursuant to Article 154-bis, in order to ensure that the AO has the powers and the means necessary to carry out the assigned tasks and that compliance with the aforementioned procedures is maintained. In the meeting of July 30, 2008, the Board of Directors, upon favorable opinion issued by the Board of Statutory Auditors, has appointed to the position of AO Mr. Alessandro Bernini, Eni’s Chief Financial Officer (CFO) and has deemed as being adequate, for the purpose of performing his functions, the conferred expenditure powers, to be exercised independently from or jointly with the CEO, as well as the means at his disposal in terms of organizational structures and administrative, accounting and internal control systems.
In the meeting of March 11, 2010, the Board of Directors has confirmed the adequacy of the "powers and means" at the disposal of the CFO, in his capacity as AO, and has verified compliance of the procedures implemented by the AO with the applicable law. Main characteristics of the risk management and internal control systems applied to the financial reporting process
The internal control system applied to financial reporting is a process aimed at providing a reasonable certainty on the reliability⁵⁶ of the financial reporting itself and on the capacity of the process set up for the preparation of the financial statements to produce financial reports compliant with generally accepted international accounting principles.
The "Guidelines on internal control system over corporate reporting" approved by the Board of Directors on June 20, 2007, define the rules and methods to be adopted in the planning, establishing and maintaining, over time, of the internal control system applied to Eni’s financial reporting, as well as in the assessment process of its efficacy.
These Guidelines have been defined in compliance with the provisions of the aforementioned Article 154-bis of the Consolidated Law on Finance and with the provisions of the US Sarbanes-Oxley Act of 2002 (SOA), to which Eni must adhere as a company whose stocks are listed on the New York Stock Exchange (NYSE), formulated in accordance with the COSO Report ("Internal Control - Integrated Framework" published by the Committee of Sponsoring Organizations of the Treadway Commission).
The Guidelines are applicable to Eni SpA and to the subsidiaries in which Eni holds a direct or indirect interest, in compliance with international accounting principles and in consideration of their relevance in terms of the preparation of financial reporting. All subsidiaries, regardless of their relevance within the internal control system applied to Eni’s financial reporting, refer to these Guidelines in setting up their own control system on financial reporting that better reflects the company’s size and complexity of operation.

(56) Reliability (of the reporting): A reporting that meets the requirements of correctness and compliance with generally accepted accounting principles and includes the characteristics sets forth by the applicable laws and regulations.

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The planning, set up and maintenance of the internal control system applied to financial reporting are guaranteed through: risk assessment, controls identification, controls evaluation and reporting.
The risk assessment process, based on a "top-down" approach, aims at identifying the organizational entities, the processes and the specific activities capable of generating risks of unintentional errors or of frauds, which may significantly affect the financial statements.
In particular, the identification of the organizational entities under the internal control system applied to financial reporting, is based on the contribution, by the various entities, to the figures stated in the consolidated financial statements (assets, financial debt, net proceeds, taxable income) also in consideration of their relevance in terms of processes and specific risks⁵⁷. Within the companies that are relevant to the control system applied to financial reporting, significant processes are subsequently identified upon an analysis of quantitative factors (processes that contribute to determining the financial statement items for amounts over a certain percentage of pre-tax profits) and of qualitative factors (e.g.: complexity in the accounting handling of financial operations; news and/or significant changes in the business conditions). Following identification of all relevant processes and activities, the potential risks are identified. The term "risk" refers to potential events that may compromise the achievement of the control system’s objectives applied to financial reporting (e.g. financial statements). The identified risks are assessed in terms of their potential impact and probability of occurrence, based on qualitative and quantitative parameters and assuming the absence of a control system (inherent assessment). In particular, with reference to fraud risks⁵⁸, a risk assessment was performed based on a specific methodology used in the "Anti-fraud programs and controls" to which the aforementioned Guidelines refer.
In consideration of the relevant companies, of the processes and risks involved, a control system was set up on the basis of two fundamental principles: the application of the control system to all levels of the corporate organizational structure and in accordance with the assigned operating responsibilities, and the controls’ sustainability over time so as to ensure a performance that is integrated and compatible with operational requirements.
The structure of the control system applied to financial reporting provides for controls implemented at the level of entities that operate in a transversal manner with respect to the reference entity (Group/Division/single company), and provides for controls at the process level.
The controls implemented at the entity level are organized in a checklist which, based on the model adopted in the COSO Report, focuses on five components (control environment, risk assessment, control activity, information systems and reporting, monitoring activities). Of particular importance are the control activities related to the scheduling of drafting and disseminating economic-financial operating results ("half-year and financial statement circular" and related timelines); the existence of organizational structures and of a regulatory body aimed at reaching the pre-set objectives as regards financial reporting (these controls provide, for example, for auditing and updating activities carried out through specialized corporate functions, as set forth in the Group’s Regulations, with reference to the group’s financial statements and Accounting Plan); training activities on accounting principles and an internal control system applied to financial reporting; and finally activities related to the reporting system for the management of the consolidation process (Mastro).
The controls at the process level are divided as follows: specific controls intended as a set of manual or automated activities aimed at preventing, identifying and correcting errors or irregularities that may occur in carrying out operational activities; pervasive controls intended as structural elements of the control system applied to financial reporting and aimed at defining the general conditions that would promote a correct execution and control of operational activities (e.g. segregation of incompatible tasks and general controls on information systems).
The "specific controls" consist in special procedures that define both the execution of corporate processes and the so-called "key controls", the absence or non-functioning of which would carry the risk of a relevant error or fraud in the financial statements that may not be detected by other forms of controls.
The controls at the entity and process level are subject to evaluation (monitoring) in order to assess, over time, the effectiveness of their design and their actual functioning. For this purpose, the following activities were provided for: ongoing monitoring – assigned to the management group responsible for the relevant processes/activities – and separate evaluations, assigned to the Internal Audit Department which operates in compliance with a preset plan, formulated by the

(57)	Among the entities under the internal control system, are some companies established and operating in compliance with the laws of countries that are not part of the European Union, to which the regulatory provisions of Article 39 of the Consob Market Regulations apply.
(58)	Fraud: within Internal Control System, each act or intentional omission which generates a deceptive statement.

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CFO/AO, that defines the scope and the objectives of the interventions through agreed upon auditing procedures.
The monitoring activities enable the identification of deficiencies present in the control system applied to financial reporting, which are subject to evaluation in terms of probability and impact on Eni’s financial reporting and, based on their relevance, are qualified as "deficiencies", "significant weak points" or "relevant deficiencies".
The results of these monitoring activities are included in periodical reports on the status of the control system applied to financial reporting, through the use of computerized tools in order to guarantee the tracking of the information collected on the effectiveness of the design and on the actual functioning of the controls. Based on this reporting activity, the CFO/AO prepares a report on the adequacy and actual implementation of the control system applied to financial reporting, which, after approval by the CEO, is submitted to the Board of Directors, following review by the Internal Control Committee and upon approval of the annual and half-year financial statements, in order to enable the execution of the required supervisory functions and of the appropriate evaluations, related to the internal control system applied to financial reporting. This report is also submitted to the Board of Statutory Auditors, in its capacity as Audit Committee in compliance with US regulations.
The CEO/AO is assisted, in his/her activities within ENI, by several other individuals whose tasks and responsibilities are defined in the aforementioned Guidelines. More specifically, control activities involve all levels of Eni’s organizational structure, from business managers to executives to administrative Directors and the CEO. Within this organizational structure, the so-called "risk owner" assumes a particular relevance, as regards the internal control system, as he/she performs ongoing monitoring activities aimed at evaluating the design and effectiveness of specific and pervasive controls, as well as providing information to be used in the reports on monitoring activities and on any identified deficiencies, in order to promptly implement all necessary corrective actions. Eni Watch Structure and Model 231
According to the Italian regulations pertaining to the "administrative liability of legal entities deriving from offences", pursuant to Legislative Decree No. 231 of June 8, 2001 (hereinafter, "Legislative Decree No. 231 of 2001"), associations, including corporations, may be held liable – and therefore charged with the payment of a penalty or placed under injunction, with regard to certain offences that are attempted or committed in Italy or abroad in the interest or for the benefit of the company. The companies may, in any case, adopt organizational, management and control models suitable to the prevention of possible offences.
With regards to this issue, Eni SpA’s Board of Directors – in its meetings of December 15, 2003 and January 28, 2004 – has approved an organizational, managerial and control model pursuant to Legislative Decree No. 231 of 2001 (hereinafter, "Model 231") and has appointed the Eni Watch Structure. The composition of the Eni Watch Structure, initially consisting of only three members, was amended in 2007 with the addition of two external members, one of them appointed by the Chairman of the Eni Watch Structure and selected from among university professors and professionals of proven experience and expertise in economics and business management. The internal members are represented by the Senior Executive Vice President (or managers directly reporting to them) of Legal Affairs, Human Resources and the Internal Audit Departments.
The Eni Watch Structure carries out the following main activities: (i) monitors the efficacy of Model 231 of Eni SpA as well as all related implementation and updating activities; (ii) evaluates the effectiveness of Model 231 and ensures the maintenance over time of its sound and efficient functioning by proposing the necessary updates; (iii) monitors the progress of its application to the subsidiaries and promotes the dissemination and knowledge to the same of the methodologies and tools to be used for the Model’s implementation (iv) approves the annual planning of all Eni SpA’s supervisory activities, coordinates their implementation; and evaluates the results; (v) manages the reporting activities, working for this purpose with the Watch Structure of subsidiaries’ appropriate personnel and supervisory bodies. The synergies between Model 231 and the Code of Ethics, an integral part and underogable principle of Model 231, are evident in the assignment to Eni SpA’s Watch Structure of the functions of Guarantor of the Code of Ethics. Similarly, each subsidiary assigns the functions of Guarantor of the Code of Ethics to its own Watch Structure. The Watch Structure of Eni SpA reports periodically on its activities to the Chairman, to the CEO – who informs the Board of Directors by means of his/her own report on the execution of delegated powers – to the Internal Control Committee and to the Board of Statutory Auditors. These periodical reports are processed according to the evidence acquired while performing its activities.
Following the first approval of Model 231 and its subsequent updates in compliance with legislative developments, in the meeting of March 14, 2008, the

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Board of Directors of Eni SpA, after consultation with the Board of Statutory Auditors, has approved its own update which has been implemented in accordance with corporate organizational changes, new legal requirements⁵⁹, new developments on the part of authorities and case law, issues resulting from the application of the Model (including any knowledge stemming from legal disputes), the practices of Italian and foreign companies with regards to the models, the outcomes of supervisory activity and the results of internal auditing activities.
Model 231 of Eni SpA, a set of principles and the point of reference for subsidiaries, is provided to each subsidiary so that they may adopt and/or update their own models. The subsidiaries listed on the stock exchange and those operating in the gas and electrical sectors, subject to unbundling regulations, adopt their own model and adjust it as necessary, in accordance with their own company characteristics and with the principle of managerial autonomy. The representatives identified, as indicated by Eni, within the corporate bodies of the subsidiaries as well as in consortia and joint ventures, promote the principles and contents of Model 231 within their respective areas of competence. Control provisions (based on general and specific standards) have been set forth in order to regulate corporate activities for the prevention of crimes, pursuant to Legislative Decree No. 231 of 2001. In addition, in compliance with the applicable law, a disciplinary system has been implemented to sanction infringements of Model 231 and failures to comply with corporate procedures. At the end of 2009, Eni has launched some initiatives aimed at streamlining and optimizing the organizational and operational structure of the watch structures of the subsidiaries, and at analyzing the process implemented by the subsidiaries themselves for the adoption of Model 231 while taking into consideration any developments in the regulatory system and in best practices.
The Board of Directors plays a primary role concerning Model 231 since, as mentioned earlier, it has reserved the right to approve it, to establish and appoint the members of the Watch Structure and to receive, through the CEO, periodical reports on its operations. On the other hand, the CEO is responsible for implementing and updating Model 231, pursuant to the powers conferred to him/her by the Model itself. For this purpose, the CEO has set up a multifunctional Team ("Team 231") responsible for drafting/submitting proposals for updates. During 2009, the Team 231 has completed the update of Model 231 to include crimes pertaining to receiving stolen goods, recycling, and unlawful usage of money and properties of illegal origins, computer crimes and unlawful data processing, and will shortly implement new updates by adding new types of presumed crimes introduced by the legislature in 2009 (organized crimes, crimes against industry and commerce, infringements of copyrights, instigation not to make statements or to make false statements to judicial authorities).
In 2009, the rationale and methods to be applied to the planning and implementation of supervisory activities were defined in the areas of workplace safety and health for the prevention of "manslaughter or serious or very serious personal injuries, in violation of workplace safety and health laws", pursuant to the provisions of Legislative Decree No. 231/2001, to the principles and the content of Model 231 and to Eni SpA’s Managing System Model HSE concerning internal assessments and controls. The activities were carried out by a dedicated multifunctional team, under the coordination of the Watch Structure of Eni SpA, which, in accordance with the tasks assigned by Model 231, shall promote, in 2010, the implementation in the subsidiaries of the principles defined for Eni’s supervisory activities pertaining to HS.
For a correct implementation of Model 231, training and/or communication activities based on the type of recipient (including third party and the market) have been planned. A Web Based Training (WBT) on Model 231 has been planned for the year 2010 and will be provided specifically to managers/executives, corporate organizational communication groups and to key officers of Eni.
Model 231 and the Code of Ethics are published on Eni’s web site and are available on the company’s intranet network. Anti-Corruption Policy
Of primary importance is the fight against corruption, which has been approved by Eni’s Board of Directors and subsequently regulated with Anti-Corruption Guidelines and with the first two Auxiliary Anti-Corruption Procedures dealing specifically with joint-venture and intermediary agreements. Other Auxiliary

(59) The current scope of application of Legislative Decree No. 231 of 2001 provides for the following: Offences against public authorities and public faith, (ii) corporate crimes, (iii) crimes associated with the subversion of public order, and financing of terrorism, (iv) offences against the person, (v) market abuse ("abuse of confidential information" and "market manipulation"), (vi) offences against individuals, Law No. 7 of 2006, (vii) transnational crimes, (viii) manslaughter and serious or very serious personal injury committed in violation of industrial accident laws and of the protection of industrial hygiene and health, (ix) crimes related to receiving stolen goods, recycling, and unlawful usage of money and properties of illegal origins, (x) computer crimes and unlawful data processing, (xi) organized crimes, (xii) offences against industry and commerce, (xiii) infringements of copyrights, (xiv) instigation to make false statements to judicial authorities.

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Anti-Corruption Procedures, on specific subject matters, are currently under review. The Anti-Corruption Guidelines and Auxiliary Anti-Corruption Procedures aim at providing a systematic reference framework with anti-corruption regulations and procedures, already implemented by Eni over time, as well as at ensuring full compliance, by Eni and its employees, with the Code of Ethics, with Model 231 and with national and international anti-corruption laws. For this purpose, both the Anti-Corruption Guidelines and the Auxiliary Anti-Corruption Procedures are being adopted by all of Eni’s subsidiaries, both in Italy and abroad, upon resolution issued by the Board of Directors (or by the corresponding body/function, if the governance of the subsidiary does not provide for the establishment of a Board). The internal regulations adopted by Eni, as regards this subject matter, provide for the involvement of Eni’s Board of Directors or of the subsidiary company, in the approval phase of the most significant activities (such as the appointment of intermediaries). In compliance with international market best practices, an anti-corruption unit was also set up, within the Eni SpA’s Legal Affairs Department, with the objective of providing legal advisory services and support, in anti-corruption matters, to Eni’s business units and unlisted subsidiaries.
At the time of the adoption of this policy, a presentation event was held in order to provide Eni’s personnel with information on the company’s new and future initiatives aiming at a continuously more effective fight against, and prevention of corruption. An anti-corruption training program for the company’s employees, currently under development, will be held in the course of the year and will consist of an information session, delivered through e-learning modules with an overview of the anti-corruption topic, and a series of interactive workshops for a more in-depth analysis on specific sub-topics.
Audit firm⁶⁰ The auditing of Eni’s financial statements is entrusted, in accordance with the law, to an audit firm, registered in the Consob special registry and appointed by the Board of Directors, upon a documented proposal submitted by the Board of Statutory Auditors.
In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the audit firm files an Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States, and requires the issue of an assessment on the efficacy of the internal control system, applied to financial reporting, which oversees the preparation of the consolidated financial statements.
For the most part, the subsidiaries’ financial statements are subject to auditing by the same company that audits Eni’s financial statements. In addition and for the purpose of issuing an assessment on the consolidated financial statements, Eni’s audit firm assumes the responsibility for the work performed by other auditing companies as regards those subsidiaries’ financial statements which represent altogether an irrelevant part of the company’s assets and consolidated turnover.
The current audit firm is PricewaterhouseCoopers SpA. Its first mandate of June 1, 2001, was later confirmed for three more years by the Shareholders’ Meeting held on May 28, 2004, and subsequently extended to the 2007-2009 financial years by the Shareholders’ Meeting held on May 24, 2007, pursuant to Legislative Decree No. 303/2006, since the maximum term of nine financial years provided for by the law had yet to be completed. Consequently, at the time of the approval of the financial statements of the 2009 financial year, PricewaterhouseCoopers SpA will have fulfilled its mandate and the Shareholders’ Meeting will appoint another audit firm.
During the course of its operations, the audit firm shall have access to the information and data in both printed and digital form, as well as to the archives and assets of the company and of its subsidiaries.
The single reference framework for the application to Eni’s group of auditing regulations is represented by the Financial Statements Auditing Regulations (Normativa in materia di revisione dei bilanci) adopted by the Board of Directors as of April 3, 2008. These regulations include the new legislative provisions issued in the last few years⁶¹ as well as the provisions issued by the appropriate control authorities (Consob and SEC). The regulations comply with the general framework of principles applied to the following: granting and revocation of the mandate; relations between the Group’s primary and secondary Auditors; independence of the audit firm and reasons for incompatibility; reporting responsibilities and obligations of the audit firm; regulations applied to the reports to be submitted to the company, to Consob and SEC. In order to protect the independent nature of the Auditors, a monitoring system of "non-auditing" tasks has been set up where, in general, the entrusted

(60)	The audit firm, verified the redaction of this Report, renders an opinion according to Article 156, par. 4-bis, lett. d) of the Consolidated Law on Finance on the information provided according to Article 123-bis, par. 1, lett. c), d), f), l) and m), and par. 2, lett. b) of the same law. The audit report is published together with the Annual Financial Report.
(61)	Law No. 262/2005 and Legislative Decree No. 303/2006 which have amended the Consolidated Law on Finance.

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audit firm and the companies of its network, shall not be assigned tasks other than those pertaining to accounting audits, with few exceptions in the case of assignments that are not prohibited by Italian laws or the Sarbanes-Oxley Act. These assignments are approved by the Board of Directors of each company, following consultation with the Board of Statutory Auditors of that same company, and are subsequently authorized by Eni’s Board of Statutory Auditors if such assignments are not included among those provided for in the applicable laws and regulations. Eni’s Board of Statutory Auditors is, in any case, periodically informed of the tasks entrusted to the audit firm by the companies of the Group. The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services provided by Eni audit for and its member firms, with respect to the years indicated:

Principal accountant fees and services	2007	2008	2009
(euro thousand)

Audit fees	26,383	27,962	30,748
Audit-related fees	169	152	276
Tax fees	81	46	51
All other fees	120	1	-
	26,753	28,161	31,075

Court of Auditors The financial management of Eni is subject to control by the Court of Auditors in order to protect public finances. This activity was carried out by the Judge of the Court of Auditors, Lucio Todaro Marescotti, succeeded by Raffaele Squitieri⁶², appointed by resolutions issued on October 28, 2009 by the Council of the Presidency of the Court of Auditors.
The Judge of the Court assists at the meetings of the Board of Directors, of the Board of Statutory Auditors and of the Internal Control Committee.
Directors’ interests and transactions with related third parties While awaiting the issue of the executive provisions of Article 2391-bis of the Italian Civil Code, the Board of Directors – following consultation with the Internal Control Committee – has adopted the Guidelines relative to transactions involving Directors and Auditors’ interests and related third parties in order to ensure compliance with the principles of transparency and of formal and substantial correctness which govern these transactions – in relation to the aforementioned transactions – by the cited provisions and by the Code of Borsa Italiana.
By sharing the general principles set forth by Consob on this matter, Eni has incorporated them into its own procedures while also taking into account the market’s best practices. More specifically, in the adopted Guidelines, the Board: - has identified, on the basis of pre-determined criteria, the most relevant transactions with related third parties that fall under its decision-making area of competence;
- has assigned a decisive role to the independent Directors by providing for the involvement of the Internal Control Committee in the inquiry and deliberative phases of the aforementioned relevant transactions with the possibility to be assisted in carrying out these tasks by one or more experts appointed in its choice. The Committee plays also an important role in those transactions that do not fall within the area of the competence of the Board;
- has provided for a more in-depth inquiry into all transactions conducted with related third parties, regardless of deliberative powers, in order to ensure transparency as well as a substantial and procedural correctness of the transactions; this transparency must also be ensured in the subsequent deliberative phase.
Consequently, the approved Guidelines define the policies to be adopted by the Group in this area.
The number of relations of a commercial, financial and other nature with related third parties, the description of the type of most relevant transactions, the impact of these relations and transactions on the balance sheet, the income statement and cash flow statements, are highlighted in the explanatory notes to the consolidated financial statements (Note 36 – Relations with related third parties).
The Guidelines, as required by Eni’s Code, also regulate transactions involving the interests of Directors/

(62) Alternate Judge is Amedeo Federici.

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Auditors, thereby providing that:
- Directors and Auditors periodically issue a statement reporting the potential interests held by each party in relation to the company and to the Group, and they promptly notify the other Directors and the Board of Statutory Auditors about individual transactions with the Company in which they hold interests that are "external" to the company;
- the involved Directors normally do not take part in the discussion and in the resolutions issued by the Board with regard to relevant issues; at times they may even leave the meeting room.
In any case, the transactions in which the related third party is a Director or an Auditor, or other parties associated with them, are considered relevant and thus subject to more in-depth investigational and deliberative procedures, as well as to a resolution that the Board of Directors takes after consulting with the Internal Control Committee.
The text of the Guidelines is available on the website of the company, in the Corporate Governance section.
Relations with the shareholders and the market From the start of the privatization process and in compliance with its Code of Ethics and Corporate Governance Code, Eni maintains an open and on-going communication with institutional investors, with retail shareholders and with the market in order to ensure the dissemination of complete, correct and timely information on its activity, with restrictions applied only to certain confidential information.
Information concerning periodical reports, the four year strategic plan, events and relevant operations is disseminated by means of press releases, meetings and conference calls with institutional investors, financial analysts and the press and is promptly disseminated to the public also through its website. In particular, presentations given by top-management and directed to the financial markets, that contain quarterly and yearly operating results and the four year strategy, are broadcast live from the website of the company, thus giving to the retail shareholders the opportunity to be informed in real time on the most significant market events. The recording of these events, the press releases and the live presentations are available at all times on the website. In the month of December, the financial calendar is disclosed to the market and published on the website with details on the main financial events of the following year. The pages "Eni on the Stock Markets" (Eni in Borsa), in the Investor Relations section of Eni’s website⁶³ are constantly updated with information regarding dividends, securities prices, peer securities trends and main exchange codes.
Also available on the web site are the periodical reports, the press releases, the Report, the Governance Code and related procedures, Eni’s By-Laws, communications to shareholders and bond holders, reports and documentation regarding the topics of the agenda of the Shareholders’ and Bondholders meetings, with the related minutes. The documentation is sent to anybody who may request it, also through the website⁶⁴.
The company has also agreed to fulfill the requests, which have emerged in recent Shareholders’ meetings, for an increasing involvement of the investors.
Eni is fully committed to make available to the public all information, as required by the law, and in addition all information related to its own Corporate Governance system, with particular attention given to keeping the content on the website consistently updated. A section of the website is dedicated to Eni’s corporate governance, and the governance system is illustrated in a summary interactive diagram⁶⁵ as well as through additional detailed explanations. The site also provides a significant amount of documentation, easy to consult, including this Report, previous reports and all the documents mentioned in the Report. The efficacy of the communication provided by Eni through its corporate website has been rated of the best quality for two consecutive years (2008 and 2009), both at national and European levels⁶⁶, thanks to its capacity for guaranteeing a high level of disclosure through a clear, accessible and transparent presentation style. In particular, the corporate governance section has earned the highest score among Italian companies and the second highest among European companies⁶⁷. Notwithstanding all regulatory and Statutory provisions, the project aiming at encouraging the interest and participation of the shareholders is progressing. In recent years, in fact, the objective to have companies not only respect the rights of the shareholders, but also promote their active participation by assisting them in exercising their rights, by communicating comprehensible and easily accessible information and by encouraging their participation in corporate activities, has been strongly stressed.

(63) At the following address: http://www.eni.com/en_IT/investor-relation/eni-stock-markets/eni-stock.shtml

(64)	At the following address: http://www.eni.com/en_IT/documentation/documentation.page?type=bil-rap&header=documentazione&doc_from=hpeni_header
(65)	At the following address: http://www.eni.com/en_IT/governance/governance-model-policies/eni-corporate-governance-code/eni-corporate-governance-code.shtml
(66)	This refers to the "H&H Webranking" which provides the most authoritative rankings on the quality of corporate communication through a website of the most important 100 Italian and 500 European companies.
(67)	At the following address: http://www.eni.com/en_IT/governance/governance-model-policies/eni-governance-awards/eni-governance-awards.shtml

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The commitment to presenting Eni to the shareholders in the simplest and most intuitive way led to the idea of creating a section of the website⁶⁸ dedicated to direct communications including a Guide for the Shareholders and an overview of future initiatives. One of these initiatives is the presentation of the Shareholders’ Meeting – held on April 30, 2009, for the approval of the 2008 financial statements – and of the shareholders rights, by means of a simple and quick interactive animated film. Specific positions/functions within Eni ensure effective relations with institutional investors, shareholders and the media.
In particular, as set forth in the Eni’s Code, the relations with institutional investors and financial analysts are handled by the Manager of Investor Relations; all related information is available on the Eni website and may be requested by e-mail at the address: investor.relations@eni.com.
The relations with the media are handled by the External Communication Manager; all related information is available on the Eni website and may be requested by e-mail at the address: ufficio.stampa@eni.com.
The relations with the shareholders are handled by the Company Secretary For Eni SpA Manager. All related information is available on the Eni website and may be requested by e-mail at the address segreteriasocietaria.azionisti@eni.com or by calling the toll free number 800940924 (outside of Italy: 80011223456).
The relations with the shareholders, as regards corporate governance matters, are handled by the Corporate Governance Systems and Policies Manager. All related information is available on the Eni website and may be requested by e-mail at the address: info.governance@eni.com.
Corporate information processing In compliance with the provisions set forth in the Consolidated Law on Finance and in the Consob Regulations on Issuers, upon implementation of the European Directive on the so-called Market Abuse, the Board of Directors, on February 28, 2006, has approved procedures for communicating privileged information to the market, for creating a log of individuals with access to privileged information and for notifying about transactions carried out by previously identified "relevant subjects" and concerning the shares of the company (internal dealing). These procedures were subsequently updated to include the interpretations provided by Consob through a communication dated March 28, 2006, and are available in the Corporate Governance section of the Eni website⁶⁹ Following is a summary of the approved procedures. Communication to the market of documents and inside information
The "Procedure for advising the market of inside information and documents concerning the Group’s issuer companies and their financial instruments", adopted in substitution of a previous policy dating back to 2002, sets forth the requirements for communicating inside information (materiality, clarity, homogeneity, information symmetry, consistency and timeliness) to the public and defines the rules for acquiring, from the subsidiaries, the data and information that are necessary to provide accurate and prompt reports to the Board and to the market on the events and circumstances that may materialize into inside information.
Furthermore, the procedure identifies the measures to be adopted in the event of an infringement of the provisions contained therein, also keeping into account the new types of offences that are subject to legal and administrative sanctions introduced by the Savings Protection Law. Eni’s Code of Ethics defines the confidentiality obligations of the Group’s employees with regard to the processing of confidential information.
The Directors and the Auditors ensure the confidentiality of the documents and of the information acquired during the course of their operations and comply with the procedure adopted by Eni concerning the internal management, as well as the communication to external parties, of such documents and information. Register of persons having access to inside information
The "Procedure for keeping and updating the Register of Persons with access to inside information of Eni SpA", set up in compliance with the provisions of Article 115-bis of the Consolidated Law on Finance and with the executive provisions of the Consob Regulations on Issuers, defines the following: (i) the methods and terms for the registration in the Register (or removal from it) of individuals who, because of their work or professional activity or because of the functions carried out on behalf of Eni, have access, on a regular or occasional basis, to inside information; (ii) the methods for communicating to the interested parties their registration in the Register, and/or their removal from it, with the related explanations.

(68) At the following address: http://www.eni.com/en_IT/governance/shareholders/initiatives/initiatives.shtml

(69) At the following address: http://www.eni.com/en_IT/governance/market-abuse/market-abuse-procedures/market-abuse-procedures.shtml

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Internal Dealing
The "Procedure concerning identification of the relevant persons and the transactions carried out directly or through nominees in respect of shares issued by Eni SpA or other related financial instruments " (Internal Dealing Procedure) has replaced the previous policy on the subject matter, dating back to 2002, and is written in compliance with the provisions of Article 114, paragraph 7, of the Consolidated Law on Finance. The procedure, in accordance with the indications provided for in the Consob Regulations on Issuers (i) identifies the relevant subjects; (ii) defines the transactions on shares issued by Eni or other related financial instruments; (iii) sets forth the methods and terms for communicating to Eni the transactions that are carried out, as well as the terms for disclosing such communications to the public. The procedure provides also, in addition to regulatory obligations, for certain periods of the year during which the subjects identified as "relevant" are not allowed to perform transactions (blocking periods). A similar principle has also been introduced in another internal procedure approved on December 23, 2008, concerning transactions carried out by the company on Eni’s securities or on securities associated with Eni’s securities. The Internal Dealing procedure was updated further on September 1, 2009 to include some organizational changes. Following are the tables mentioned in the "Handbook for the preparation of the Report on Corporate Governance", issued in March 2004 by Assonime and Emittenti Titoli SpA.

Structure of the Board of Directors and its Committees

Board of Directors Internal Control
Committee Compensation
Committee Oil-Gas Energy Committee

Members executive non executive independent % attendance other appointments ^(a) members % attendance members % attendance members % attendance

Chairman
Roberto Poli		X		100	3
CEO
Paolo Scaroni	X			100	3
Directors
Alberto Clô (*)		X	X	100	3			X	92	X	100
Paolo Andrea Colombo		X	X	100	6			X	92	X	100
Paolo Marchioni		X	X	100	0	X	80
Marco Reboa (*)		X	X	100	3	X	100			X	100
Mario Resca		X	X	88.2	1			X	100	X	10
Pierluigi Scibetta		X	X	100	0	X	95			X	90
Francesco Taranto (*)		X	X	100	2	X	100	X	100

Number of meetings in 2009	17		20	13	10
Average duration of meetings	3h 17m		4h 36m	1h 46m	1h 31m
Average attendance percentage	98.3%	98.7%	93.80%	96%	80%

(a)	Appointments as director or statutory auditor in other listed companies, also outside Italy, in financial, banking, insurance or large companies.
(*)	Appointed by the minority list.
For presenting a list a shareholder or group of shareholders must hold at least 1% of voting shares in an ordinary shareholders’ meeting, unless new regulation coming into force.

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Board of Statutory Auditors

Members % attendance
Meeting of the Board of Statutory Auditors % attendance
Meeting of the Board of Directors Number of other
appointments ^(a) Total number of
appointments ^(b)

Members
Chairman
Ugo Marinelli (*)	100	94	1	5
Auditors
Roberto Ferranti	69	82	1	2
Luigi Mandolesi	96	100	1	10
Tiziano Onesti	96	100	2	18
Giorgio Silva (*)	92	100	2	12
Number of meetings in 2009	26	17
Average duration of meetings	3h 48m
Average attendance percentage	91%	95%

(*)	Appointed by the minority list.
(a)	Including Eni SpA in accordance with Article 144-quinquiesdecies of "Regolamento Emittenti Consob".
(b)	Including listed companies in accordance with Article 144-quinquiesdecies of "Regolamento Emittenti Consob".
For presenting a list a shareholder or group of shareholders must hold at least 1% of voting shares in an ordinary shareholders’ meeting, unless new regulation coming into force.

Other information to be disclosed under the Self-discipline Code

	Yes	No
System of delegated powers and transactions with related parties
The Board of Directors delegated powers defining:
a) limitations	X
b) exercise	X
c) periodicity of information	X
The Board of Directors reserved examination and approval of relevant transactions (including transactions with related parties)	X
The Board of Directors defined guidelines for identifying relevant transactions	X
Such guidelines are described in the report	X
The Board of Directors defined procedures for examination and approval of transactions with related parties	X
Such procedures are described in the annual report	X
Procedures for the latest appointment of Directors and Statutory Auditors
Lists of candidate directors were deposited at least 10 days before the date set for appointment	X
Lists were accompanied by sufficient information on candidates	X
Candidates to the role of director disclosed information that qualified them as independent	X
Lists of candidate auditors were deposited at least 10 days before the date set for appointment	X
Lists were accompanied by sufficient information on candidates	X
Meetings
The company approved regulations of meetings	X
The regulations are attached to the report (indication of where to find it online is provided)	X
Internal Control
The company appointed persons responsible for internal control	X
Such persons do not report to managers of operating divisions	X

Internal office responsible of internal control (Article 9.3 of the Code) Internal Audit

Investor relations
The company appointed an investor relations manager	X

Information on investor relations manager (telephone, address, e-mail) and unit

Eni SpA - Piazza Vanoni, 1 - San Donato Milanese (Milan) 20097 Italy - Tel: +39 02 52051651 - Fax +39 02 52031929 - investor.relations@eni.com

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Commitment to sustainable developmentThe implementation of a sustainability model and relations with stakeholders

The sustainability model is part of Eni’s governance system and allows to plan, manage and communicate Eni’s commitment to sustainable development, focusing on the issues emerging from the assumptions on future energy scenarios and from dialogue with our stakeholders. The commitment to sustainable development is part of Eni’s governance model and affects the development of our management system. The most significant actions taken in this direction in the past few years concerned the promotion of shareholders’ participation in the company’s life, a stronger focus on issues of sustainability to be communicated to shareholders, the Board and the company itself and the dissemination of good governance practices in accordance with the principles stated in Eni’s Code of Ethics.
In 2009 Eni’s 231 Team updated Model 231 for the parts concerning crimes of receiving stolen goods, recycling and using moneys, goods and utilities deriving from illegal sources, crimes in IT and illegal data treatment, and will also take care of updating it with the new crimes introduced into Italian law in 2009.
During 2009 the Code Promotion Team carried out the implementation of a promotion plan that concerned: dissemination of the code to all those to whom Eni relates in its ordinary business activity, training activities and engagement of Eni’s main stakeholders on this issue.
Relations with the Global Compact were enhanced in light of the strategic value of this initiative for multilateral cooperation and with the United Nations. In 2009, in particular, Eni prepared an analysis of the ten principles of Global Compact in terms of achieved results, future commitments and measurability of results. With the aim of promoting transparency and fairness in dealings with the countries where it operates, in 2009 Eni continued to provide its contribution to the Extractive Industries Transparency Initiative (EITI) detailing the cash flows generated by its business activities in the countries participating in the Initiative in cooperation with the Italian Ministry for External Affairs with the aim of promoting the initiative in the countries that have not yet endorsed it.
As concerns human rights, after the completion of the experimental phase of the Human Rights Compliance Assessment (HRCA) methodology, in 2009 three new assessments were performed in industrial sites in Algeria, Egypt and Congo. In Nigeria and Kazakhstan, where pilot assessments were carried out, work continued for sharing results and analyzing recommendations on gaps recorded. As concerns security activities, in 2009, Eni designed and implemented a module on human rights in the framework of a training course addressed to security managers, along with a test training for staff of security agencies working for Eni. As concerns the provision of security services, Eni resolved to include specific provisions on the respect of human rights in its supply contracts.
Eni’s commitment to sustainability is confirmed by its ranking in the major sustainability indexes. In 2009 Eni was included in the Dow Jones Sustainability Index, in the STOXX and in the FTSE4GOOD, in addition to ranking second in the Accountability Rating Italy 2009. Eni was also ranked first in the Italian and world rating of the CSR Online Award 2009. In June 2009 Eni’s CEO received the Foreign Policy Association’s Corporate Social Responsibility Award.
Eni’s commitment for human resources in 2009 was focused on improvement actions based on the

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climate analysis performed and on the updating of management and development tools with a special focus on feedback processes.
In the area of safety, the progressive improvement of performance indicators achieved also in 2009 confirms Eni’s constant commitment to reducing the number of accidents involving employees and contractors and preventing and mitigating process risks. Eni also continued to work to improve the management of health protection, carried out with a "systemic" approach in all Eni sites in Italy and abroad, based on the development of a system for the integrated management of HSE issues.
The complexity and globality of the issues of sustainable development led Eni to cooperate actively with international organizations in the area of dissemination of sustainability.
In 2009 Eni requested CENSIS to perform a qualitative and quantitative survey addressed to Eni employees. The survey interviewed over 240 senior and junior managers and allowed to obtain an interesting view of the quality of the relations Eni holds with the countries where it operates, Italy included, as well as an overall view of its strengths and of the areas where improvement is required.
In 2009 Eni continued its work in consolidating relations with producing countries through the signing of agreements that integrate our traditional business with actions aimed at sustainable development. In 2009 Eni signed agreements in this sense in Angola, Kazakhstan, Congo, Egypt, Pakistan, Turkmenistan.
Eni has been committed for a long time to the protection of biodiversity and ecosystems by means of an organic approach to territories, that can highlight risks and opportunities related to a better management of resources, the enhancement of the environmental, cultural and social wealth of the countries where it operates.
The main objectives of Eni’s commitment to customers and consumers are represented by its ability to combine efficiently its sustainability model with the offer provided to its customers and increasing its dialogue with consumers’ associations. In 2009 in fact, Eni developed various new projects aimed at improving the quality of the services rendered and customer satisfaction, as well as consolidating relations with consumers’ associations.
The fact of being active in different parts of the world requires Eni to invest consistently so that also local suppliers and contractors respect the principles upheld by Eni. In 2009 Eni focused on projects aimed at:
- improving and codifying qualifications and controls of supply chains (vendor management systems), including an improvement of management systems and auditing, in particular in the areas requiring greater attention (e.g. emerging countries, critical areas);
- monitoring and disseminating the respect of sustainability principles in the supply chain;
- improving data collection systems especially outside Italy.
Commitment to environmental protection and investment of resources in it are major strategic objectives for Eni. The projects approved for reaching by 2012 the goal of decreasing by 70% flaring emissions (from emissions registered in 2007) reached on average 80% of completion in 2009, while many water injection projects have been carried out.
Research and innovation are a basic part of our commitment to constantly improve our sustainability model. Technologies developed to date intend to favor access to new energy sources, improve their recovery from the soil and the efficiency of use while reducing environmental impact.
Eni’s R&D is also addressed to the field of renewable energy sources, mainly solar energy and biofuels. In order to reach excellent results in this area and to overcome the current limitations to renewable sources by means of breakthrough solutions, Eni continued its policy of strategic alliances and cooperation based on the construction of a global network with major research centers while developing internal resources.

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PEOPLE

To Eni the people working in its production system represent an asset to be safeguarded and enhanced with careful career paths. Accurate assessment and development of personnel, training initiatives customized to roles and persons, along with the respect of shared ethical values, are key factors for the creation of sustainable value in the long-term. Eni’s main objectives for its human resources are:
- constantly updating management and development tools with a specific focus on feedback processes, addressing them to various population targets and extending them to all business units;
- investing on different types of population by identifying specific tools within a general policy aimed at a better integration and valorization of internal resources with a reduced recourse to new hiring;
- protecting, sharing and developing strategic know-how for supporting business strategies;
- supporting the engagement of personnel also with the introduction of additional welfare tools aimed at reconciling private and working life.
More detailed information on the management of human resources is found on Eni’s website in the area People and in the Sustainability Report.
Employees At December 31, 2009, Eni’s employees totaled 78,417, with a decrease of 463 employees from December 31, 2008, down 0.6%, reflecting a 718 increase in employees hired and working outside Italy and a decrease of 718 employees hired in Italy. Employees hired in Italy were 38,299 (48.9% of all Group employees). Of these, 34,794 were working in Italy, 3,282 outside Italy and 223 on board of vessels, with a 1,181 unit decrease from 2008. Declines were registered in all business segments due to efficiency actions and to the postponement to 2010 of some orders obtained by Saipem.
The process of improvement in the quality mix of employees continued in 2009 with the hiring of 1,163 persons, of which 491 with fixed-term contracts. A total of 672 persons were hired with open-end and with apprenticeship contracts, most of them with university qualifications (359 persons) and 282 persons with a high school diploma. During the year 2,357 persons left their job at Eni, of these 1,634 had an open-end contract and 491 a fixed-term contract.
Employees hired and working outside Italy were 40,118 (51.1% of all Group employees), with a 718 persons increase, of these approximately 650 employees were hired with fixed-term contracts in the Engineering & Construction segment due mainly to new contracts in Nigeria and Kazakhstan (Kashagan project), and 160 persons in the Exploration & Production segment, offset by downsizing in other segments, in particular in Hungary in the Gas & Power segment (Tigaz).

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Employees at year end (units) 2007 2008 2009 Change % Ch.

Exploration & Production	9,023	10,891	10,870	(21	)	(0.2	)
Gas & Power	11,893	11,692	11,404	(288	)	(2.5	)
Refining & Marketing	9,428	8,327	8,166	(161	)	(1.9	)
Petrochemicals	6,534	6,274	6,068	(206	)	(3.3	)
Engineering & Construction	33,111	35,629	35,969	340		1.0
Other activities	1,172	1,070	968	(102	)	(9.5	)
Corporate and financial companies	4,701	4,997	4,972	(25	)	(0.5	)
	75,862	78,880	78,417	(463	)	(0.6	)

Organization In 2009 Eni continued to upgrade its structures and organizational processes following guidelines consistent with the new corporate integrated model adopted by Eni.
Among the most significant upgrading processes completed in 2009, the following are worth mentioning:
- the centralization of all administration activities of Eni SpA into a single company (through the sale of relevant business units to Sofid, which changed its name in Eni adfin) in order to guarantee greater homogeneity and standardization of administrative processes and to improve efficiency and quality of services rendered. In addition, two new units, reporting directly to the CFO, have been created for evaluating and managing Industrial risks and Insurance, respectively. The former insurance unit has been eliminated with the new company taking up this role (Eni insurance) reporting directly to the CFO;
- a new structure has been given to the supply and procurement function, now called Global Procurement and Strategic Sourcing aimed at strengthening its presence outside Italy and optimizing the planning of procurement through a stronger integration with the requesting lines (to this end specific competence centers have been established that are made up of personnel from procurement and technical line reference persons);
- the reorganization of the Legal Department continued through the consolidation of a structure organized by geographical areas with a greater focus on compliance and antibribery issues (the new structure has been finalized on December 1, 2009 and started operating on January 1, 2010);
- the definition of a new structure for the Strategy and Development department, concerning in particular an improvement of direction and control of the areas of innovation and the integrated monitoring of long-term strategies;
- the start-up of new project called "Eni rules" aimed at defining a system of regulations and procedures oriented to processes, providing greater efficiency and flexibility in line with Eni’s new organizational model.
The design phase has been completed in December 2009, along with the inception of pilot projects, while in the first part of 2010 Eni intends to launch a new information system supporting document consultation, provided also with a view by process.
As concerns business units, Eni continued to upgrade their organizational structures to better adjust to business requirements and industrial plans in order to maximize efficiency and the protection of safety, health and the environment.

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Management and development
of human resources The "Eni secondo te 2008" climate analysis was a great opportunity for collecting opinions and suggestions from Eni people, following which Eni launched and continued various initiatives aimed at improving communication, leadership and engagement also providing a stronger support to the effort at reconciling private and working life. These initiatives have been collected in a dedicated internet site that is going to be opened to users in 2010 in coincidence with the start-up of a new survey.
Eni continued the integration and revision of its various management and development tools that led to the definition of a new formalized feedback process related to the annual performance assessment. In 2009 Eni launched an "Eni excellence model" aimed at supporting managers in assessing resources and favoring the dissemination of a common language. The excellence model will be disseminated to all Eni people and will be used for evaluation and development actions. Eni continued the mapping of managers’ skills by means of its Management Review that keeps into account potential development and performance achieved. For resources with a high development potential specific methodologies have been applied for an in-depth evaluation of future allocations. These processes allowed to update the succession plan, a tool used by top management in its decisions concerning the more relevant managerial resources.
In 2009 in the area of compensation and benefits various projects have been set up for better integrating compensation and local situations and benchmarking compensation with competitors.
A relevant initiative concerned the updating of compensation policies addressed to international mobility of resources, a key factor for the development of businesses outside Italy.
Aimed at enhancing the benefit system, Eni started a communication program to support its offer of additional health and pension programs. Eni also started the definition of a global governance model to be applied internationally in the area of health and pension benefits. Training and internal communication Following the results of the "Eni secondo te" climate analysis performed in 2008, in 2009 various training activities have been carried out in order to develop leadership, improve relations between managers and employees, support individual motivation and favor widespread wellbeing. A total of 1,100 managers from all business areas participated to these initiatives that included also managers involved in the "360° feedback" project.
In addition, at the end of 2009, a training initiative was addressed to key managers and concerned assessment of and feedback to employees. The action will continue also in 2010.
In 2009, expenditure for training amounted to euro 49.2 million, of which euro 30.4 million in Italy and euro 18.8 million outside Italy. A total of 3,094,487 training hours were provided (1,423,051 in Italy and 1,674,436 outside Italy). In addition, 807,969 hours of training were provided to non consolidated companies outside Italy for an expenditure of euro 21.1 million.
Eni continued its work on the development of knowledge management systems by implementing dedicated IT systems supporting existing ones, increasing the number of persons addressed and creating new practice communities in the E&P and R&M divisions, in the HSE area and at Polimeri Europa. Also in the G&P division projects have been started for the creation of a knowledge management portal and the development of a practice community in the division and at EniPower.
In 2009, Eni inaugurated the 53^rd academic year of the Scuola Mattei operating in research and post-graduate training in the fields of energy and the environment. From its foundation in 1957, the school trained over 2,600 young talents, of which 55% came from 110 countries in the world. In 2009-2010 the school hosts 59 students (28 from Italy and 31 from the rest of the world).
Special attention has been paid to internal communication to promote a more widespread and constant penetration of communication that favors the exchange of information and ideas. In 2009 the cascade program addressed to all Eni people and aimed at stressing the concept that the contribution of each person allows to reach corporate objectives, engaged 30,940 persons in 43 countries and consisted of 484 meetings in 103 sites.
All internal communication programs are published on myeni, the corporate intranet portal, a unified platform for sharing information with 31,700 registered employees. The program for extending myeni outside Italy continued and reached a total of over 5,400 users (up 34%). Other communication channels have also been increased by means of tools such as digital signage (a system of plasma screens centrally managed to disseminate news and

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videos in real time), myeni news (a paper version for employees who do not use a computer); an internal communication network (an international network aimed at highlighting success experiences, disseminating information and providing a local base for cross company initiatives).
In 2009 the new welfare site has been launched, as a communication tool where employees find information on current and new initiatives aimed at enhancing and showing Eni’s commitment to the issues of reconciling private and working life. New activities and services meeting the real and specific needs of Eni people are being elaborated, such as services supporting families and favoring an improved management of money and time.
Industrial relations Industrial relations in 2009 have been characterized by a constant dialogue with workers’ unions that led to significant agreements concerning the reorganization of business units that touched Eni and its subsidiaries.
In particular agreements regulated the sale of the Administration business unit from Eni SpA to Eni adfin SpA and the transfer of mineral assets from the E&P division to three newcos, Società Padana Energia SpA, Società Adriatica Idrocarburi SpA and Ionica Gas SpA.
Dialogue and communication with workers’ unions also marked the completion of the reorganization of the G&P and R&M divisions started in the previous year. In 2009 the new collective contract for workers in the chemical industries was signed, while negotiations are underway for renewing the collective work contract of workers in the energy and oil and water industry.
With reference to the new fund integrating public health assistance for employees (FASIE), the process of integration with the pre-existing organizations has been completed, thus unifying all provisions related to reimbursement of personal health spending under specific tariffs and an insurance against death and illness for all employees that will be operating from January 2010.
Internationally, in March 2009, Eni and the International Federation of Chemical, Energy, Mine and General workers Union (ICEM) and the Italian Workers’ Unions signed an agreement on international industrial relations and corporate social responsibility. In June 2009, the European Works Council met in Lisbon for its 13^th general meeting. Health Eni is committed to the protection of the health of its people, of the communities living in the areas where its plants are located and of all those that get in touch at various times with its activities.
In particular Eni adopted a systemic approach to all its activities in Italy and abroad based on a general framework of regulations on health and safety in line with OHSAS 18001.
In implementing this system, Eni carried out assessments of the local health situations and of any risks posed to workers’ health by means of:
- health risk assessments;
- health surveys;
- Occupational Health and Medical Support Gap Analysis - OH&MSA GA.
These methodologies represent the basis for developing local programs of work medicine, health assistance and management of emergencies.
In order to optimize health management Eni is implementing a documentation system extended to all business units by integrating all existing systems.
Eni confirms its serious commitment to prevention also outside Italy with actions geared on local regulations and Eni standards and signing service agreements with other companies active in areas where no generalized service is provided.
At European level Eni continued its work for applying the REACH Regulation (Registration, Evaluation, Authorization and Restriction of Chemicals, EC Regulation No. 197/2006). Eni estimates that about 150 products in its plants fall within the scope of this rule.
Safety Eni has always been deeply engaged in the issue of the safety of its workers, of the people living in the areas where its industrial sites are located and of its producing assets.
Based on the evaluation of actions, benchmarking and performance, its short and medium-term strategy is updated every year and is addressed to:
- dissemination of a safety culture to all Eni people, this year mainly focused on process security;
- technological and operational support to business units;
- compliance with recently enacted Italian safety laws, as improved by Legislative Decree No. 106 and analysis of its impact on Eni’s activities;
- continuing improvement of performance in critical areas.

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As a response to these policies, Eni started the following actions.
In the area of enhancing the safety culture of Eni people: a new project called Communicating safety, developed and promoted jointly by the corporate HSE department and the Internal Communication department, based on a careful survey of the most frequent accident causes, from which it emerged that a relevant portion (over 60%) of accidents is related to behaviors such as underestimation of risk, lack of concentration, etc. This project is directed to 11 business units, in about 100 sites, and addressed to employees and contractors for a total of about 60,000 persons. The first operating phase (teasing) started on December 18, 2009, anticipates the dissemination of messages on safety making use of well established media techniques: posters in the workplace, images and slogans that capture attention and accompany people on a route of awareness and motivation.
The application of a methodology for increasing awareness of middle management and workers called Leadership in safety, developed and successfully applied by Saipem in the past two years in refineries of the R&M division.
On the question of process safety a seminar has been organized for middle management and staff (for a total of 140 persons) aimed at exchanging knowledge and experiences integrated by lectures on the European approach to the issue. This initiative is part of the HSE training for top middle management that will be reported to employees through the cascade system.
As for technological support, business units have been provided with the INDACO database for the collection, management and dissemination of information on accidents, near misses and under standard operating conditions. The most relevant business units have started to feed in their data.
Support to business units includes also the simulation of accident trends (Congo, Italy) based on historical data, information on the developments of emergency management worldwide and participation to emergency drills and trials (Archimede, oil spills in the sea, with the cooperation of the Italian navy).
Among the actions for improving safety management, we like to mention: technical guidelines on monitoring contractors, guidelines for obtaining work permits, the updating of safety audits according to the most recent model, the developments in the 3TER software to an advanced version with better integration of georeferenced data of industrial sites.
After the earthquake in Abruzzo, Eni provided its valuable support to the civil works department with qualified professionals and appliances. Eni’s new HSE emergency room and personnel from its emergency unit coordinated all the work required for guaranteeing the safety of plants and the distribution of refined products in the area affected by the quake.
This constant commitment led to a further improvement in safety indicators for Eni, confirming the positive trends of the past three years.

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RELATIONS WITH TERRITORY AND COMMUNITIES

The model of cooperation
and development in territories One of the distinctive features of Eni’s relations with the communities and territories where it operates – ever since the early times of the "Mattei formula" – consists in developing strategies for dialogue, cooperation and the creation of actions and projects for producing development paths that respect local specificities. The tools used by our company for implementing a cooperation model in the countries where it operates are the promotion of open and proactive dialogue with the main stakeholders, the definition of integrated agreements (Memorandum of understanding or Intent protocol) with subjects in countries or regions, the promotion of local content through the enhancement of local supply chains, the support of development initiatives for the self-determination of social and economic systems, the integrated charitable action of Eni foundation.
In 2009 Eni continued to consolidate its relations with producing countries, first of all through the definition of agreements that integrate its traditional business with actions aimed at promoting sustainable development in those countries. The actions carried out confirm Eni’s commitment to the areas with greater strategic importance, with particular reference to Sub-Saharan Africa, where Eni has been present since the early sixties, in the most important producing countries such as Angola, Nigeria, the Republic of Congo, Gabon and Mozambique. In 2009 Eni signed agreements in Angola, Kazakhstan, the Democratic Republic of Congo, Egypt, Pakistan, Turkmenistan. In February 2009 in Angola Eni signed with Sonangol the first agreements provided for by a Memorandum of Understanding relating to a contribution to the sustainable development of the country’s energy infrastructure and the implementation of educational and training projects for local professionals. Within the cooperation agreement signed with the Egyptian Oil Ministry, Eni agreed to provide its infrastructure and the skills of Eni Corporate University for a joint training program for local professionals addressed to selected qualified resources. In November 2009 Eni signed a cooperation agreement with Turkmenistan for the provision of training to local resources.
In Italy Eni signed an addendum to the intent protocol with the Basilicata Region that implements actions for sustainable development and the management of an environmental monitoring system on upstream activities in Val d’Agri with an investment of approximately euro 67 million to be paid by Eni in annual installments in the next 10 and 15 years, respectively. Eni also signed a protocol of intent with the Ministry of Education and the University of L’Aquila for the project called "A bridge to innovation".
In 2009 expenditures for local development amounted to euro 98.6 million.

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Engaging communities and knowing territories

Engaging communities and knowing territories Eni acts as an integral part of the territories where it is present proactively opening areas of dialogue and communication with local communities. The engagement of local stakeholders is included in all phases of our business projects. In addition, in order to manage and monitor the effect of its activities on the areas, Eni performs feasibility studies and impact assessments. In order to improve these tools, in late 2009 Eni started a cooperation with the International Business Leaders Forum (IBLF) aimed at integrating the impact assessment criteria directly related to human rights in business practices (impact analysis).
In 2009 within Eni’s E&P activities, various studies have been carried out for assessing and analyzing the environmental and social impacts, as well as the social and health risks (ESIA - Environmental and Social Impact Assessment, SIA - Social Impact Assessment, EIA - Environmental Impact Assessment, HIA - Health Impact Assessment, SBA - Social Baseline Assessment) in Algeria, Angola, Congo, Mali, Indonesia, Italy, Mozambique, Nigeria, Australia, India and Pakistan.
Development of territories Eni aims at creating opportunities for the territories where it operates respecting the directions chosen by local communities through integrated long-term programs and projects, as for example the Green River Project that started in 1987, and continues to support the development of local communities in the states of Nigeria where it operates. In 2009 Eni started various initiatives for the development of local social and economic activities through the upgrading of local procurement, microcredit actions, local empowerment, vocational training and provision of infrastructure and basic services for communities.
In 2009 expenditure for local communities amounted to euro 70.4 million, over 60% of which was devoted to infrastructure and social actions. In Italy in 2009 in cooperation with FEEM and the Aaster consortium Eni continued the "Community Mission" project aimed at engaging local communities in actions and dialogue for fostering tourism.
Special attention was paid to the enhancement of tourism in particular focusing on small sized enterprises by means of the creation of an educational nature trail and the inauguration of an educational center dedicated to Energy and Territory in Calvello. In cooperation with Civita, Eni started a project for the enhancement of the historical and artistic heritage of 23 municipalities in Val d’Agri and Val Camastra. Eni also cooperated in the creation of trails and tracks for a better knowledge of local natural beauties and, in cooperation with Shell and the local arts council Eni sponsors the restoration of a Roman villa at Barricelle.
In May 2009 Eni signed a protocol with the University of L’Aquila and the Ministry of Education called "A bridge for innovation" aimed at supporting research and fostering the economic recovery of the Italian city badly damaged by an earthquake in April 2009. Eni is providing human, financial and structural resources.
In 2009 in Kazakhstan Eni invested $7 million for the provision of vocational training for local employees

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and approximately $10 million in infrastructure, such as schools, hospitals, sports and arts centers aimed at fostering local social and economic development policies. In Pakistan Eni continued in 2009 the Bhit Rural Support program with an investment of $420,000. The BSRP is a rural development program based on the promotion of local skills and on the engagement of the local community in the definition and implementation of activities such as vocational training, microcredit for starting new enterprises, creation and management of infrastructure for improving the life conditions of local communities, support of animal husbandry and agriculture.
In East Timor Eni continued its integrated rural development program started in 2008 in partnership with CARE, the international NGO, aimed at improving health and life conditions in 6 villages in the Bobonaro and Covalima districts. Over 100 courses of health and food education have been provided along with the supplies for planting 140 vegetable gardens and training 364 farmers.

Country	Areas /Activities 2009
Algeria	Construction of infrastructure for power generation from solar energy and water supply in cooperation with the Sonatrach-Tassili Foundation; at Setif, training and hiring of local staff for the restoration of the Roman Bacchus mosaic; sponsoring of the second pan-African cultural festival; environmental and social impact assessments.
Angola	Finalization of specific agreements included in the MoU among which a Cooperation Protocol for education signed with Sonangol.
Australia	Local empowerment actions and capacity building projects, support of local indigenous entrepreneurship; campaigns for the protection of women’s and children’s health; support and enhancement of indigenous culture; social impact assessments.
Republic of Congo	Construction of water infrastructure, agricultural development projects, construction of schools; creation of a Monitoring Committee and a Working Team for the "Oil Palm" pilot project.
Ecuador	Construction of roads and water supply mains; construction of health centers and schools; cooperation agreements with indigenous communities in the area of the Villano Project.
Egypt	Campaigns on road safety; provision of a training course on health and safety; support of health services; support of education by means of scholarships.
India	Social structure assessments in the Andaman Islands.
Indonesia	Construction of roads; support of agricultural development; sponsoring of projects for specialized surgery; enhancement of local cultural heritage; environmental and social impact assessments.
Italy	Basilicata – Signed an Addendum to the Intent Protocol with the Basilicata Region; support to the development of tourism and start-up/improvement of relations with developing entrepreneurs; protection of natural beauties and construction of an educational nature trail; elaboration of the first social territorial balance of Val Camastra (FEEM); creation of a permanent seat of confrontation between Eni and local stakeholders; provision of training for journalists (with FEEM) and educational activities; restoration and enhancement of local cultural heritage; environmental and health impact assessments. L’Aquila - signed an Intent Protocol for starting the project "A bridge for innovation". Ravenna - Social and economic impact assessments.
Kazakhstan	Construction of infrastructure for the health, education and community sectors, for gas and water supply; promotion of local empowerment actions fostering entrepreneurship; support to culture, training and education; social impact assessments.
Libya	Construction of infrastructure for the health and education sectors. Restoration of the existing museums and construction of a new visitor trail in the Archaeological Site of Sabratha; study on the management of urban, special and hospital waste; inauguration of a laboratory at the department of environmental engineering at the Sabratha - Seventh of April University; support to treatment programs for AIDS patients; environmental impact assessments.
Mali	Construction of water wells powered with solar energy for local communities; training of medical and paramedical staff; environmental and social impact assessments.
Mozambique	Restoration of water supply networks; provision of education and training; environmental impact assessments.
Nigeria	Signed a MoU concerning actions in education, power supply, health protection, infrastructure and protection of coastal areas; improvement of water supply and road networks, civil, health and education infrastructure; microcredit projects, development of human resources, support to farmers; scholarships; environmental impact assessments.
Norway	Construction of a bird watching center; design of an Arctic Slow Food Centre; educational projects for increasing learning of industry related subjects.
Pakistan	Signed partnership agreements for the 2010-2013 period with local NGOs; integrated projects for rural development by means of capacity building; construction of water mains, medical buildings and services; support to medical centers; training for promoting food safety, for computer use, teaching projects; social impact assessments.
East Timor	Integrated rural development projects fostering local entrepreneurship, health and safe nutrition, training and capacity building; health and nutrition education, children’s rights and protection of children’s and mothers’ health; environmental impact assessments.

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Eni Foundation In 2009 the Eni Enrico Mattei Foundation continued its work for solidarity actions in support of the health of women and children especially in Africa with the Salissa Mwana and Kento Mwana programs in Congo and Kamba Kiaxi in Angola. In 2009 in Congo nearly 5,000 pregnant women applied to the health centers that provide tests and protocols for the prevention of AIDS. In Angola approximately 150,000 children received care from a program sponsored by Eni.
Protection and enhancement of ecosystems Eni has been committed for years to the protection of biodiversity and ecosystems through an organic approach that highlights risks and opportunities related to an improved management of resources, the protection of the environmental, cultural and social heritage of the countries where it operates.
As part of "Proteus 2012", an action promoted by UNEP (United Nations Environmental Program) - WCMC (World Conservation Monitoring Centre) endorsed by Eni in 2008, in 2009 Eni continued the collection of information within the World Database on Protected Areas (WDPA) aimed at mapping operating sites in terms of biodiversity so as to reduce the risks deriving from operations in these areas.
From 2009 Eni is also part of the Environmental Services, Tools & Markets Working Group promoted by Business for Social Responsibility (BSR) that is to date the most important business action for the comparison and analysis of the most updated tools and methods for evaluating ecosystemic services on the life cycle of industrial plants.
The culture of sustainable development The promotion and support of culture as a lever for education and training of new generations have become a distinctive feature of Eni.
Eni supports research by participating in international projects and providing funds for scholarships. In 2009 Eni conferred to Eni Corporate University the management and coordination of all its activities in the area of education and research carried out with Italian and international academic institutions.
Eni’s expenditures in this field in 2009 amounted to euro 28.5 million (49% in Italy and 51% abroad). Over half of co-operations concerned research activities (including service contracts), 17% was dedicated to training and 23% scholarships and other funding.
In May 2009, in L’Aquila, a Protocol of Understanding was signed by the Italian Ministry of Education, University and Research, the University of L’Aquila and Eni which launched the "Un ponte per l’Innovazione" (A Bridge for Innovation) Project for the support and accommodation at structures belonging to the Eni Group of 50 PhD students and researchers from the university, also through study grants and project contracts aimed at allowing the continuation or start-up of study, teaching or research activities in the energy and environmental sectors.
Eni supports culture also by sponsoring projects based on criteria such as affinity with Eni’s image and identity, links with areas of presence, adherence to Eni’s business objective and high visibility, always keeping account of sustainability.
In 2009 Eni sponsored projects and events with a total expenditure of euro 16.6 million. Eni was partner of the municipal museums of Venice and financed various events and exhibitions in Italy, such as the Mantova Festival and the Ravenna Festival. Eni was also a partner for the festival of the city and area of Ferrara centered on the issue of territory in all its aspects.
Through its Historical Archive in 2009 Eni conducted research on its brand. Cooperated to the shooting of a TV movie on the life of Enrico Mattei based on historical material provided by Rai and Lux Vide which received very positive reviews and great appreciation from the public. It also participated to the European Oil and Gas Archives Network in Norway together with the main players of this industry (Total, ConocoPhillips and Hydro Statoil).

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Activities of the Eni Enrico Mattei Foundation The Fondazione Eni Enrico Mattei (FEEM) that celebrated in 2009 twenty years of activity in the field of sustainable development is considered one of the international centers of excellence on the study of environmental and energy issues. FEEM supports Eni in actions favoring sustainable development, in particular in Basilicata by providing training, research and support to local activities.
The year 2009 was very important for research: as worldwide governments met in Copenhagen to define an agreement on policies for climate change (COP15), FEEM worked at defining indicators of sustainability in addition to GDP. This year has been important also for innovation in the promotion of research, dissemination of scientific results and communication, three factors that contributed to confirming the relevance and impact of FEEM.
In 2009 various cooperation agreements were confirmed with important Italian and international institutions such as the Fondazione Giorgio Cini in Venice and the Monitor Group in the USA.

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RESPONSIBILITY TOWARDS THE ENVIRONMENT

Reference scenario The impact of industrial activities on the environment is affected by an increasing number of stringent laws and regulations in Italy and Europe. In 2009 this trend was further confirmed. In Italy Law No. 68/2009 devolved authority to the government to approve before June 30, 2010 legislative decrees for adjusting and integrating the so called "Environmental Code" intended to collect and simplify all laws and regulations pertaining to the environment. A ministerial decree of December 17, 2009 defined a system to trace all waste. In Europe too the situation has changed. In April a new directive was published concerning the geological storage of carbon dioxide (2009/31/CE). On October 10, 2009 the new REACH discipline came into force. In November 2009, the European Union marked the official start of the new E-PRTR (European Pollutant Release and Transfer Register) where 2007 data of over 24,000 industrial facilities covering 65 different economic activities are stored. At the end of 2009 the new EMAS 1221/2009 regulation came in force. At the end of December the European Commission published a list of sectors and sub-sectors considered exposed to an increased risk of relocalization of carbon emissions.
Despite these trends in laws and regulations, Eni strives to carry out its activities going beyond the limits set by current laws. In all its facilities Eni employs reference best practices and guarantees high quality products while respecting the environment. Eni applies and promotes the most efficient environmental management systems, alerts its managers on the issues of the environment, makes use of state of the art technologies, provides training on environmental themes to its employees. Eni pursues the highest performance targets, extending its standards to its suppliers and contractors and at its foreign affiliates.
More detailed information on the reduction of the environmental footprint is found on Eni’s website in the area Sustainability and in the Sustainability Report.
Environmental management Eni pursues the objective of a high environmental performance in all its activities by means of comprehensive certification programs of its HSE management system applied in all areas in line with its management model, as updated in January 2010.
In the spring of 2009, the US Environmental Protection Agency published an article "The Eni success story" describing the participation of Eni to the international initiative called M2M (Methane to Markets) and confirming our contribution to innovative actions for the reduction of methane emissions. This project promotes the recovery of methane and its use as clean energy source to favor economic growth and energy safety, improving the quality of air and reducing greenhouse gas emissions.
In 2009 Eni further improved its HSE planning and periodic control systems. The planning and analysis process led to the definition of improvement objectives for the main environmental aspects to be reached by means of specific innovative projects. The Eni PRTR project is nearing completion. The project consists in the implementation of a centralized information system for the areas of air, water, soil and waste in line with the European Regulation 166/2006/CE aimed at the creation of the European Register of Pollutant Release and Transfer. This will lead to a unification, integration

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and improvement of environmental management and of performance monitoring. This system, currently being released to business units will provide for the collection of environmental data for 2010.
In 2009 Eni obtained 5 integrated environmental authorizations (AIA) for 4 types of facility (refinery, power plant, platform, petrochemical plant), while the remaining facilities are still undergoing the relevant survey. As concerns certification, nearly all major production plants obtained the ISO 14001 certification.
In Europe, Eni’s main production facilities have applied for EMAS certification, while many foreign affiliates, petrochemical plants and gas pipelines obtained a OHSAS 18001 certification or ISO 9000 or both. In the Exploration & Production division, on a total of 37 companies, 23 obtained the ISO 14001 certification; in the petrochemical segment the ISO 14001 certification was completed for all production plants, as already done in the refining area. The electric segment expects to complete the ISO 14001 certification of all plants by 2010.
Know-how in the HSE area is managed also with the help of specific career paths aimed at enhancing the contribution of qualified resources conferring their competence and expertise.
These qualified professional resources are managed in a way that enables them to share information and knowledge, thus optimizing synergies among the various units.

Rational use of natural resources The minimization of use of natural resources and the control of impacts that are priority objectives of a sustainable environmental management are achieved by adopting the best practices and technologies capable of ensuring a proper control of releases in the environment (air, waters, soils).
Eni constantly strives to reduce air emissions with the help of investments aimed at improving monitoring and reduction systems. By using the best available techniques, Eni’s facilities show a good level of control of emission of primary pollutants (carbon monoxide, nitrogen oxides, sulphur dioxide, total particulate and aromatic compounds). Emissions of SO₂ and NO_x declined by 5% and 3%, respectively.
In addition, the development and adoption of programs of energy efficiency, aimed at optimizing the use of energy in industrial processes guarantee the containment of all air emissions. Eni has been striving for years to use low environmental impact fuels and promotes the use of natural gas with ensuing benefits for air quality.
The rationalization of water consumption has been obtained by preferring integrated production cycles based on the treatment and recycling of process water. In the Exploration & Production division, water injection projects allow to maintain field pressure, reducing the environmental impact of releasing process waters.
In 2009 re-injection of water increased due to projects carried out in Libya (in the Bouri field from June 2009, in the Bu Attifel field is expected to come on line in the first quarter of 2010), Egypt (where a 50% share of reinjected water was reached from 40% in 2008), Algeria

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(expected to reach 100% at mid-2010), Indonesia (in 2008 all water had been reinjected at the Badak, Nilam and Semberah sites and in 2009 the project has been extended to Pamaguan and Mutiara) and Kazakhstan, where in the settlements built for the workers and the facilities of the offshore Kashagan project water treatment plants have been installed that reduced the amount of clear water required. In addition, in 2009, work continued to define the standard on the minimization of water consumption and discharge that already led to a 17% reduction in water consumption from 2008.
The management of waste deriving from production activities is obtained by optimizing production processes, identifying actions for reducing waste sent to landfills and by controlling also the operations of contractors. Eni continued the planning and management of divestment/decommissioning of industrial plants, the environmental reclaiming of soils and aquifers under approved and environmentally adequate processes and procedures.
Waste from production processes amounted to approximately 1.6 mmtonnes, in line with 2008.
In 2009 the Exploration & Production division following the assessment of waste management performed, published a standard for waste management planning addressed to all its affiliates and indicating the planning process to be carried out for each year and four-year period that will allow to monitor and plan the management of different kinds of waste, identifying all possible improvement actions.
In the Petrochemical segment, technical and management actions continued to reduce total waste produced, while Syndial applied a program for the management of reclaiming actions also intended to reduce waste production.
In order to protect the areas where Eni operates, responsibilities and operating modes aiming at reducing the negative impact of oil spills have been defined. Tools available include the recourse to external professionals and/or international organizations. Various projects in oil spill assessment/response/plan are underway or have been completed. In the R&M division in 2009 Eni continued to apply technical improvements for prevention and containment to its facilities with new actions planned to be carries out in the next few years.
In 2009, In the Exploration & Production segment a total of 287 oil spills were registered for a total of 21,547 barrels of oil spilled (increasing from the preceding two years). About 17% of all spills were due to sabotage, while the volumes deriving from accidents increased by 33%.
In line with the increasing attention for green remediation, Eni also invested in the concept of taking account of all the aspect of remediation also outside the specific site and is currently planning its reclaiming actions protecting the environment at sustainable cost and creating value for communities.
Climate change and emissions Eni’s action plan for the mitigation of climate change, finalized in 2009, is based on projects for the reduction of gas flaring, for energy saving and increasing efficiency of industrial plants and R&D projects aimed at the containment of CO₂ emissions.
In particular Eni aims at:
- reducing gas flaring: the E&P division confirmed in its industrial plan the gas flaring reduction target of 70% by 2012 from 2007 levels. In order to reach this objective capital expenditures will be dedicate to new and modern infrastructure for gas transport, more efficient power plants and gas liquefaction plants;
- increasing efficiency in all areas: from production (including gas flaring/venting) to transport and energy conversion to final uses; the G&P division cooperates with its final customers by providing technical consultancy for energy saving actions;
- feasibility studies and planning in the field of renewables (photovoltaic, biomass, wind energy);
- capture and geological confinement of CO₂: in October 2008 Eni and Enel signed a strategic agreement for a first integrated project for the capture, transport and geological sequestration of CO₂;
- promotion of methane as vehicle fuel with low environmental impact that also allows to reduce CO₂ emissions as compared to other fuels;
- participation in European emission trading schemes that, in addition to monitoring compliance, require a focus on technical, economic and financial aspects of this trade performed by a team responsible for the control of greenhouse gas emissions;
- constant updating of internal procedures: Eni is currently updating its Protocol for accounting and reporting greenhouse gas emission under the new rules imposed by current laws and best practices and the API compendium.
Eni also signed a program agreement with the Ministry for the Environment within the environmental pact signed by other 10 large companies in Italy. Under this agreement approximately euro 450 million will be

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invested in the 2009-2013 period in the areas of energy saving, renewables, the distribution network for methane as vehicle fuel. Aim of this agreement is to save 160 ktoe/y of consumption and 459 ktoe CO₂/y from 2013.
In 2009 total greenhouse gas emissions in CO₂ tonnes, including CO₂ emissions from combustion and processes, methane emissions (converted into CO₂ using the Global Warming Potential of 21) and flaring and venting emissions decreased by 8% from 2008. The most significant decrease in the Exploration & Production segment, which accounts for 50% of total Eni emissions and reduced its emissions by 13% from 2008, resulted from reductions in flaring (down 20%) and venting (down 9%).

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THE FUTURE OF ENERGY AND INNOVATION

The future challenges of energy The availability of energy is crucial in supporting social and economic development worldwide. The energy industry has to face the challenge of the growth of energy requirements and relevant issues of energy interdependence, security of supplies and environmental impact of fossil fuel production and use.
The question of interdependence is crucial because it deeply affects the relationships between producing and consuming countries and is bound to become even more relevant in the long-term.
The diversification of producing areas and energy sources represents a necessary step to cope with the question of interdependence and security of supplies.
The diversification of production areas and energy sources is not a question of scarcity of resources, but rather of limited access, technical complexity and high costs. Conventional hydrocarbon resources that are technically recoverable can support current production levels for a few decades.
But Western oil companies have limited access to economical and plentiful resources, that are directly controlled by state owned companies and local governments. This leads to a reduction in opportunities for Western companies that tend to explore borderline areas (ultra deep waters, Arctic areas, complex geological structures) that are costly and technically difficult to bring to production.
This situation is complemented by the fact that renewable sources currently satisfy only a portion of energy requirement worldwide – 3% excluding biomass and waste – due to the low energy density and power produced at high cost based on currently available technologies. It is reasonable to assume that at least in the medium-term the cost of renewable energy will remain high and not competitive with traditional sources. It is difficult to economically support an industry, like generation from renewable sources, that requires subsidization for growing, also because in some cases the policies aimed at boosting the use of these sources can produce an increase in costs that is too high both for consumers and producers.
Furthermore, although renewable sources are growing at a considerable rate, they start from a very low contribution to overall consumption and will not be able to meet a high share of requirements unless relevant technological breakthroughs are obtained, as is foreseeable in the long-term.
The prevalence of fossil sources in the overall energy mix brings to the forefront the problem of the environmental impact of energy production. About 60% of current CO₂ emissions from human activities (about 38 billion tonnes in 2004) derive from the energy segment.
In order to win these challenges, it is necessary to work on the cornerstones represented by technological innovation and energy efficiency, also developing new forms of cooperation with producing countries and national oil companies.
Eni pays special attention to these aspects that directly affect the supply and consumption of energy and are crucial for mitigating their negative impact on the environment.
A strategy for innovation The consequences of the recent financial crisis and the related decline in energy consumption, environmental pressures for the containment of greenhouse gas

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emissions and the increase in use of renewable energy sources allow to outline a scenario without scarcity of oil and natural gas worldwide.
All this notwithstanding, the growth in consumption related to the accelerated industrialization of emerging countries, such as China and India, requires the development and dissemination of technologies that reduce the environmental impact of production and use of fossil fuels, leading to sustainable development. Consistent with this vision, Eni launched in 2006 an innovation strategy based on the following lines:
i) the "Along with petroleum" program to reach technological leadership in the exploitment of solar energy and the production of biofuels;
ii) the launch of the Blue Sky fund for financing research projects characterized by high technical risk, whose results can provide significant returns within Eni’s core business by means of technological discontinuities;
iii) a new approach to the enhancement and management of intellectual property, based on the recognition of the value of intellectual assets generated by R&D activities. In 2009 Eni filed 106 patent applications, with a 10% increase from 2008 and 54% from 2007. In particular, 24 applications were in the field of drilling and completion, geology/ geophysics of fields, engineering, mid/downstream; 3 applications concerned gas transport, 21 related to biofuels, catalysts and refining processes and the environment; 9 applications concerned solar energy and biomass and 15 concerned petrochemical technology;
iv) a new policy of strategic alliances and scientific cooperation projects with internationally renowned academic institutions and research centers aimed at reaching technological goals in less time and increasing knowledge and skills of Eni employees. An example is the research alliance with the Massachusetts Institute of Technology, Boston (USA), focused on innovative technology in the field of solar energy and on oil & gas issues and environmental sustainability. Eni also signed framework agreements with the Milan and Turin Polytechnic Schools and with the Italian Research Council (CNR);
v) establishment of the Eni Award for advanced research in the new frontiers of hydrocarbons, alternative and non conventional sources and environmental protection. The 2009 edition received 792 applications for its main prize, an 82% increase from 2008 and 374% increase from its first edition in 2007. It received 82 application for the prize for research debut from post doc students in 25 Italian universities.
Results achieved in 2009 In 2009 overall expenditure in R&D amounted to approximately euro 207 million, excluding general and administrative expenses (euro 217 million in 2008 and euro 208 million in 2007).
At December 31, 2009, a total of 1,019 persons were employed in research and development activities (1,098 in 2008). The following table describes the main results achieved in research and innovation.
Exploration & Production division Advanced exploration techniques
- Depth Velocity Analysis (DVA): Proprietary technology based on calculations on speed data from seismic prospecting for visualizing underground areas. In 2009 it has been successfully applied in Egypt and Angola.
- Depositational models for meandering channel systems: Proprietary technology based on geologic simulation codes that allows to build models on the more favorable conditions for hydrocarbon reservoirs. It has been successfully applied for the evaluation of mineral potential in fields in India and Angola.
- Uncertainty estimation for thinly bedded reservoir: This methodology has been successfully applied in Angola for estimating the production potential of a field as it allows to detail some parts of the subsoil.
- Coil Shooting: The interpretation of offshore seismic data collected with this technology (streamers pushed on spiraling routes instead of the traditional grid routes) confirmed the improvement that can be obtained in the definition of subsoil geology. Drilling technologies
- Dual casing running: In 2009 this technology has been successfully applied in West Africa. It allows to drill a well with two different diameters and inserting casings with different diameters at the same time, thus reducing completion time and risks.
- Radial drilling: This technology, applied by Eni in a pioneering effort, allows to increase production in heavy oil fields reducing also its footprinting. Drilling is performed radially from the main well with small diameter bores.

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Increase in recovery rates
- Enhanced oil recovery with CO₂ injection: In 2009 the research phase was completed and a field application is planned for 2010. CO₂ will be recovered from industrial plants near the fields.
- Bright water injection: This technology is based on an additive that is injected in the ground and selectively blocks the rock parts where water is present, thus potentially increasing the extraction of crude. A field test has been started with results scheduled for 2011. Marketing of marginal gas resources
- Gas to liquids (GtL): The GtL project, started in 1996 with IFP-Axens, turns natural gas into distillates. In 2009 the life test for the industrial catalyst for Fischer-Tropsch synthesis in the pilot plant at the Sannazzaro refinery has been completed, while the design has been started of a plant with a 15 bbl/d capacity.
- Monitoring of offshore pipelines (Dionisio project): Eni is developing a proprietary technology based on vibro-acoustic systems (patent application filed) capable of detecting damage to underwater pipelines. In 2009 a prototype has been installed at a gas import terminal. Accidental impact to the offshore pipeline confirmed the potential of this approach.
- TPI-intermediate pressure transport: Eni is examining the potential and maturity of this transport option that seems to have a shorter time to market than the TAP technology (high pressure transport, based on grade X100 pipes, still showing criticalities). The TPI project was started in 2008 with the production of the first grade X80 pipes by some world leading manufacturers. In 2009 other pipes have been bought and agreements have been signed for their welding. Tests on a real scale simulating operating conditions have been started. Conversion of heavy crude into lighter products (oil upgrading)
- Eni Slurry Technology (EST): The EST proprietary process consists in the conversion of heavy crudes and fractions into middle distillates for vehicles. As compared to the conversion technologies available on the market EST allows to fully convert feedstocks. In 2009 Eni continued testing this proprietary technology at the Taranto demonstration plant. Testing was mainly aimed at validating the upgrading performance and the plant operation. Innovative solutions for maximizing process yields have been devised. Construction is underway of an industrial plant with a capacity of 23,000 bbl/d at the Sannazzaro refinery with start-up expected in 2012.
- Flexible FCC (Fluid Catalytic Cracking): A proprietary material – the ERS-10 zeolite – has been developed and used as additive in an FCC catalyst thus increasing the conversion of heavier fractions. In 2009 the catalytic results have been confirmed and cooperation has started with a leading firm in FCC catalyst production aimed at industrial testing in an Eni refinery.
- Dual Catalyst Slurry System: Aim of this project is to develop a catalyst that further increases the conversion of heavy residues into fuels. The development of a bi-functional catalyst is underway that hydrogenates and desulphorates feesdtocks and increases the cracking rate and nitrogen removal.
- H₂S splitting: Aim of this project is the enhancement of hydrogen sulphide contained in natural gas or by-product of refining obtaining hydrogen from it. A promising technology consists in the decomposition of H₂S by means of cold plasma into sulphur and hydrogen. Lab activities were completed in 2009. Tests will be performed in a pilot plant in 2010.
- Downstream application of microwave technology for improving the features of heavy crude and cuts: Lab studies have been performed aimed at testing the possibility of significantly and permanently reducing the viscosity of crude, residues and bitumen improving their handling and reducing the use of flux oil by applying microwaves. Based on the results reached, in 2009 two patent applications have been filed. For 2010 tests on a continuous reactor are scheduled.
- Hydrogen: SCT-CPO (Short Contact Time-Catalytic Partial Oxidation) is a reforming technology that can convert gaseous and liquid hydrocarbons (also derived from biomass) into synthetic gas (carbon monoxide and hydrogen). This technology can contribute to process intensification as it allows to produce synthetic gas and hydrogen using reactors up to 100 times smaller than those currently in use with relevant savings.
Petrochemicals - Basic petrochemicals: A proprietary process for the selective hydrogenation of acetone to isopropylic alcohol has been successfully determined (the latter being later used for producing cumene).
- Polyethylene: The production of two new grades of LLDPE (linear low density polyethylene) has been transferred to industrial scale. These new polymers

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are produced by means of a proprietary catalysis and are used in the production of plastic films. On a pilot plant new polyethylenes have been produced using a new proprietary catalyst, these are HDPE (high density polyethylene) and LLDPE provided with good physical and mechanical properties and better processability.
- Elastomers: In cooperation with a primary producer of lubricant base oils, at pilot level new butadiene-styrene copolymers have been produced with improved viscosity index. On a pilot scale new grades of SBR (styrene-butadiene rubber) have been produced that improved performance in terms of adhesion and resistance to heating in tire materials.
- Styrenic polymers: On a pilot scale we completed the validation of production of HIPS (shock resistant polystyrene) and ABS (acrylonitryl-butadiene-styrene polymer) with anionic radical single stage polymerization. At the Mantova plant we completed the first test production of a new EPS (continuous mass expandable polystyrene) in the new 38,000 tonnes/y plant with the new PE proprietary technology. At the Dunastyr site (Hungary) a white improved EPS type has been successfully industrialized that shows higher insulating power with unchanged mechanical properties (called VERDI) exclusively produced by PE.
Environment and efficiency - New formulas for fuels and lubricants: The development of the new premium products of the Blu line has been completed. Tests were performed on engines and vehicles in order to optimize engine efficiency and reducing noxious emissions. Tests of the new premium gasoline were performed on new Fiat Multiair engines in the framework of an agreement with the Fiat research center. In 2009 two new lubricants that reduce consumption and emissions reached the commercial stage.
- GHG program (green house gas): Eni organized meetings with the people living in the area of Cortemaggiore aimed at informing them on the pending capture and sequestration of CO₂ in the subsoil of the municipality.
- Zero waste: For the treatment of oily and biological waste generated by the oil industry a thermal process is under study that allows for the gasification of slime that is turned into an inert residue. A patent application has been filed on this project. Basic design has been completed of pilot plant with a 50 kg/h capacity along with a feasibility study for an annual volume of 5,000 tonnes of slime.
- Ensolvex process: In the framework of the cleaning up of an area within the Gela refinery Eni plans to build an Ensolvex plant for the reclaiming of soil polluted by hydrocarbons within the limits imposed by the law. The design phase has been completed in 2009 and the plant is expected to be built by the first half of 2010.
- En-Z-lite process: In 2009 at the Taranto refinery a demonstration plant has been tested for removing organic compounds from water by means of adsorption on synthetic hydrophobic zeolites complying with the most stringent standards on MTBE and TPH levels as well as metal content. This technology can be used for treating underground waters and for steam production. A new system for regenerating zeolites has been patented.
Renewable energy sources - Green Diesel: In 2009 tests have been started for using non-food feedstock in the Ecofining^TM process, that has already been used with traditional vegetable oils at industrial level.
- Biodiesel by means of micro algae: The project aims at testing the technical and economic feasibility of a process based on the biofixation of CO₂ by means of micro algae for the purification of discharge waters with production of biomass that can be converted into biofuel. A pilot plant is nearing start-up at the Gela refinery.
- Biodiesel from waste: In the field of better use of biomass for energy production, Eni is developing an integrated thermal-fermenting process for the conversion of the organic fraction of urban waste into bio-oil.
- Micro-organisms for diesel: Aim of the project is the identification of micro-organisms that metabolize organic substances and produce lipids, optimal precursors of biodiesel. A yeast has been identified that can grow efficiently on all the sugars present in wood-cellulose biomass and accumulates lipids up to 75% of its weight, thus improving the results obtained in 2008 (60%).
- Photoactive materials: In 2009 the first samples were obtained of devices allowing to use a much smaller surface of silicon as compared to conventional photovoltaic technology, at parity of power produced, with a potential cost reduction for electricity generation. this result was obtained by using dull, transparent or colored

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plates including adequate substances playing a double role: converting solar light, concentrating and carrying light to the edges of the plate where silicon is located and converts radiating energy into electricity. The conversion of light is exerted on components of solar radiation that are usually underused by traditional silicon materials, converting them into radiation with a wavelength that can induce a photovoltaic effect. These results are expected to be consolidated in 2010 thus testing the reproducibility and stability of the process and preparing large prototypes.

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Glossary

The glossary of oil and gas terms is available on Eni’s web page at the address www.eni.com. Below is a selection of the most frequently used terms. FINANCIAL TERMS Dividend Yield Measures the return on a share based on dividends for the year. Calculated as the ratio of dividends per share of the year and the average reference price of shares in the last month of the year. Generally, companies tend to keep a constant dividend yield, as shareholders compare this indicator with the yield of other shares or other financial instruments (e.g. bonds). Leverage Is a measure of a company’s debt, calculated as the ratio between net financial debt and shareholders’ equity, including minority interests. ROACE Return On Average Capital Employed Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed. TSR Total Shareholder Return Measures the total return of a share calculated on a yearly basis, keeping account of changes in prices (beginning and end of year) and dividends distributed and reinvested at the ex-dividend date. OIL AND NATURAL GAS ACTIVITIES Average reserve life index Ratio between the amount of reserves at the end of the year and total production for the year. Barrel Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons. Boe (Barrel of Oil Equivalent) Is used as a standard unit measure for oil and natural gas. The latter is converted from standard cubic meters into barrels of oil equivalent using a coefficient equal to 0.00615. Concession contracts Contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production. The company holding the mining concession has an exclusive on mining activities and for this reason it acquires a right on hydrocarbons extracted, against the payment of royalties to the State on production and taxes on oil revenues. Condensates These are light hydrocarbons produced along with gas, that condense to a liquid state at normal temperature and pressure for surface production facilities.

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Contingent resources Amounts of oil and gas estimated at a given date that are potentially recoverable by means of development projects that are not considered commercially recoverable due to one or more contingency. Deep waters Waters deeper than 200 meters. Development Drilling and other post-exploration activities aimed at the production of oil and gas. Elastomers (or Rubber) Polymers, either natural or synthetic, which, unlike plastic, when stress is applied, return, to a certain degree, to their original shape, once the stress ceases to be applied. The main synthetic elastomers are polybutadiene (BR), styrene-butadiene rubber (SBR), ethylene-propylene rubber (EPR), thermoplastic rubber (TPR) and nitrylic rubber (NBR). Enhanced recovery Techniques used to increase or stretch over time the production of wells. EPC (Engineering, Procurement, Construction) A contract typical of onshore construction of large plants in which the contractor supplies engineering, procurement and construction of the plant. The contract is defined "turnkey" when the plant is supplied for start-up. EPIC (Engineering, Procurement, Installation, Commissioning) A contract typical of offshore construction of complex projects (such as the installation of production platforms or FPSO systems) in which the global or main contractor, usually a company or a consortium of companies, supplies engineering, procurement, construction of plant and infrastructure, transport to the site and all preparatory activities for the start-up of plants. Exploration Oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis, and well drilling. FPSO vessel Floating, Production, Storage and Offloading system made up of a large capacity oil tanker including a large hydrocarbon treatment plant. This system, moored at the bow in order to maintain a geostationary position, is in fact a temporary fixed platform linking the underwater wellheads to the treatment, storage and offloading systems onboard by means of risers from the seabed. Infilling wells Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels. LNG Liquefied Natural Gas obtained through the cooling of natural gas to minus 160°C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed and consumed. One ton of LNG corresponds to 1,400 cubic meters of gas. LPG Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression. Mineral Potential (Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage. Mineral Storage Volumes of natural gas required for allowing optimal operation of natural gas fields in Italy for technical and economic reasons. Modulation Storage Volumes of natural gas required for meeting hourly, daily and seasonal swings of demand. Natural gas liquids Liquid or liquefied hydrocarbons recovered from natural gas through separation

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equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that used to be defined natural gasoline, are natural gas liquids. Network Code A code containing norms and regulations for access to, management and operation of natural gas pipelines. Offshore/Onshore The term offshore indicates a portion of open sea and, by induction, the activities carried out in such area, while onshore refers to land operations. Olefins (or Alkenes) Hydrocarbons that are particularly active chemically, used for this reason as raw materials in the synthesis of intermediate products and of polymers. Over/Underlifting Agreements stipulated between partners regulate the right of each to its share in the production of a set period of time. Amounts different from the agreed ones determine temporary Over/Underlifting situations. Possible reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Probable reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Production Sharing Agreement Contract in use in non OECD countries, regulating relationships between States and oil companies with regard to the exploration and production of hydrocarbons. The mining concession is assigned to the national oil company jointly with the foreign oil company who has exclusive right to perform exploration, development and production activities and can enter agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "cost oil" is used to recover costs borne by the contractor, "profit oil" is divided between contractor and national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions may vary from one country to the other. 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 know reservoirs, and under existing economic conditions. 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. Reserves Quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods. Reserve replacement ratio Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates,

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enhanced recovery, improvement in recovery rates and changes in the value of reserves – in PSAs – due to changes in international oil prices. Management also calculates this ratio by excluding the effect of the purchase of proved property in order to better assess the underlying performance of the Company’s operations. Ship-or-pay Clause included in natural gas transportation contracts according to which the customer for which the transportation is carried out is bound to pay for the transportation of the gas also in case the gas is not transported. Strategic Storage Volumes of natural gas required for covering lack or reduction of supplies from extra-European sources or crises in the natural gas system. Swap In the gas sector, the term is referred to a buy/sell contract between some counterparties and is generally aimed to the optimization of transport costs and respective commitments in purchasing and supplying. Take-or-pay Clause included in natural gas purchase contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of the gas set in the contract also in case it is not collected by the customer. The customer has the option of collecting the gas paid and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years. Upstream/Downstream The term upstream refers to all hydrocarbon exploration and production activities. The term downstream includes all activities inherent to the oil sector that are downstream of exploration and production activities. Wholesale sales Domestic sales of refined products to wholesalers/distributors (mainly gasoil), public administrations and end consumers, such as industrial plants, power stations (fuel oil), airlines (jet fuel), transport companies, big buildings and households. They do not include distribution through the service station network, marine bunkering, sales to oil and petrochemical companies, importers and international organizations. Workover Intervention on a well for performing significant maintenance and substitution of basic equipment for the collection and transport to the surface of liquids contained in a field. ABBREVIATIONS mmcf = million cubic feet
bcf = billion cubic feet
mmcm = million cubic meters
bcm = billion cubic meters
boe = barrel of oil equivalent
kboe = thousand barrel of oil equivalent
mmboe = million barrel of oil equivalent
bboe = billion barrel of oil equivalent
bbl = barrels
kbbl = thousand barrels
mmbbl = million barrels
bbbl = billion barrels
mmtonnes = million tonnes
ktonnes = thousand tonnes
/d = per day
/y = per year

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Balance sheet

Dec. 31, 2008 Dec. 31, 2009

(euro million) Note Total amount of which with related parties Total amount of which with related parties

ASSETS
Current assets
Cash and cash equivalents	(1)	1,939			1,608
Other financial assets held for trading or available for sale:	(2)
- equity instruments		2,741
- other securities		495			348
		3,236			348
Trade and other receivables	(3)	22,222		1,539	20,348		1,355
Inventories	(4)	6,082			5,495
Current tax assets	(5)	170			753
Other current tax assets	(6)	1,130			1,270
Other current assets	(7)	1,870		59	1,307		9
Total current assets		36,649			31,129
Non-current assets
Property, plant and equipment	(8)	59,255			63,177
Inventory - compulsory stock	(9)	1,196			1,736
Intangible assets	(10)	7,697			8,057
Equity-accounted investments	(11)	5,471			5,828
Other investments	(11)	410			416
Other financial assets	(12)	1,134		356	1,148		438
Deferred tax assets	(13)	2,912			3,558
Other non-current receivables	(14)	1,881		21	1,938		40
Total non-current assets		79,956			85,858
Assets held for sale	(25)	68			542
TOTAL ASSETS		116,673			117,529
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	(15)	6,359		153	3,545		147
Current portion of long-term debt	(20)	549			3,191
Trade and other payables	(16)	20,515		1,253	19,174		1,241
Income taxes payable	(17)	1,949			1,291
Other taxes payable	(18)	1,660			1,431
Other current liabilities	(19)	3,863		4	1,856		5
Total current liabilities		34,895			30,488
Non-current liabilities
Long-term debt	(20)	13,929		9	18,064
Provisions for contingencies	(21)	9,506			10,319
Provisions for employee benefits	(22)	947			944
Deferred tax liabilities	(23)	5,784			4,907
Other non-current liabilities	(24)	3,102		53	2,480		49
Total non-current liabilities		33,268			36,714
Liabilities directly associated with assets held for sale	(25)				276
TOTAL LIABILITIES		68,163			67,478
SHAREHOLDERS' EQUITY	(26)
Minority interest		4,074			3,978
Eni shareholders' equity
Share capital		4,005			4,005
Reserves		40,722			46,269
Treasury shares		(6,757	)		(6,757	)
Interim dividend		(2,359	)		(1,811	)
Net profit		8,825			4,367
Total Eni shareholders' equity		44,436			46,073
TOTAL SHAREHOLDERS' EQUITY		48,510			50,051
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		116,673			117,529

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Profit and loss account

2007 2008 2009

(euro million) Note Total amount of which with related parties Total amount of which with related parties Total amount of which with related parties

REVENUES
Net sales from operations	(29)	87,204		4,198		108,082		5,048		83,227		3,300
Other income and revenues		833				728		39		1,118		26
Total revenues		88,037				108,810				84,345
OPERATING EXPENSES	(30)
Purchases, services and other		58,133		3,777		76,350		6,298		58,351		4,999
- of which non-recurring charge		91				(21	)			250
Payroll and related costs		3,800				4,004				4,181
- of which non-recurring income		(83	)
OTHER OPERATING (CHARGE) INCOME		(129	)	10		(124	)	58		55		44
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS		7,236				9,815				9,813
OPERATING PROFIT		18,739				18,517				12,055
FINANCE INCOME (EXPENSE)	(31)
Finance income		4,445		49		7,985		42		5,950		27
Finance expense		(4,554	)	(20	)	(8,198	)	(17	)	(6,497	)	(4	)
Derivative financial instruments		155				(427	)			(4	)
		46				(640	)			(551	)
INCOME (EXPENSE) FROM INVESTMENTS	(32)
Share of profit (loss) of equity-accounted investments		773				640				393
Other gain (loss) from investments		470				733				176
		1,243				1,373				569
PROFIT BEFORE INCOME TAXES		20,028				19,250				12,073
Income taxes	(33)	(9,219	)			(9,692	)			(6,756	)
Net profit		10,809				9,558				5,317
Attributable to:
- Eni		10,011				8,825				4,367
- Minority interest	(26)	798				733				950
		10,809				9,558				5,317
Earnings per share attributable to Eni (euro per share)	(34)
Basic		2.73				2.43				1.21
Diluted		2.73				2.43				1.21

172

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statement of comprehensive income

(euro million) Note 2007 2008 2009

Net profit		10,809		9,558		5,317
Other items of comprehensive income
Foreign currency translation differences		(1,980	)	1,077		(869	)
Change in the fair value of cash flow hedging derivatives	(26)	(2,237	)	1,969		(481	)
Change in the fair value of available-for-sale securities	(26)	(6	)	3		1
Share of "Other comprehensive income" on equity-accounted entities						2
Taxation	(26)	869		(767	)	202
Other comprehensive income		(3,354	)	2,282		(1,145	)
Total comprehensive income		7,455		11,840		4,172
Attributable to:
- Eni		6,708		11,148		3,245
- Minority interest		747		692		927
		7,455		11,840		4,172

173

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statements of changes in shareholders’ equity

Eni shareholders’ equity

(euro million) Share capital Legal reserve of Eni SpA Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the fair value of available-for-sale securities net of the tax effect Other reserves Cumulative currency translation
differences Treasury shares Retained earnings Interim dividend Net profit for the year Total Minority interest Total shareholders’ equity

Balance at December 31, 2006	4,005	959	7,262		1		6		393	(398	)	(5,374	)	25,168		(2,210	)	9,217		39,029		2,170		41,199
Net profit for the year																		10,011		10,011		798		10,809
Other items of comprehensive income
Change in the fair value of cash flow hedge derivatives net of the tax effect					(1,370	)														(1,370	)			(1,370	)
Change in the fair value of available-for-sale securities net of the tax effect							(4	)												(4	)			(4	)
Foreign currency translation differences					25					(1,835	)			(119	)					(1,929	)	(51	)	(1,980	)
					(1,345	)	(4	)		(1,835	)			(119	)					(3,303	)	(51	)	(3,354	)
Total recognized income and (expense) for the year					(1,345	)	(4	)		(1,835	)			(119	)			10,011		6,708		747		7,455
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.65 per share in settlement of 2006 interim dividend of euro 0.60 per share)																2,210		(4,594	)	(2,384	)			(2,384	)
Interim dividend distribution of Eni SpA (euro 0.60 per share)																(2,199	)			(2,199	)			(2,199	)
Dividend distribution of other companies																						(289	)	(289	)
Payments by minority shareholders																						1		1
Allocation of 2006 net profit														4,623				(4,623	)
Shares repurchased												(680	)							(680	)			(680	)
Net effect related to the purchase of treasury shares by Saipem SpA and Snam Rete Gas SpA																						(201	)	(201	)
Treasury shares sold under incentive plans for Eni managers			(55	)					35			55		11						46				46
Difference between the carrying amount and strike price of stock options exercised by Eni managers														9						9				9
			(55	)					35			(625	)	4,643		11		(9,217	)	(5,208	)	(489	)	(5,697	)
Other changes in shareholders’ equity
Cost related to stock options and stock grant														18						18				18
Other changes														(119	)					(119	)	11		(108	)
														(101	)					(101	)	11		(90	)
Balance at December 31, 2007	4,005	959	7,207		(1,344	)	2		428	(2,233	)	(5,999	)	29,591		(2,199	)	10,011		40,428		2,439		42,867

174

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statements of changes in shareholders’equitycontinued

Eni shareholders’ equity

(euro million) Share capital Legal reserve of Eni SpA Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the fair value of available-for-sale securities net of the tax effect Other reserves Cumulative currency translation
differences Treasury shares Retained earnings Interim dividend Net profit for the year Total Minority interest Total shareholders’ equity

Balance at December 31, 2007	4,005	959	7,207		(1,344	)	2	428		(2,233	)	(5,999	)	29,591		(2,199	)	10,011		40,428		2,439		42,867
Net profit for the year																		8,825		8,825		733		9,558
Gains (losses) recognized directly in equity
Change in the fair value of cash flow hedge derivatives net of the tax effect					1,255															1,255		(52	)	1,203
Change in the fair value of available-for-sale securities net of the tax effect							2													2				2
Foreign currency translation differences					25					1,264				(223	)					1,066		11		1,077
					1,280		2			1,264				(223	)					2,323		(41	)	2,282
Total recognized income and (expense) for the year					1,280		2			1,264				(223	)			8,825		11,148		692		11,840
Transactions with shareholders
Dividend distribution of Eni SpA (euro 0.70 per share in settlement of 2007 interim dividend of euro 0.60 per share)																2,199		(4,750	)	(2,551	)			(2,551	)
Interim dividend distribution of Eni SpA (euro 0.65 per share)																(2,359	)			(2,359	)			(2,359	)
Dividend distribution of other companies																						(297	)	(297	)
Payments by minority shareholders																						20		20
Allocation of 2007 net profit														5,261				(5,261	)
Shares repurchased												(778	)							(778	)			(778	)
Treasury shares sold under incentive plans for Eni managers			(20	)				13				20		(1	)					12				12
Difference between the carrying amount and strike price of stock options exercised by Eni managers														2						2				2
Net effect related to the purchase of treasury shares by Saipem SpA																						(31	)	(31	)
Put option granted to Publigaz SCRL (the Distrigas NV minority shareholder)								(1,495	)											(1,495	)			(1,495	)
Minority interest recognized following the acquisition of Distrigas NV and Hindustan Oil Exploration Co Ltd																						1,261		1,261
			(20	)				(1,482	)			(758	)	5,262		(160	)	(10,011	)	(7,169	)	953		(6,216	)
Other changes in shareholders’ equity
Cost related to stock options and stock grant														18						18				18
Other changes					(26	)								37						11		(10	)	1
					(26	)								55						29		(10	)	19
Balance at December 31, 2008 (Note 26)	4,005	959	7,187		(90	)	4	(1,054	)	(969	)	(6,757	)	34,685		(2,359	)	8,825		44,436		4,074		48,510

175

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statements of changes in shareholders’ equitycontinued

Eni shareholders’ equity

(euro million) Share capital Legal reserve of Eni SpA Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the fair value of available-for-sale securities net of the tax effect Other reserves Cumulative currency translation
differences Treasury shares Retained earnings Interim dividend Net profit for the year Total Minority interest Total shareholders’ equity

Balance at December 31, 2008 (Note 26)	4,005	959	7,187		(90	)	4	(1,054	)	(969	)	(6,757	)	34,685		(2,359	)	8,825		44,436		4,074		48,510
Net profit for the year																		4,367		4,367		950		5,317
Gains (losses) recognized directly in equity
Change in the fair value of cash flow hedge derivatives net of the tax effect (Note 26)					(279	)														(279	)			(279	)
Change in the fair value of available-for-sale securities net of the tax effect (Note 26)							1													1				1
Share of "Other comprehensive income" on equity-accounted entities								2												2				2
Foreign currency translation differences					1					(696	)			(151	)					(846	)	(23	)	(869	)
					(278	)	1	2		(696	)			(151	)					(1,122	)	(23	)	(1,145	)
Total recognized income and (expense) for the year					(278	)	1	2		(696	)			(151	)			4,367		3,245		927		4,172
Transactions with shareholders:
Dividend distribution of Eni SpA (euro 0.65 per share in settlement of 2007 interim dividend of euro 0.65 per share)																2,359		(4,714	)	(2,355	)			(2,355	)
Interim dividend distribution of Eni SpA (euro 0.50 per share)																(1,811	)			(1,811	)			(1,811	)
Dividend distribution of other companies																						(350	)	(350	)
Payments by minority shareholders																						1,560		1,560
Allocation of 2008 net profit														4,111				(4,111	)
Put option granted to Publigaz SCRL (the Distrigas NV minority shareholder)								1,495												1,495				1,495
Effect related to the purchase of Italgas SpA and Stoccaggi Gas SpA by Snam Rete Gas SpA								1,086												1,086		(1,086	)
Minority interest acquired following the mandatory tender offer and the squeeze-out on the shares of Distrigas NV																						(1,146	)	(1,146	)
								2,581						4,111		548		(8,825	)	(1,585	)	(1,022	)	(2,607	)
Other changes in shareholders’ equity
Utilization of the reserve for the acquisition of treasury shares			(430	)				1						429
Cost related to stock options and stock grant														13						13				13
Stock option expired														(7	)					(7	)			(7	)
Other changes					(71	)		(38	)					80						(29	)	(1	)	(30	)
			(430	)	(71	)		(37	)					515						(23	)	(1	)	(24	)
Balance at December 31, 2009 (Note 26)	4,005	959	6,757		(439	)	5	1,492		(1,665	)	(6,757	)	39,160		(1,811	)	4,367		46,073		3,978		50,051

176

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statement of cash flows

(euro million) Note 2007 2008 2009

Net profit of the year		10,809		9,558		5,317
Depreciation, depletion and amortization	(30)	7,029		8,422		8,762
Revaluations, net		(494	)	2,560		495
Net change in provisions for contingencies		(122	)	414		574
Net change in the provisions for employee benefits		(67	)	(8	)	16
Gain on disposal of assets, net		(309	)	(219	)	(226	)
Dividend income	(32)	(170	)	(510	)	(164	)
Interest income		(603	)	(592	)	(352	)
Interest expense		523		809		603
Exchange differences		(119	)	(319	)	(156	)
Income taxes	(33)	9,219		9,692		6,756
Cash generated from operating profit before changes in working capital		25,696		29,807		21,625
(Increase) decrease:
- inventories		(1,117	)	(801	)	52
- trade and other receivables		(655	)	(974	)	(19	)
- other assets		(362	)	162		(472	)
- trade and other payables		360		2,318		(1,201	)
- other liabilities		107		1,507		(129	)
Cash from operations		24,029		32,019		19,856
Dividends received		658		1,150		576
Interest received		333		266		594
Interest paid		(555	)	(852	)	(583	)
Income taxes paid, net of tax receivables received		(8,948	)	(10,782	)	(9,307	)
Net cash provided from operating activities		15,517		21,801		11,136
- of which with related parties	(36)	549		(62	)	(1,188	)
Investing activities:
- tangible assets	(8)	(8,532	)	(12,312	)	(12,300	)
- intangible assets	(10)	(2,061	)	(2,250	)	(1,395	)
- consolidated subsidiaries and businesses		(4,759	)	(3,634	)	(25	)
- investments	(11)	(4,890	)	(385	)	(230	)
- securities		(76	)	(152	)	(2	)
- financing receivables		(1,646	)	(710	)	(972	)
- change in payables and receivables in relation to investments and capitalized depreciation		185		367		(97	)
Cash flow from investments		(21,779	)	(19,076	)	(15,021	)
Disposals:
- tangible assets		172		318		126
- intangible assets		28		2		250
- consolidated subsidiaries and businesses		56		149
- investments		403		510		3,219
- securities		491		145		164
- financing receivables		545		1,293		861
- change in payables and receivables in relation to disposals		(13	)	(299	)	147
Cash flow from disposals		1,682		2,118		4,767
Net cash used in investing activities (*)		(20,097	)	(16,958	)	(10,254	)
- of which with related parties	(36)	(822	)	(1,598	)	(1,262	)

177

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

Statement of cash flows continued

(euro million) Note 2007 2008 2009

Proceeds from long-term debt		6,589		3,774		8,774
Repayments of long-term debt		(2,295	)	(2,104	)	(2,044	)
Increase (decrease) in short-term debt		4,467		(690	)	(2,889	)
		8,761		980		3,841
Net capital contributions by minority shareholders		1		20		1,551
Net acquisition of treasury shares different from Eni SpA		(340	)	(50	)	9
Acquisition of additional interests in consolidated subsidiaries		(16	)			(2,068	)
Dividends paid to Eni's shareholders		(4,583	)	(4,910	)	(4,166	)
Dividends paid to minority interest		(289	)	(297	)	(350	)
Net purchase of treasury shares		(625	)	(768	)
Net cash used in financing activities		2,909		(5,025	)	(1,183	)
- of which with related parties	(36)	20		14		(14	)
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)		(40	)	(1	)
Effect of exchange rate changes on cash and cash equivalents and other changes		(160	)	8		(30	)
Net cash flow for the period		(1,871	)	(175	)	(331	)
Cash and cash equivalents - beginning of year	(1)	3,985		2,114		1,939
Cash and cash equivalents - end of year	(1)	2,114		1,939		1,608

(*) Net cash used in investing activities included investments in certain financial assets to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. For the definition of net borrowings, see "Financial Review" in the "Report of the Directors".
Cash flows of such investments were as follows:

(euro million) 2007 2008 2009

Financing investments:
- securities	(75	)	(74	)	(2	)
- financing receivables	(970	)	(99	)	(36	)
	(1,045	)	(173	)	(38	)
Disposal of financing investments:
- securities	419		145		123
- financing receivables	147		939		311
	566		1,084		434
Net cash flows from financing activities	(479	)	911		396

178

ENI ANNUAL REPORT / CONSOLIDATED FINANCIAL STATEMENTS

SUPPLEMENTAL CASH FLOW INFORMATION

(euro million) 2007 2008 2009

Effect of investment of companies included in consolidation and businesses
Current assets	398		1,938		7
Non-current assets	5,590		7,442		47
Net borrowings	1		1,543		4
Current and non-current liabilities	(972	)	(3,598	)	(29	)
Net effect of investments	5,017		7,325		29
Minority interests			(1,261	)
Fair value of investments held before the acquisition of control	(13	)	(601	)
Sale of unconsolidated entities controlled by Eni
Purchase price	5,004		5,463		29
less:
Cash and cash equivalents	(245	)	(1,829	)	(4	)
Cash flow on investments	4,759		3,634		25
Effect of disposal of consolidated subsidiaries and businesses
Current assets	73		277
Non-current assets	20		299
Net borrowings	26		(118	)
Current and non-current liabilities	(94	)	(270	)
Net effect of disposals	25		188
Gain on disposal	33		25
Minority interest			(1	)
Selling price	58		212
less:
Cash and cash equivalents	(2	)	(63	)
Cash flow on disposals	56		149

Transactions that did not produce cash flows
Acquisition of equity investments in exchange of businesses contribution:

(euro million) 2007 2008 2009

Current assets
Non-current assets	38
Net borrowings	(4	)
Long-term and short-term liabilities
Net effect of contribution	34
Minority interest
Gain on contribution
Acquisition of investments	34

179

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Basis of presentation

The Consolidated Financial Statements of Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and adopted by the European Union (EU) pursuant to Article 6 of the EC Regulation No. 1606/2002 of the European Parliament and Council of July 19, 2002 and in accordance with Article 9 of Legislative Decree No. 38/2005¹. Oil and natural gas exploration and production activity is accounted for in conformity with internationally accepted accounting principles. Specifically, this concerns the determination of the amortization expenses using the unit-of-production method and the recognition of the production-sharing agreements and buy-back contracts. The Consolidated Financial Statements have been prepared on a historical cost basis except for certain items that under IFRS must be recognized at fair value as described in the summary of significant accounting policies paragraph. The Consolidated Financial Statements include the statutory accounts of Eni SpA and the accounts of controlled subsidiary companies where the company holds the right to directly or indirectly exercise control, determine financial and management decisions and obtain economic and financial benefits. Immaterial subsidiaries are not consolidated. A subsidiary is generally considered to be immaterial when it does not exceed two of the following three limits: (i) total assets or liabilities: euro 3,125 thousand; (ii) total revenues: euro 6,250 thousand; and (iii) average number of employees: 50 units. Moreover, companies for which consolidation does not produce significant economic and financial effects are not consolidated. These are essentially entities acting as sole-operator in the management of oil and gas contracts on behalf of companies participating in a joint venture. These are financed proportionately based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenues and other operating data (production, reserves, etc.) of the project, as well as the obligations arising from the project, are recognized proportionally in the financial statements of the companies involved. The effects of these exclusions are immaterial². Immaterial subsidiaries excluded from consolidation, jointly controlled entities, associates and other interests are accounted for as described below under the item "Financial fixed assets". Subsidiaries’ financial statements are audited by the independent auditors who examine and certify also the information required for the preparation of the Consolidated Financial Statements. The 2009 Consolidated Financial Statements approved by Eni’s Board of Directors on March 11, 2010 were audited by the independent auditor PricewaterhouseCoopers SpA (PwC) who reviewed disclosed information. The independent auditor of Eni SpA, as the main auditor of the Group, is in charge of the auditing activities of the subsidiaries, unless this is incompatible with local laws, and, to the extent allowed under Italian legislation, of the work of other independent auditors. Amounts in the notes to these financial statements are expressed in millions of euros (euro million).

Principles of consolidation

Interest in consolidated companies
Assets and liabilities, revenues and expenses related to fully consolidated subsidiaries are wholly incorporated in the Consolidated Financial Statements; the book value of interests in these subsidiaries is eliminated against the corresponding share of the shareholders’ equity by attributing to each of the balance sheet items its fair value at the acquisition date. When acquired, the net equity of controlled subsidiaries is initially recognized at fair value. The excess of the purchase price of an acquired entity over the total fair value assigned to assets acquired and liabilities assumed is recognized as goodwill; negative goodwill is recognized in the profit and loss account. Equity and net profit of minority shareholders are included in specific lines of the financial statements; this share of equity is determined using the fair value of assets and liabilities, excluding any related goodwill, at the time when control is acquired. The purchase of additional ownership interests in subsidiaries from minority shareholders is recognized as goodwill and represents the excess of the amount paid over the carrying value of the minority interest acquired. Gains or losses associated with the sale of interests in consolidated subsidiaries are reflected in the profit and loss account for the difference between the proceeds from the sale and the divested portion of net equity.

(1)

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, the Consolidated Financial Statements are fully compliant with IFRS as issued by the IASB and effective for the year 2009 with the exception of IFRIC 12 "Service Concession Arrangements" and IFRIC 18 "Transfers of Assets from Customers" (see also "Recent Accounting Principles" paragraph).

(2)

According to the requirements of the Framework of international accounting standards, information is material if its omission or misstatement could influence the economic decisions that users make on the basis of the financial statements.

180

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Inter-company transactions
Inter-company transactions, balances and unrealized gains on transactions between group companies are eliminated. Unrealized losses are not eliminated since they are considered an impairment indicator of the asset transferred.

Foreign currency translation
Financial statements of foreign companies having a functional currency other than the euro are translated into the presentation currency using closing exchange rates for assets and liabilities, historical exchange rates for equity accounts and average rates for the period for the profit and loss account (source: Bank of Italy). Cumulative exchange rate differences resulting from this translation are recognized in shareholders’ equity under "Other reserves" in proportion to the Group’s interest and under "Minority interest" for the portion related to minority shareholders. Cumulative exchange rate differences are charged to the profit and loss account when the investments are sold or the capital employed is repaid. Financial statements of foreign subsidiaries which are translated into the euro are denominated in the functional currencies of the countries where the entities operate. The U.S. dollar is the prevalent functional currency for the entities that do not adopt euro.

Summary of significant accounting policies

The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below.

Current assets
Held for trading financial assets and available-for-sale financial assets are measured at fair value with gains or losses recognized in the profit and loss account under "Financial income (expense)" and to the equity reserve related to other comprehensive income, respectively. In the latter case, changes in fair value recognized in equity are charged to the profit and loss account when they are impaired or realized. The objective evidence that an impairment loss has occurred is verified considering, interalia, significant breaches of contracts, serious financial difficulties or the high probability of insolvency of the counterparty; asset write downs are included in the carrying amount³.
Available-for-sale financial assets include financial assets other than derivative financial instruments, loans and receivables, held for trading financial assets, held-to-maturity financial assets and, if applicable, investments associated with a derivative financial instrument. The latter are stated at fair value with effects of changes in fair value recognized in the profit and loss account rather than shareholders’ equity (the so-called "fair value option") in order to ensure a match with the recognition in the profit and loss account for the changes in fair value of the derivative instrument⁴. The fair value of financial instruments is determined by market quotations or, in their absence, by the value resulting from the adoption of suitable financial valuation models which take into account all the factors adopted by market operators and prices obtained in similar recent transactions in the market. Interests and dividends on financial assets stated at fair value with gains or losses reflected in the profit and loss account are accounted for on an accrual basis in "Financial income (expense)" and "Other gain (loss) from investments", respectively. When the purchase or sale of a financial asset under a contract whose terms require delivery of the asset within the time frame generally established by regulation or convention in the market place concerned, the transaction is accounted for on the settlement date. Receivables are carried at amortized cost (see item "Financial fixed assets" below). Transferred financial assets are derecognized when the contractual rights to receive the cash flows of the financial assets are transferred together with the risks and rewards of the ownership.
Inventories, including compulsory stocks and excluding contract work in progress, are stated at the lower of purchase or production cost and net realizable value. Net realizable value is the estimated selling price less the costs to sell, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual sale price. The cost for inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted-average cost method on a three-month basis, or monthly, when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost for inventories of the Petrochemical segment is determined by applying the weighted-average cost on an annual basis. Contract work in progress is measured using the

(3)

By EU Commission Regulation No. 1004/2008 of October 15, 2008, amendments to IAS 39 "Financial Instruments: Recognition and Measurement" and to IFRS 7 "Financial Instruments: Disclosures" were endorsed. The amendments permit, with certain criteria met, an entity to reclassify held for trading and available-for-sale financial assets into financial instruments valuated at cost or at amortized cost. The change has not produced any effect for Eni.

(4)

Regarding the investment in OAO Gazprom Neft see Note 2 – Other financial assets held for trading or available for sale.

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cost-to-cost method whereby contract revenue is recognized based on the stage of completion as determined by the cost incurred. Advances are deducted from inventories within the limits of contractual considerations; any excess of such advances over the value of the inventories is recorded as a liability. Losses related to construction contracts are accrued for once the company becomes aware of such losses. Contract work in progress not yet invoiced, whose payment will be made in a foreign currency, is translated to euro using the current exchange rates at year end and the effect of rate changes is reflected in the profit and loss account.
When take-or-pay clauses are included in long term natural gas purchase contracts, uncollected gas volumes which imply the "pay" clause, measured using the price formulas contractually defined, are recognized under "Other assets" as "Deferred costs" as an offset to "Trade payables" or, after the settlement, to "Cash and Cash equivalents".
The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually delivered – the related cost is included in the determination of the weighted-average cost of inventories and (ii) for the portion which is not recoverable, when it is not possible to collect gas that was previously uncollected within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizable value, measured adopting the same criteria described for inventories.
Hedging instruments are described in the section "Derivative Instruments".

Non-current assets

Property, plant and equipment⁵
Tangible assets, including investment properties, are recognized using the cost model and stated at their purchase or self-construction cost including any costs directly attributable to bringing the asset into operation. In addition, when a substantial period of time is required to make the asset ready for use, the purchase price or self-construction cost includes the borrowing costs incurred that could have otherwise been saved had the investment not been made. In the case of a present obligation for the dismantling and removal of assets and the restoration of sites, the carrying value includes, with a corresponding entry to a specific provision, the estimated (discounted) costs to be incurred at the moment the asset is retired. Changes in estimate of the carrying amounts of provisions due to the passage of time and changes in discount rates are recognized under "Provisions for contingencies"⁶. Property, plant and equipment is not revalued for financial reporting purposes. Assets carried under financial leasing or concerning arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset are recognized at fair value, net of taxes due from the lessor or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt payable to the lessor is recognized as a financial liability. These assets are depreciated using the criteria described below. When the renewal is not reasonably certain, leased assets are depreciated over the shorter of the lease term or the estimated useful life of the asset. Expenditures on renewals, improvements and transformations which provide additional economic benefits are capitalized to property, plant and equipment. Tangible assets, from the moment they begin or should begin to be used, are depreciated systematically using a straight-line method over their useful life which is an estimate of the period over which the assets will be used by the company. When tangible assets are composed of more than one significant element with different useful lives, each component is depreciated separately. The amount to be depreciated is the book value less the estimated net realizable value at the end of the useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchased with a building. Tangible assets held for sale are not depreciated (see item "Non-current assets held for sale" below). Assets that can be used free of charge by third parties are depreciated over the shorter term of the duration of the concession or the asset’s useful life. Replacement costs of identifiable components in complex assets are capitalized and depreciated over their useful life; the residual book value of the component that has been substituted is charged to the profit and loss account. Expenditures for ordinary maintenance and repairs are expensed as incurred. The carrying value of property, plant and equipment is reviewed for impairment whenever events indicate that the carrying amounts for those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying value with the recoverable amount, which is the higher of fair value less costs to sell or its value in use. If there is no binding sales agreement, fair value is

(5)

Recognition and evaluation criteria of exploration and production activities are described in the section "Exploration and production activities" below.

(6)

The company recognizes material provisions for the retirement of assets in the Exploration & Production 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 undetermined settlement dates for asset retirements do not allow a reasonable estimate of the fair value of the associated retirement obligation. The company performs periodic reviews of its downstream and chemical long-lived assets for any changes in facts and circumstances that might require recognition of a retirement obligation.

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estimated on the basis of market values, recent transactions, or the best available information that shows the proceeds that the company could reasonably expect to collect from the disposal of the asset. Value in use is the present value of the future cash flows expected to be derived from the use of the asset and, if significant and reasonably determinable, the cash flows deriving from its disposal at the end of its useful life, net of disposal costs. Cash flows are determined 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 (and to prices for products which derive there from) used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. Discounting is carried out at a rate that reflects a current market valuation of the time value of money and of those specific risks of the asset that are not reflected in the estimate of the future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the activity. The evaluation of the specific country risk to be included in the discount rate is provided by external parties. The WACC differs considering the risk associated with individual operating segments; in particular for the assets belonging to the Gas & Power and Engineering & Constructions segments, taking into account the different risk compared with Eni, specific WACC rates have been defined (for Gas & Power segment on the basis of a sample of companies operating in the same segment; for Engineering & Constructions segment on the basis of the market quotation); WACC used for impairments in the Gas & Power segment is adjusted to take into consideration the risk premium of the specific country of the activity while WACC used for impairments in the Engineering & Constructions segment is not adjusted for country risk as most of the company assets are not located in a specific country. For the regulated activities, the discount rate used for the measurement of the value in use is equal to the rate return defined by the Regulator. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the realizable value of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called "cash generating unit". When the reasons for their impairment cease to exist, Eni makes a reversal that is recognized in the profit or loss account as income from asset revaluation. This reversed amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.

Intangible assets
Intangible assets are assets without physical substance, controlled by the company and able to produce future economic benefits, and goodwill acquired in business combinations. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or as an integral part of other assets. An entity controls an asset if it has the power to obtain the future economic benefits generated by the underlying asset and to restrict the access of others to those cash flows. Intangible assets are initially stated at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with a definite useful life are amortized systematically over their useful life estimated as the period over which the assets will be used by the company; the amount to be amortized and the recoverability of the carrying amount are verified in accordance with the criteria described in the section "Property, plant and equipment". Goodwill and other intangible assets with an indefinite useful life are not amortized. The recoverability of their carrying value is reviewed at least annually and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Goodwill is tested for impairment at the level of the smallest aggregate on which the company, directly or indirectly, evaluates the return on the capital expenditure to which goodwill relates. When the carrying amount of the cash generating unit, including goodwill allocated thereto, exceeds the cash generating unit’s recoverable amount, the excess is recognized as impairment. The impairment loss is first allocated to reduce the carrying amount of goodwill; any remaining excess to be allocated to the assets of the unit is applied pro-rata on the basis of the carrying amount of each asset in the unit. Impairment charges against goodwill are not reversed⁷. Negative goodwill is recognized in the profit and loss account. Costs of technological development activities are capitalized when: (i) the cost attributable to the development activity can be reasonably determined; (ii) there is the intention, availability of funding and technical capacity to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate future economic benefits.

(7) Impairment charges recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.

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Exploration and production activities⁸

ACQUISITION OF MINERAL RIGHTS
Costs associated with the acquisition of mineral rights are capitalized in connection with the assets acquired (such as exploratory potential, probable and possible reserves and proved reserves). When the acquisition is related to a set of exploratory potential and reserves, the cost is allocated to the different assets acquired on the basis of the value of the relevant discounted cash flows. Expenditure for the exploratory potential, represented by the costs for the acquisition of the exploration permits and for the extension of existing permits, is recognized under "Intangible assets" and is amortized on a straight-line basis over the period of the exploration as contractually established. If the exploration is abandoned, the residual expenditure is charged to the profit and loss account. Acquisition costs for proved reserves and for possible and probable reserves are recognized in the balance sheet as assets. Costs associated with proved reserves are amortized on a UOP basis, as detailed in the section "Development", considering both developed and undeveloped reserves. Expenditures associated with possible and probable reserves are not amortized until classified as proved reserves; in case of a negative result, the costs are charged to the profit and loss account.

EXPLORATION
Costs associated with exploratory activities for oil and gas producing properties incurred both before and after the acquisition of mineral rights (such as acquisition of seismic data from third parties, test wells and geophysical surveys) are initially capitalized in order to reflect their nature as an investment and subsequently amortized in full when incurred.

DEVELOPMENT
Development costs are those costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas. They are then capitalized within property, plant and equipment and amortized generally on a UOP basis, as their useful life is closely related to the availability of feasible reserves. This method provides for residual costs at the end of each quarter to be amortized at a rate representing the ratio between the volumes extracted during the quarter and the proved developed reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between investments and proved developed reserves. Costs related to unsuccessful development wells or damaged wells are expensed immediately as losses on disposal. Impairments and reversal of impairments of development costs are made on the same basis as those for tangible assets.

PRODUCTION
Production costs are those costs incurred to operate and maintain wells and field equipment and are expensed as incurred.

PRODUCTION-SHARING AGREEMENTS AND BUY-BACK CONTRACTS
Oil and gas reserves related to production-sharing agreements and buy-back contracts are determined on the basis of contractual clauses related to the repayment of costs incurred for the exploration, development and production activities executed through the use of company’s technologies and financing (cost oil) and the company’s share of production volumes not destined to cost recovery (profit oil). Revenues from the sale of the production entitlements against both cost oil and profit oil are accounted for on an accrual basis whilst exploration, development and production costs are accounted for according to the policies mentioned above. The company’s share of production volumes and reserves representing the profit oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on the behalf of the company. As a consequence the company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense.

RETIREMENT
Costs expected to be incurred with respect to the retirement of a well, including costs associated with removal of production facilities, dismantlement and site restoration, are capitalized and amortized on a UOP basis, consistent with the policy described under "Property, plant and equipment".

(8) IFRS does not establish specific criteria for hydrocarbon exploration and production activities. Eni continues to use existing accounting policies for exploration and evaluation assets previously applied before the introduction of IFRS 6 "Exploration for and evaluation of mineral resources".

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Grants
Grants related to assets are recorded as a reduction of purchase price or production cost of the related assets when there is reasonable assurance that all the required conditions attached to them, agreed upon with government entities, have been met. Grants not related to capital expenditure are recognized in the profit and loss account.

Financial fixed assets

INVESTMENTS
Investments in subsidiaries excluded from consolidation, jointly controlled entities and associates are accounted for using the equity method⁹. When there is objective evidence of impairment (see also section "Current assets"), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the section "Property, plant and equipment".
Subsidiaries, joint ventures and associates excluded from consolidation are accounted for at cost, adjusted for impairment losses if this does not result in a misrepresentation of the company’s financial condition. When the reasons for their impairment cease to exist, investments accounted for at cost are re-valued within the limit of the impairment made and their effects are included in "Other income (expense) from investments".
Other investments, included in non-current assets, are recognized at their fair value and their effects are included in the equity reserve related to other comprehensive income; the changes in fair value recognized in equity are charged to the profit and loss account when it is impaired or realized. When investments are not traded in a public market and fair value cannot be reasonably determined, investments are accounted for at cost, adjusted for impairment losses; impairment losses may not be reversed¹⁰. The risk deriving from losses exceeding shareholders’ equity is recognized in a specific provision to the extent the parent company is required to fulfill legal or implicit obligations towards the subsidiary or to cover its losses.

RECEIVABLES AND FINANCIAL ASSETS TO BE HELD TO MATURITY
Receivables and financial assets to be held to maturity are stated at cost represented by the fair value of the initial exchanged amount adjusted to take into account direct external costs related to the transaction (e.g. fees of agents or consultants, etc.). The initial carrying value is then adjusted to take into account capital repayments, devaluations and amortization of the difference between the reimbursement value and the initial carrying value. Amortization is carried out on the basis of the effective interest rate of return represented by the rate that equalizes, at the moment of the initial revaluation, the current value of expected cash flows to the initial carrying value (so-called "amortized cost method"). Receivables for finance leases are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease.
Any impairment is recognized by comparing the carrying value with the present value of the expected cash flows discounted at the effective interest rate as defined at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and financial assets to be held to maturity are recognized net of the allowance for impairment losses; when the impairment loss is definite the allowance for impairment losses is reversed for excess charges. Changes to the carrying amount of receivables or financial assets in accordance with the amortized cost method are recognized as "Financial income (expense)".

Non-current assets held for sale
Non-current assets and current and non-current assets included within disposal groups, whose carrying amount will be recovered principally through a sale transaction rather than through their continuing use, are classified as held for sale.
Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized in the balance sheet separately from the entity’s other assets and liabilities.
Non-current assets held for sale are not depreciated and they are measured at the lower of the fair value less costs to sell or their carrying amount.
Any difference between the carrying amount and the fair value less costs to sell is taken to the profit or loss account as an impairment loss; any subsequent reversal is recognized up to the cumulative impairment losses, including those recognized prior to qualification of the asset as held for sale.

(9)

In the case of step acquisition of a significant influence (or joint control), the investment is recognized at the acquisition date of significant influence (joint control) at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the "step-up" of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity.

(10)

Impairment charges recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.

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Financial liabilities
Debt is carried at amortized cost (see item "Financial fixed assets" above).

Provisions for contingencies
Provisions for contingencies are liabilities for risks and charges of a definite nature and whose existence is certain or probable but for which at year-end the timing or amount of future expenditure is uncertain. Provisions are recognized when: (i) there is a current obligation (legal or constructive), as a result of a past event; (ii) it is probable that the settlement of that obligation will result in an outflow of resources embodying economic benefits; and (iii) the amount of the obligation can be reliably estimated. The amount recognized as a provision is the best estimate of the expenditure required to settle the present obligation at the balance sheet date or to transfer it to third parties at that time. The amount recognized for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any indemnity or penalty arising from failure to fulfill these obligations. If the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognized as "Financial income (expense)". When the liability regards a tangible asset (e.g. site restoration and abandonment), the provision is stated with a corresponding entry to the asset to which it refers. Charges to the profit and loss account are made with the amortization process. Costs that the company expects to bear in order to carry out restructuring plans are recognized when the company formally defines the plan and the interested parties have developed the reasonable expectation that the restructuring will happen. Provisions are periodically updated to show the variations of estimates of costs, production times and actuarial rates. The estimated revisions to the provisions are recognized in the same profit and loss account item that had previously held the provision, or, when the liability regards tangible assets (i.e. site restoration and abandonment) with a corresponding entry to the assets to which they refer. In the notes to the Consolidated Financial Statements, the following potential liabilities are described: (i) possible, but not probable obligations deriving from past events, whose existence will be confirmed only when one or more future events beyond the company’s control occur and (ii) current obligations deriving from past events whose amount cannot be reasonably estimated or whose fulfillment will probably not result in an outflow of resources embodying economic benefits.

Employee benefits
Post-employment benefit plans, including constructive obligations, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. In the first case, the company’s obligation, which consists of making payments to the State or a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. The valuation of the liability is made by independent actuaries. The actuarial gains and losses of defined benefit plans are recognized pro-rata on service, in the profit and loss account using the corridor method, if and to the extent that net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period exceed the greater of 10% of the present value of the defined benefit obligation or 10% of the fair value of the plan assets, over the expected average remaining working lives of the employees participating in the plan. Such actuarial gains and losses derive from changes in the actuarial assumptions used or from a change in the conditions of the plan. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety.

Treasury shares
Treasury shares are recorded at cost and as a reduction of equity. Gains resulting from subsequent sales are recorded in equity.

Revenues and costs
Revenues associated with sales of products and services are recorded when significant risks and rewards of ownership pass

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to the customer or when the transaction can be considered settled and the associated revenue can be reliably measured. In particular, revenues are recognized for the sale of:
- - crude oil, generally upon shipment;
- - natural gas, upon delivery to the customer;
- - petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognized upon shipment;
- - chemical products and other products, generally upon shipment.
Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer. Revenues from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognized on the basis of Eni’s net working interest in those properties (entitlement method). Differences between Eni’s net working interest volume and actual production volumes are recognized at current prices at year end. Income related to partially rendered services is recognized in the measurement of accrued income if the stage of completion can be reliably determined and there is no significant uncertainty as to the collectability of the amount and the related costs. When the outcome of the transaction cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable. Revenues accrued during the year related to construction contracts are recognized on the basis of contractual revenues with reference to the stage of completion of a contract measured on the cost-to-cost basis. Requests of additional revenues, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them. Revenues are stated net of returns, discounts, rebates, bonuses and direct taxation.
Award credits, related to customer loyalty programs, are recognized as a separate component of the sales transaction which grant the right to customers. Therefore, the portion of revenues related to the fair value of award credits granted is recognized as an offset to the item "Other liabilities". The liability is charged to the profit and loss account in the period in which the award credits are redeemed by customers or the related right is lost.
The exchange of goods and services of a similar nature and value do not give rise to revenues and costs as they do not represent sale transactions. Costs are recorded when the related goods and services are sold, consumed or allocated, or when their future benefits cannot be determined.
Costs associated with emission quotas, determined on the basis of the average prices of the main European markets at period end, are reported in relation to the amount of the carbon dioxide emissions that exceed the amount assigned. Costs related to the purchase of the emission rights are taken to intangible assets net of any negative difference between the amount of emissions and the quotas assigned. Revenues related to emission quotas are recognized when they are realized after the related sale. In case of sale, if applicable, the acquired emission rights should be considered as the first to be sold.
Operating lease payments are recognized in the profit and loss account over the length of the contract. Labor costs include stock options granted to managers, consistent with their actual remunerative nature. The instruments granted are recorded at fair value on the vesting date and are not subject to subsequent adjustments; the current portion is calculated pro-rata over the vesting period¹¹. The fair value of stock options is determined using valuation techniques which consider conditions related to the exercise of options, current share prices, expected volatility and the risk-free interest rate. The fair value of stock options is recorded as a charge to "Other reserves". The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalized, are included in the profit and loss account.

Exchange rate differences
Revenues and costs associated with transactions in currencies other than the functional currency are translated into the functional currency by applying the exchange rate at the date of the transaction.
Monetary assets and liabilities denominated in currencies other than functional currency are converted by applying the year end exchange rate and the effect is stated in the profit and loss account. Non-monetary assets and liabilities denominated in currencies other than the functional currency valued at cost are translated at the initial exchange rate. Non-monetary assets that are re-measured to fair value, recoverable amount or realizable value, are translated at the exchange rate applicable at the date of re-measurement.

(11) The period between the date of the award and the date starting from the option can be exercised.

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Dividends
Dividends are recognized at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain.

Income taxes
Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in "Income taxes payables". Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the tax authorities, using tax laws that have been enacted or substantively enacted as of the balance sheet date and the tax rates estimated on annual basis. Deferred tax assets or liabilities are provided on temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates (tax laws) that have been enacted or substantively enacted for future years. Deferred tax assets are recognized when their realization is considered probable. Deferred tax assets and liabilities are included in non-current assets and liabilities and are offset at a single entity level if related to offsettable taxes. The balance of the offset, if positive, is recognized in the item "Deferred tax assets"; if negative, in the item "Deferred tax liabilities". When the results of transactions are recognized directly in shareholders’ equity, current taxes, deferred tax assets and liabilities are also charged to the shareholders’ equity.

Derivatives
Derivatives, including embedded derivatives which are separated from the host contract, are assets and liabilities recognized at their fair value which is estimated by using the criteria described in the section "Current assets". When there is objective evidence that an impairment loss has occurred (see "Current assets" paragraph) derivative are recognized net the allowance for impairment losses. Derivatives are classified as hedging instruments when the relationship between the derivative and the hedged item is formally documented and the hedge is highly effectiveness and regularly reviewed. When hedging instruments cover the risk of variation of the fair value of the hedged item (fair value hedge, e.g. hedging of the variability on the fair value of fixed interest rate assets/liabilities) the derivatives are stated at fair value and the effects charged to the profit and loss account. Hedged items are consistently adjusted to reflect the variability of fair value associated with the hedged risk. When derivatives hedge the cash flow variation risk of the hedged item (cash flow hedge, e.g. hedging the variability on the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), changes in the fair value of the derivatives, considered effective are initially stated in equity and then recognized in the profit and loss account consistent with the economic effects produced by the hedged transaction. The changes in the fair value of derivatives that do not meet the conditions required to qualify for hedge accounting are reported in the profit and loss account. Economic effects of transactions, which relate to purchase or sales contracts for commodities entered into to meet the entity’s normal operating requirements and for which the settlement is provided with the delivery of the goods, are recognized on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption).

Financial statements¹²Assets and liabilities on the balance sheet are classified as current and non-current. Items of the profit and loss account are presented by nature¹³.

(12)

The financial statements are the same reported in the Annual Report 2008 with the exception of: (i) the adjustments related the application, starting from 2009, of the revised IAS 1 "Presentation of Financial Statements" as integrated by the document "Improvements to IFRSs" issued in May 2008, which requires the preparation of the statement of comprehensive income and the recognition of the non-hedging derivatives in the "current" and "non-current" section of the balance sheet. The classification of non-hedging derivatives determined the following effects: (a) the reclassification from current assets to non-current assets of euro 290 million and euro 480 million at January 1, 2008 and December 31, 2008 respectively; (b) the reclassification from current liabilities to non-current liabilities of euro 86 million and euro 564 million at January 1, 2008 and December 31, 2008 respectively; (ii) the recognition of the changes in the fair value of the non-hedging derivatives on commodities, also including the effects of settlements, in the new profit and loss account item "Other operating income (expense)". Comparative period figures have been consistently restated; (iii) the final allocation of the acquisition costs of Distrigas NV, Eni Hewett Ltd, First Calgary Petroleums Ltd and Hindustan Oil Exploration Co Ltd related to business combinations occurred in 2008; carrying amounts of certain assets and liabilities acquired have been restated starting from the acquisition date. The final allocations are indicated in Note 27 – Other information.

(13)

Further information on financial instruments as classified in accordance with IFRS is provided in Note 28 – Guarantees, commitments and risks - Other information about financial instruments.

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The statement of comprehensive income shows net profit integrated with income and expenses that are recognized directly in equity according to IFRS.
The statement of changes in shareholders’ equity includes profit and loss for the year, transactions with shareholders and other changes in shareholders’ equity.
The statement of cash flows is presented using the indirect method, whereby net profit is adjusted for the effects of non-cash transactions.

Changes in accounting principles

Starting from January 1, 2009, following the adoption of the provisions of IFRIC 13 "Customer Loyalty Programmes", award credits granted are recognized as a separate component of the sales transaction which granted the right to customers. As a result, part of the consideration received from the sale transaction is allocated to award credits granted, on the basis of their fair value, as an offset to the balance sheet item "Other liabilities"; such liability is recorded to the profit and loss account (as a revenue) in the year when award credits are redeemed by customers or rights are cancelled.
The application of IFRIC 13 determined the following adjustments in the 2007 and 2008 profit and loss account and in the balance sheet as of January 1, 2008 and December 31, 2008: (i) a decrease of euro 52 million and of euro 66 million in the "Net sales from operations" in the 2007 and 2008 profit and loss account, respectively; (ii) an increase of euro 6 million and euro 8 million in the "Other income and revenues" in the 2007 and 2008 profit and loss account, respectively; (iii) a decrease of euro 46 million and euro 58 million in the line item "Purchases, services and other" in the 2007 and 2008 profit and loss account, respectively; (iv) the reclassification of euro 53 million and euro 66 million from "Provisions for contingencies" to "Other current liabilities" in the balance sheet as of January 1, 2008 and December 31, 2008, respectively.
Segment reporting is prepared according to the provisions of IFRS 8 "Operating Segments", effective from January 1, 2009. The new standard requires segment reporting to be prepared according to the requirements used for the preparation of internal reports for the entity’s chief operating decision maker. Therefore, the identification of operating segments and the related reporting are prepared on the basis of internal reports that are regularly reviewed by the entity’s chief operating decision maker in order to allocate resources to the segment and to assess its performance. The adoption of the provisions of IFRS 8 "Operating segments" has not modified the reporting segments¹⁴.

Use of accounting estimates

The company’s Consolidated Financial Statements are prepared in accordance with IFRS. These require the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the 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. A summary of significant estimates follows.

(14) Moreover, starting from 2009, the provisions of the revised IAS 23 "Borrowing Costs" are effective. The revised standard requires the capitalization of borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset that takes a substantial period of time to get ready for use or sale. As a result, the main change from the previous version is the removal of the option of immediately recognizing as an expense such borrowing costs. The change does not affect Eni’s financial statements as it already capitalizes such costs.

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Oil and gas activities
Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering criteria that must be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Field reserves will only be categorized as proved when all the criteria for attribution of proved status have been met. At this stage, all booked reserves will be classified as proved undeveloped. Volumes will subsequently be reclassified from proved undeveloped to proved developed as a consequence of development activity. The first proved developed bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of Production-sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion expenses and impairment expense. Depreciation rates on oil and gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, depletion and amortization expense. Conversely, a decrease in estimated proved developed reserves increases depreciation, depletion and amortization expense. In addition, estimated proved reserves are used to calculate future cash flows from oil and gas properties, which serve as an indicator in determining whether or not property impairment is to be carried out. The larger the volume of estimated reserves, the lower the likelihood of asset impairment.

Impairment of assets
Eni assesses its tangible assets and intangible assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate the carrying values of the assets are not recoverable. Such indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced utilization of the plants and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply and demand conditions for crude oil, natural gas, commodity chemicals and refined products. Similar remarks are valid for the physical recoverability of assets recognized in the balance sheet (deferred cost - see also item "Current assets") related to natural gas volumes not collected under long term purchase contracts with take-or-pay clauses.
The amount of an impairment loss is determined by comparing the book value of an asset with its recoverable amount. The recoverable amount is the greater of fair value net of disposal cost or the value in use. The estimated value in use is based on the present values of expected future cash flows net of disposal costs. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate related to the activity involved.
For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and non-developed proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimated future level of production is based on assumptions concerning: future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors. Oil, natural gas and petroleum product prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years and management’s long-term planning assumptions thereafter. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, market demand and other factors. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows. Goodwill

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and other intangible assets with an indefinite useful life are not subject to amortization. The company tests such assets at the cash-generating unit level for impairment on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value below its carrying amount. In particular, goodwill impairment is based on the determination of the fair value of each cash-generating unit to which goodwill can be attributed on a reasonable and consistent basis. A cash generating unit is the smallest aggregate on which the company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash generating unit is lower than the carrying amount, goodwill attributed to that cash generating unit is impaired up to that difference; if the carrying amount of goodwill is less than the amount of impairment, assets of the cash generating unit are impaired on a pro-rata basis for the residual difference.

Asset retirement obligations
Obligations to remove tangible equipment and restore land or seabed require significant estimates in calculating the amount of the obligation and determining the amount required to be recorded presently in the Consolidated Financial Statements. Estimating future asset retirement obligations is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The subjectivity of these estimates is also increased by the accounting method used that requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically, at the time the asset is installed at the production location). When liabilities are initially recorded, the related fixed assets are increased by an equal corresponding amount. The liabilities are increased with the passage of time (i.e. interest accretion) and any change in the estimates following the modification of future cash flows and discount rate adopted. The recognized asset retirement obligations are based on future retirement cost estimates and incorporate many assumptions such as: expected recoverable quantities of crude oil and natural gas, abandonment time, future inflation rates and the risk-free rate of interest adjusted for the Company’s credit costs.

Business combinations
Accounting for business combinations requires the allocation of the purchase price to the various assets and liabilities of the acquired business at their respective fair values. Any positive residual difference is recognized as "Goodwill". Negative residual differences are credited to the profit and loss account. Management uses all available information to make these fair value determinations and, for major business acquisitions, typically engages an independent appraisal firm to assist in the fair value determination of the acquired assets and liabilities.

Environmental liabilities
Together with other companies in the industries in which it operates, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental costs are recognized when it becomes probable that a liability has been incurred and the amount can be reasonably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by Decree No. 471/1999 of the Ministry of Environment concerning the remediation of contaminated sites; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible insurance recoveries.

Employee benefits
Defined benefit plans and other long-term benefits are evaluated with reference to uncertain events and based upon actuarial assumptions including among others discount rates, expected rates of return on plan assets, expected rates of salary increases, medical cost trends, estimated retirement dates and mortality rates. The significant assumptions used to account for pensions and other post-retirement benefits are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include rates of annuity contracts and rates of return on high quality fixed-income investments. The inflation rates reflect

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market conditions observed country by country; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved, based principally on available actuarial data; and (v) determination of the expected rates of return on assets is made through compound averaging. For each plan, the distribution of investments among bonds, equities and cash and their specific average expected rate of return is taken into account. Differences between expected and actual costs and between the expected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. Eni applies the corridor method to amortize its actuarial losses and gains. This method amortizes on a pro-rata basis the net cumulative unrecognized actuarial gains and losses at the end of the previous reporting period that exceed 10% of the greater of: (i) the present value of the defined benefit obligation; and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan. Additionally, obligations for other long-term benefits are determined by adopting actuarial assumptions. The effect of changes in actuarial assumptions or a change in the characteristics of the benefit are taken to the profit or loss in their entirety.

Contingencies
In addition to accruing the estimated costs for environmental liabilities, asset retirement obligation and employee benefits, Eni accrues for all contingencies that are both probable and estimable. These other contingencies are primarily related to litigation and tax issues. Determining the appropriate amount to accrue is a complex estimation process that includes subjective judgments.

Revenue recognition in the Engineering & Construction segment
Revenue recognition in the Engineering & Construction segment is based on the stage of completion of a contract as measured on the cost-to-cost basis applied to contractual revenues. Use of the stage of completion method requires estimates of future gross profit on a contract by contract basis. The future gross profit represents the profit remaining after deducting costs attributable to the contract from revenues provided for in the contract. The estimate of future gross profit is based on a complex estimation process that includes identification of risks related to the geographical region, market conditions in that region and any assessment that is necessary to estimate with sufficient precision the total future costs as well as the expected timetable. Requests of additional income, deriving from a change in the scope of work, are included in the total amount of revenues when it is probable that the customer will approve the variation and the related amount. Claims deriving from additional costs incurred for reasons attributable to the client are included in the total amount of revenues when it is probable that the counterparty will accept them.

Recent accounting principles

Accounting standards and interpretations issued by IASB /IFRIC and endorsed by EU
By Commission Regulation No. 495/2009 and 494/2009 of June 3, 2009 the revised IFRS 3 "Business Combinations" and an amended version of IAS 27 "Consolidated and Separate Financial Statements" have been endorsed. The revisions to IFRS 3 require, interalia, (i) the acquisition-related costs to be accounted for separately from the business combination and then recognized as expenses; (ii) the recognition to the profit and loss account of any change to contingent consideration; and (iii) the choice of the full goodwill method which means to account for the full value of the goodwill of the business combination including the share attributable to non-controlling interests. In the case of step acquisitions, the revisions also require the recognition in the profit and loss account the difference between the fair value at the acquisition date of the net assets previously held and their carrying amounts. The amendments of IAS 27 require, interalia, that acquisitions or disposals of ownership interests in a subsidiary that do not result in the acquisition (loss) of control, shall be accounted for as equity transactions. By contrast, disposal of any interests that the parent retains in a former subsidiary, jointly controlled entity or associate may result in a loss of control, joint control and significant influence. In this case, at the date when control (joint control or significant influence) is lost, the remaining investment retained is recognized at its fair value with gains or losses arising from the difference between the fair value and carrying amount of the held investment recorded in the profit or loss account. The revised Standards shall be applied for annual periods beginning on or after July 1, 2009 (for Eni: 2010 financial statements).

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By Commission Regulation No. 1293/2009 of December 23, 2009, the amendment to IAS 32 "Classification of rights issues" has been endorsed. The amendment clarifies how to classify in the issuer’s financial statements those financial instruments which grant to shareholders the right to acquire equity instruments of the issuers for a price denominated in a currency other than issuer’s functional currency. If such instruments are issued pro rata to the issuer’s existing shareholders for a fixed amount of cash, they should be classified as equity even if their exercise price is denominated in a currency other than the issuer’s functional currency. The amendment to IAS 32 shall be applied for annual period beginning on or after February 1, 2010 (for Eni: 2011 financial statements).

By Commission Regulation No. 254/2009 of March 25, 2009 IFRIC 12 "Service Concession Arrangements" (hereinafter IFRIC 12) has been endorsed. The interpretation provides guidance on the accounting by operators for public-to-private service concession arrangements. An arrangement within the scope of this interpretation involves for a specified period of time an operator constructing, upgrading, operating and maintaining the infrastructure used to provide the public service. In particular when the grantor controls or regulates what services the operator must provide with the infrastructure, at what price and any significant residual interest in the infrastructure at the end of the term of the arrangement, the operator shall recognize the concession as an intangible asset or as a financial asset on the basis of the agreements. According to the Commission Regulation, this interpretation shall be applied for annual periods beginning on or after March 29, 2009 (for Eni: 2010 financial statements)¹⁵.

By Commission Regulation No. 1142/2009 of November 26, 2009 IFRIC 17 "Distributions of Non-cash Assets to Owners" (hereinafter IFRIC 17) has been endorsed. The interpretation provides clarification and guidance on the accounting treatment of distributions of non-cash assets to owners of an entity, or distributions that give owners a choice of receiving either non-cash assets or a cash alternative. In particular, the interpretation requires, interalia, that the distribution is measured at the fair value of the assets to be distributed. The liability to pay a dividend shall be recognized when the dividend is appropriately authorized; the liability and the related adjustments are recognized as an offset to equity. When an entity settles the dividend payable, it shall recognize the difference, if any, between the carrying amount of the non-cash assets distributed and the fair value of the dividend payable in the profit or loss account. According to the Commission Regulation, this interpretation shall be applied for annual periods beginning on or after October 31, 2009 (for Eni: 2010 financial statements)¹⁶.

By Commission Regulation No. 1164/2009 of November 27, 2009 IFRIC 18 "Transfers of Assets from Customers" (hereinafter IFRIC 18) has been endorsed. The interpretation provides clarification and guidance on the accounting for transfers of assets to be used to connect customers to a network to supply goods or services.
The interpretation is also applied in the cases in which the entity receives cash from a customer that must be used only to connect the customer to a network. When the definition of an asset set out in the Framework is met, the asset received is recognized at its fair value; when the agreement states the supply of more than one service (for example, connection to a network and supply of goods) the entity receiving the transfer shall assess which service is provided against the transferred asset and recognizes, consistently, a revenue when the connection is made or over a period no longer than the length of the supply and the useful life of the asset. IFRIC 18 provisions do not apply to assets within the scope of IFRIC 12. According to the Commission Regulation, this interpretation shall be applied for annual periods beginning after October 31, 2009 (for Eni: 2010 financial statements)¹⁷.

(15)	According to IFRIC 12 provisions, the interpretation shall be applied for annual periods beginning on or after January 1, 2008. Therefore, IFRIC 12 had to be considered, starting from 2008, for the preparation of Annual Report on Form 20-F. In particular starting from 2007 year Eni applies the SEC provisions allowing elimination of the U.S. GAAP reconciliation of the net income and equity for foreign private issuers that prepare their financial statements adopting the provisions of the international accounting standards (IFRS) issued by the IASB (even if not endorsed yet or, even if endorsed, they have a different effective date). The IFRIC 12 provisions regard some Group companies of the secondary gas distribution segment; the effects of the application of the interpretation regard the different classification of the carrying amount of the distribution networks from the line item "Property, plant and equipment" to assets under concession arrangements.
(16)	According to IFRIC 17 provisions, the interpretation shall be applied for annual periods beginning on or after July 1, 2009.
(17)	According to IFRIC 18 provisions, the interpretation shall be applied prospectively to transfers of assets from customers received on or after July 1, 2009. Therefore, similarly to IFRIC 12, IFRIC 18 provisions have to be considered for the preparation of Annual Report on Form 20-F.

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Accounting standards and interpretations issued by IASB/IFRIC and not yet been endorsed by EU
On November 4, 2009, IASB issued a new version of IAS 24 "Related Party Disclosures", which: (i) enhances the definition of a related party requiring new cases; (ii) for transactions between entities related to the same Government, allows to limit quantitative disclosures to significant transactions. The revised standard shall be applied for annual periods beginning on or after January 1, 2011.

On November 12, 2009 IASB issued IFRS 9 "Financial Instruments" which changes recognition and measurement of financial assets and their classification in the financial statements. In particular, new provisions require, interalia, a classification and measurement model of financial assets based exclusively on the following categories: (i) financial assets measured at amortized cost; (ii) financial assets measured at fair value. New provisions also require that investments in equity instruments, other than subsidiaries, jointly controlled entities or associates, shall be measured at fair value with effects taken to the profit and loss account. If these investments are not held for trading purposes, subsequent changes in the fair value can be recognized in other comprehensive income, even if dividends are taken to the profit and loss account. Amounts taken to other comprehensive income shall not be subsequently transferred to the profit or loss account even at disposal. IFRS 9 provisions shall be applied for annual periods beginning on or after January 1, 2013.

On November 26, 2009 IASB issued IFRIC 19 "Extinguishing Financial Liabilities with Equity Instruments" which defines the accounting treatment to adopt when a financial liability is settled by issuing equity instruments to the creditor (debt for equity swaps). Equity instruments issued to extinguish a liability in full or in part, are measured at their fair value or, if fair value cannot be reliably measured, at the fair value of the financial liability extinguished. The difference between the carrying amount of the financial liability extinguished and the fair value of equity instrument issued shall be recognized in the profit or loss account. IFRIC 19 provisions shall be applied for annual periods beginning on or after July 1, 2010 (for Eni: 2011 financial statements).

On April 16, 2009, IASB issued the document "Improvements to IFRSs" which includes only changes to the existing standards and interpretation with a technical and editorial nature. The provisions come into effect starting from 2010.

Eni is currently reviewing these new IFRS and interpretations to determine the likely impact on the Group’s results.

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Notes to the Consolidated Financial Statements

Current assets

1 Cash and cash equivalents
Cash and cash equivalents in the amount of euro 1,608 million (euro 1,939 million as of December 31, 2008) included financing receivables originally due within 90 days for euro 450 million (euro 616 million as of December 31, 2008). The latter were related to amounts on deposit with financial institutions accessible only with a 48-hour notice.


2 Other financial assets held for trading or available for sale
Other financial assets held for trading or available for sale are set out below:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Investments	2,741
Securities held for operating purposes
Listed Italian treasury bonds	257	113
Listed securities issued by Italian and foreign financial institutions	45	171
Non-quoted securities	8
	310	284
Securities held for non-operating purposes
Listed Italian treasury bonds	109	49
Listed securities issued by Italian and foreign financial institutions	67	14
Non-quoted securities	9	1
	185	64
Total securities	495	348
	3,236	348

Equity instruments decreased by the carrying amount of the 20% interest in OAO Gazprom Neft (euro 2,741 million), purchased by Gazprom, following the exercising of a call option on April 7, 2009 on the basis of the existing agreements with Eni. On April 24, 2009, Eni received a payment of euro 3,070 million (U.S. $4,062 million at the exchange rate of the date of the transaction). Eni acquired the investment in Gazprom Neft on April 4, 2007 through a bid on the liquidation of the second lot of ex-Yukos assets. The strike price of the call option was equal to the bid price (U.S. $3.7 billion) decreased by the dividends distributed and an increase of the contractual remuneration of 9.4% on the capital employed and financing collateral expenses.
Other securities in the amount of euro 348 million (euro 495 million as of December 31, 2008) were classified as available-for-sale securities. As of December 31, 2008 and 2009, Eni did not own financial assets held for trading.

The effects of the valuation at fair value of securities are set below:

(euro million) Value at
Dec. 31, 2008 Changes recognized in the reserves of shareholders' equity Value at
Dec. 31, 2009

Fair value	5		1	6
Deferred tax liabilities	(1	)		(1	)
Other reserves of shareholders' equity	4		1	5

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Securities held for operating purposes in the amount of euro 284 million (euro 310 million as of December 31, 2008) were designed to provide coverage of technical reserves for the Group’s insurance company Eni Insurance Ltd (euro 302 million as of December 31, 2008).
The fair value of securities was determined by reference to quoted market prices.


3 Trade and other receivables
Trade and other receivables were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Trade receivables	16,444	14,916
Financing receivables:
- for operating purposes - short-term	402	339
- for operating purposes - current portion of long-term receivables	85	113
- for non-operating purposes	337	73
	824	525
Other receivables:
- from disposals	149	82
- other	4,805	4,825
	4,954	4,907
	22,222	20,348

Receivables are stated net of the allowance for impairment losses in the amount of euro 1,647 million (euro 1,251 million as of December 31, 2008):

(euro million) Value at
Dec. 31, 2008 Additions Deductions Other changes Value at
Dec. 31, 2009

Trade receivables	747	260	(15	)	(50	)	942
Financing receivables	19		(13	)			6
Other receivables	485	206	(24	)	32		699
	1,251	466	(52	)	(18	)	1,647

Trade receivables decreased in the amount of euro 1,528 million primarily due to the Gas & Power segment (euro 1,990 million), which was partially offset by the increase in the Refining & Marketing segment (euro 380 million).
Trade and other receivables were as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Trade receivables Other receivables Total Trade receivables Other receivables Total

Neither impaired nor past due	12,611	3,395	16,006	11,557	3,004	14,561
Impaired (net of the valuation allowance)	1,242	88	1,330	1,037	58	1,095
Not impaired and past due in the following periods:
- within 90 days	1,812	502	2,314	1,168	772	1,940
- 3 to 6 months	231	68	299	503	56	559
- 6 to 12 months	248	294	542	294	439	733
- over 12 months	300	607	907	357	578	935
	2,591	1,471	4,062	2,322	1,845	4,167
	16,444	4,954	21,398	14,916	4,907	19,823

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Trade receivables not impaired and past due primarily referred to high-credit-quality public administrations and other highly-reliable counterparties for oil, natural gas and chemical products supplies.
Allowances for impairment losses of traded receivables in the amount of euro 260 million (euro 251 million for the year ended December 31, 2008) primarily referred to the Gas & Power segment (euro 165 million).
Allowances for impairment losses of other receivables in the amount of euro 206 million (euro 137 million for the year ended December 31, 2008) primarily referred to the Exploration & Production segment (euro 205 million) which primarily represents the impairment of certain receivables associated with cost recovery with respect to local state-owned co-venturers based on underlying petroleum agreements and modifications of the Company’s interest in certain joint ventures.
Trade receivables included guarantees for work in progress in the amount of euro 168 million (euro 213 million as of December 31, 2008).
Other receivables in the amount of euro 461 million (euro 227 million as of December 31, 2008) associated with cost recovery in the Exploration & Production segment are currently undergoing arbitration procedure.
Receivables for financing operating activities in the amount of euro 452 million (euro 487 million as of December 31, 2008) included euro 245 million due from unconsolidated subsidiaries, joint ventures and associates (euro 399 million as of December 31, 2008), euro 179 million cash deposit to provide coverage of Eni Insurance Ltd technical reserves (euro 47 million as of December 31, 2008) and receivables for financial leasing in the amount of euro 19 million (the same amount as of December 31, 2008). More information about receivables for financial leasing is included in Note 12 – Other financial assets.
Receivables for financing non-operating activities amounted to euro 73 million (euro 337 million as of December 31, 2008) of which euro 67 million related to deposits for the Engineering & Construction segment. The decrease of euro 264 million is mainly due to the release of a deposit of Eni Lasmo Plc made to guarantee a debenture (euro 173 million) and the decrease of deposits of Eni Insurance Ltd (euro 88 million).
Other receivables were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Accounts receivable from:
- joint venture operators in exploration and production	2,242	2,372
- Italian government entities	378	457
- insurance companies	146	194
	2,766	3,023
Prepayments for services	857	860
Receivables relating to factoring operations	171	156
Other receivables	1,160	868
	4,954	4,907

Receivables deriving from factoring operations in the amount of euro 156 million (euro 171 million as of December 31, 2008) related to Serfactoring SpA and consisted primarily of advances for factoring operations with recourse and receivables for factoring operations without recourse.
Receivables with related parties are described in Note 36 – Transactions with related parties.
Because of the short-term maturity of trade receivables, the fair value approximates their carrying amount.

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4 Inventories
Inventories were as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Crude oil, gas and petroleum products Chemical products Work in progress Other Total Crude oil, gas and petroleum products Chemical products Work in progress Other Total

Raw and auxiliary materials and consumables	466	263		1,155	1,884	616	150		1,363	2,129
Products being processed and semi finished products	48	17		3	68	74	17		9	100
Work in progress			953		953			759		759
Finished products and goods	2,528	557		92	3,177	1,889	552		66	2,507
	3,042	837	953	1,250	6,082	2,579	719	759	1,438	5,495

Contract work in progress in the amount of euro 759 million (euro 953 million as of December 31, 2008) are net of prepayments in the amount of euro 13 million (euro 274 million as of December 31, 2008) which are within the limits of contractual considerations.

Inventories are stated net of the valuation allowance in the amount of euro 103 million (euro 697 million as of December 31, 2008):

(euro million) Value at
Dec. 31, 2008 Additions Deductions Other changes Value at
Dec. 31, 2009

697 36 (550 ) (80 ) 103

Deductions in the amount of euro 550 million essentially represent the Refining & Marketing (euro 336 million) and the Petrochemical segments (euro 200 million).


5 Current tax assets
Current tax assets were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Italian subsidiaries	53	570
Foreign subsidiaries	117	183
	170	753

The increase in other current tax assets in the amount of euro 583 million mainly relates to receivables for interim tax payments which exceeded the full-year tax payable (euro 430 million) made by Eni SpA.


6 Other current tax assets
Other current tax assets were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

VAT	623	889
Excise and customs duties	167	119
Other taxes and duties	340	262
	1,130	1,270

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

7 Other current assets
Other current assets were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Fair value of non-hedging derivatives	1,128	698
Fair value of cash flow hedge derivatives	474	236
Other assets	268	373
	1,870	1,307

The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Fair value Purchase commitments Sale
commitments Fair value Purchase commitments Sale
commitments

Non-hedging derivatives on exchange rate
Interest Currency Swap	35		80	2	113
Currency swap	201	2,653	1,701	64	1,855	1,117
Other	285	98	1,154	142	174	537
	521	2,751	2,935	208	2,142	1,654
Non-hedging derivatives on interest rate
Interest rate swap	2		300	1	133
Other		4		9	9
	2	4	300	10	142
Non-hedging derivatives on commodities
Over the counter	547	1,063	1,850	469	1,383	1,257
Other	58	65	53	11	234	8
	605	1,128	1,903	480	1,617	1,265
	1,128	3,883	5,138	698	3,901	2,919

Fair value of the derivative contracts is determined using market quotations provided by primary info-provider, or in the absence of market information, appropriate valuation methods used on the marketplace.
Fair values of non-hedging derivatives in the amount of euro 698 million (euro 1,128 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.
The decrease in the fair value of the non-hedging derivatives in the amount of euro 430 million primarily referred to the Gas & Power segment (euro 315 million) and Eni SpA (euro 160 million).
Fair value of the cash flow hedge derivatives in the amount of euro 236 million referred to Distrigas NV. These derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in the gas portfolio. The negative fair value for contracts expiring in 2010 is given in Note 19 – Other current liabilities; positive and negative fair value of contracts expiring beyond 2010 is given in Note 14 – Other non-current receivables and Note 24 – Other non-current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and Note 30 – Operating expenses.
The nominal value of cash flow hedge derivatives represented purchase and sale commitments in the amount of euro 25 million and euro 603 million, respectively.
Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.
Other assets amounted to euro 373 million (euro 268 million as of December 31, 2008) and included prepayments and accrued income for euro 104 million (euro 63 million as of December 31, 2008), rentals for euro 35 million (euro 31 million as of December 31, 2008) and insurance premiums for euro 18 million (euro 11 million as of December 31, 2008).

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Non-current assets

8 Property, plant and equipment
Analysis of tangible assets is set out below:

(euro million) Net value at the beginning of the year Investments Depreciation Impairments Changes in the scope of consolidation Currency translation differences Other changes Net value at the end of the year Gross value at the end of the year Provisions for amortization and impairments

Dec. 31, 2008
Land	598	8					(7	)			27		626	656	30
Buildings	1,376	102	(106	)	(29	)	(122	)	7		(342	)	886	3,125	2,239
Plant and machinery	35,880	3,590	(5,737	)	(652	)	1,301		112		4,548		39,042	91,864	52,822
Industrial and commercial equipment	550	228	(177	)	(3	)			1		227		826	2,203	1,377
Other assets	341	124	(83	)	(6	)	(13	)	5		9		377	1,563	1,186
Tangible assets in progress and advances	11,392	8,260			(653	)	2,442		408		(4,351	)	17,498	18,716	1,218
	50,137	12,312	(6,103	)	(1,343	)	3,601		533		118		59,255	118,127	58,872
Dec. 31, 2009
Land	626	10					2		(3	)	(9	)	626	654	28
Buildings	886	36	(100	)	(37	)	25		(34	)	46		822	3,129	2,307
Plant and machinery	39,042	3,599	(6,370	)	(496	)	3		(176	)	7,238		42,840	101,538	58,698
Industrial and commercial equipment	826	214	(179	)	(2	)	16		(17	)	228		1,086	2,482	1,396
Other assets	377	152	(130	)	(4	)			(8	)	156		543	1,920	1,377
Tangible assets in progress and advances	17,498	8,289			(451	)	2		(273	)	(7,805	)	17,260	18,801	1,541
	59,255	12,300	(6,779	)	(990	)	48		(511	)	(146	)	63,177	128,524	65,347

Capital expenditures in the amount of euro 12,300 million (euro 12,312 million for the year ended December 31, 2008) essentially related to the Exploration & Production segment (euro 8,196 million), the Gas & Power segment (euro 1,622 million), the Engineering & Construction segment (euro 1,615 million), and the Refining & Marketing segment (euro 626 million). Capital expenditures included capitalized finance expenses of euro 222 million (euro 236 million for the year ended December 31, 2008) essentially related to the Exploration & Production segment (euro 77 million), the Engineering & Construction segment (euro 76 million), the Refining & Marketing segment (euro 35 million) and the Gas & Power segment (euro 32 million). The interest rate used for the capitalization of finance expense ranged between 1.9% to 3.7% (3.5% and 5.1% for the year ended December 31, 2008).
The depreciation rates used were as follows:

(%)
Buildings	2	-	10
Plant and machinery	2	-	10
Industrial and commercial equipment	4	-	33
Other assets	6	-	33

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Impairments in the amount of euro 990 million (euro 1,343 million as of December 31, 2008) and the associated tax effect by segment is provided below:

(euro million) 2008 2009

Impairment
Exploration & Production	765	576
Refining & Marketing	292	287
Petrochemicals	279	121
Other segments	7	6
	1,343	990
Tax effect
Exploration & Production	213	197
Refining & Marketing	108	108
Petrochemicals	88	33
Other segments	2	2
	411	340
Impairment net of the relevant tax effect
Exploration & Production	552	379
Refining & Marketing	184	179
Petrochemicals	191	88
Other segments	5	4
	932	650

In assessing whether an impairment is required, the carrying value of an asset is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair value less costs to sell or value-in-use. Given the nature of Eni’s activities, information on the fair value of an asset is usually difficult to obtain unless negotiations with potential purchasers are taking place. Eni assesses individual assets or groups of assets (Cash Generating Units - CGUs) which represent the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. In particular, the CGUs consist of: (i) the Exploration & Production segment, which include individual oilfields or pools of oilfields whereby technical, economic or contractual features make the underlying cash flows interdependent; (ii) the Gas & Power segment, which include transport and distribution networks and related facilities, storage sites and re-gasification facilities in a consistent way with the gas segments of operations that are defined by the Italian Authority for Electricity and Gas for the purpose of tariff settings and other authorities. Other CGUs are gas carrier ships and plants for the production of electricity; (iii) the Refining & Marketing segment, which include refining plants and commercial facilities relating to each distribution channel and by country (ordinary network, high-ways network, and wholesale activity); (iv) the Petrochemicals segment, which include production plants and related facilities; and (v) the Engineering & Construction segment, which include Business Units Offshore construction, Onshore construction and Onshore drilling facilities and individual Rigs for Offshore operations.
The recoverable amount used in assessing the impairment charges described below is value-in-use. Value-in-use is calculated by discounting the estimated cash flows determined on the basis of the best information available at the moment of the assessment which is derived from: (i) the Company’s four-year plan approved by top management that provides information on the expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the four-year plan a nominal growth rate is used ranging from 0% to 2%; (ii) the commodity prices have been assessed based on the forward prices prevailing on the market place as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s management for strategic planning purposes for the following years (see "Basis of presentation").
Post-tax cash flows are discounted at the rate which corresponds for the Exploration & Production, Refining & Marketing and Petrochemicals segments to the Company’s weighted average cost of capital, adjusted to consider the risks specific to each country of activity (adjusted post-tax WACC). For 2009, the adjusted post-tax rates used for impairment testing showed an increase of 0.5 percentage points on average from the previous year as a result of a higher market premium for the equity risk and the country risk. Such increase was partially reduced by decreased nominal interest rates reflected in the cost of borrowings and in rates of assets risk-free. For 2009, the adjusted post-tax rates ranged from 9% to 13.5%. Post-tax cash flows and discount rates have been adopted as they result in an assessment that is substantially equal to a pre-tax assessment.

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In the Exploration & Production segment the main impairments related to proved and unproved oil & gas properties mainly located in the Gulf of Mexico, Australia, Congo, Egypt and Nigeria as a result of downward reserve revisions and cost increases.
In the Refining & Marketing segment the main impairments related to refining plants. The drivers of those impairments were a weak refining environment and the Company’s expectations for a slow recovery in those trends which negatively affected the refining performance in 2009, including compressed price differentials between heavy and light crudes, and weak prices for middle distillates that were dragged down by excess inventory. Also, plant-specific factors were taken into account, particularly low complexity.
In the Petrochemicals segment the main impairments related to the olefins-aromatic-polyethylene plants of Porto Marghera and the Sicilian pole. The main drivers of those impairments were continuing trends for margin pressures and volumes reduction, particularly in the case of commoditized products, due to weak industry fundamentals in terms of sluggish demand, excess capacity and rising competitive pressures as new capacity is expected to come on line in the Middle East.
Negative foreign currency translation differences in the amount of euro 511 million were primarily related to translation of entities accounts denominated in U.S. dollar (euro 1,005 million). This effect was partially offset by translation of entities accounts denominated in Norwegian krones (euro 339 million).
Other negative changes in the net book value of tangible assets (euro 146 million) relate to the reclassification to assets classified as held for sale in the amount of euro 421 million and the disposals of assets in the amount of euro 150 million, which was offset by an increase in the initial recognition and change of estimated costs for the dismantling and restoration of sites in the amount of euro 289 million which mainly relate to the Exploration & Production segment (euro 273 million).
The following is a description of unproved mineral interests, included in tangible assets in progress and advances:

(euro million) Value at the beginning of the year Acquisitions Impairments Reclassification to Proved Mineral Interest Other changes and currency translation differences Net value at the end of the year

Dec. 31, 2008
Congo	641	862	(10	)	(81	)	85		1,497
USA	1,401		(144	)			74		1,331
Turkmenistan		809	(164	)			40		685
Algeria		748					(59	)	689
Other countries	255	209	(90	)	(85	)	(1	)	288
	2,297	2,628	(408	)	(166	)	139		4,490
Dec. 31, 2009
Congo	1,497	42			(333	)	(42	)	1,164
USA	1,331	43	(231	)	(229	)	(32	)	882
Turkmenistan	685				(13	)	(23	)	649
Algeria	689				(220	)	(17	)	452
Other countries	288	137	(54	)	(140	)			231
	4,490	222	(285	)	(935	)	(114	)	3,378

Unproved mineral interests are normally recognized upon allocation of the purchase price of business combinations in the Exploration & Production segment. The main amounts are associated with probable and possible reserves in Congo, Gulf of Mexico, Turkmenistan and Algeria associated with recent acquisitions. Changes during the year amounted to a decrease of euro 935 million which related to transfers to property, plant and equipment associated with recognition of proved reserves and internal approval for development. Impairments for the year amounted to euro 285 million due to downward revisions related to properties in the Gulf of Mexico and, to a lesser extent, Nigeria.
The accumulated provisions for impairments amounted to euro 4,692 million and euro 5,680 million as of December 31, 2008 and 2009, respectively.
As of December 31, 2009, Eni pledged property, plant and equipment for euro 28 million primarily as collateral against certain borrowings (euro 29 million as of December 31, 2008).
Government grants recorded as a reduction of property, plant and equipment amounted to euro 1,335 million (euro 1,308 million as of December 31, 2008).

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Assets acquired under financial lease agreements amounted to euro 28 million (euro 163 million as of December 31, 2008), of which, euro 19 million related to FPSO ships used by the Exploration & Production segment to support oil production and treatment activities and euro 9 million related to service stations in the Refining & Marketing segment. The decrease of euro 135 million primarily related to the exercise of the option for the acquisition of a drilling platform by the Engineering & Construction segment for euro 127 million.
Contractual commitments related to the purchase of property, plant and equipment are included in Note 28 – Guarantees, commitments and risks - Liquidity risk.
Property, plant and equipment under concession arrangements are described in Note 28 – Guarantees, commitments and risks - Asset under concession arrangements.

Property, plant and equipment by segment

(euro million) Dec. 31, 2008 Dec. 31, 2009

Property, plant and equipment, gross
Exploration & Production	64,338		71,189
Gas & Power	26,566		27,998
Refining & Marketing	12,899		13,378
Petrochemicals	5,036		5,174
Engineering & Construction	7,702		9,163
Other activities	1,550		1,592
Corporate and financial companies	391		373
Elimination of intra-group profits	(355	)	(343	)
	118,127		128,524
Accumulated depreciation, amortization and impairment losses
Exploration & Production	31,983		36,727
Gas & Power	10,206		10,808
Refining & Marketing	8,403		8,981
Petrochemicals	4,124		4,321
Engineering & Construction	2,548		2,858
Other activities	1,467		1,513
Corporate and financial companies	179		194
Elimination of intra-group profits	(38	)	(55	)
	58,872		65,347
Property, plant and equipment, net
Exploration & Production	32,355		34,462
Gas & Power	16,360		17,190
Refining & Marketing	4,496		4,397
Petrochemicals	912		853
Engineering & Construction	5,154		6,305
Other activities	83		79
Corporate and financial companies	212		179
Elimination of intra-group profits	(317	)	(288	)
	59,255		63,177

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9Inventory - - compulsory stock
Inventory - compulsory stock was as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Crude oil and petroleum products	1,040	1,586
Natural gas	156	150
	1,196	1,736

Compulsory stock was primarily held by Italian companies (euro 1,184 million and euro 1,724 million as of December 31, 2008 and 2009, respectively) in accordance with minimum stock requirements set forth by applicable laws.


10 Intangible assets
Intangible assets were as follows:

(euro million) Net value at the beginning of the year Investments Amortization Changes in the scope of consolidation Other changes Net value at the end of the year Gross value at the end of the year Provisions for amortization
and writedowns

Dec. 31, 2008
Intangible assets with finite useful lives
Exploration expenditures	749	1,907	(2,097	)	335		77		971	2,295	1,324
Industrial patents and intellectual property rights	148	44	(85	)			42		149	1,203	1,054
Concessions, licenses, trademarks and similar items	786	17	(93	)	(15	)	38		733	2,475	1,742
Intangible assets in progress and advances	377	264					(61	)	580	590	10
Other intangible assets	158	18	(52	)	1,595		14		1,733	1,995	262
	2,218	2,250	(2,327	)	1,915		110		4,166	8,558	4,392
Intangible assets with indefinite useful lives
Goodwill	2,115				1,417		(1	)	3,531
	4,333	2,250	(2,327	)	3,332		109		7,697
Dec. 31, 2009
Intangible assets with finite useful lives
Exploration expenditures	971	1,273	(1,615	)			2		631	2,259	1,628
Industrial patents and intellectual property rights	149	10	(85	)			64		138	1,275	1,137
Concessions, licenses, trademarks and similar items	733	20	(153	)			71		671	2,403	1,732
Intangible assets in progress and advances	580	83					(82	)	581	584	3
Other intangible assets	1,733	9	(136	)			20		1,626	2,035	409
	4,166	1,395	(1,989	)			75		3,647	8,556	4,909
Intangible assets with indefinite useful lives
Goodwill	3,531				15		864		4,410
	7,697	1,395	(1,989	)	15		939		8,057

Exploration expenditures in the amount of euro 631 million mainly related to license acquisition costs that are amortized on a straight-line basis over the contractual term of the exploration lease or fully written off against profit and loss in case of release or when no future activity is planned. Additions for the year included exploration drilling expenditures which were fully amortized as incurred in the amount of euro 1,271 million (euro 1,715 million as of December 31, 2008).
Concessions, licenses, trademarks and similar items in the amount of euro 671 million primarily comprised of transmission rights for natural gas imported from Algeria (euro 452 million) and concessions for mineral exploration (euro 157 million).

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Other intangible assets with finite useful lives in the amount of euro 1,626 million primarily referred to: (i) customer relationship and order backlog in the amount of euro 1,244 million (euro 1,355 million as of December 31, 2008) recognized after the acquisition of control on Distrigas NV. These assets are amortized on the basis of the supply contract with the longest term (19 years) and the residual useful life of the sale contract (4 years); (ii) the development project of the gas storage capacity recognized after the acquisition of control of Eni Hewett Ltd in the amount of euro 234 million (euro 208 million as of December 31, 2008); (iii) royalties for the use of licenses by Polimeri Europa SpA in the amount of euro 68 million (euro 72 million as of December 31, 2008); (iv) estimated costs for Eni’s social responsibility projects in relation to oil development programs in Val d’Agri in the amount of euro 38 million (euro 18 million at December 31, 2008) following commitments made with the Basilicata Region.
The depreciation rates used were as follows:

(%)
Exploration expenditures	14	-	33
Industrial patents and intellectual property rights	20	-	33
Concessions, licenses, trademarks and similar items	3	-	33
Other intangible assets	4	-	25

Other changes of intangible assets with a definite useful live in the amount of euro 75 million include negative currency translation differences of euro 5 million.
Changes in the scope of consolidation related to intangible assets with indefinite useful live (goodwill) in the amount of euro 15 million mainly refers to the acquisition of Seacom SpA (euro 13 million).
The carrying amount of goodwill as of December 31, 2009 was euro 4,410 million (euro 3,531 million as of December 31, 2008). The break-down by operating segment is as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Exploration & Production	243	249
Gas & Power	2,400	3,328
Refining & Marketing	142	84
Engineering & Construction	746	749
	3,531	4,410

Goodwill acquired through business combinations has been allocated to the cash generating units ("CGUs") that are expected to benefit from the synergies of the acquisition. The recoverable amount of the CGUs is the higher of: (i) fair value less costs to sell if there is an active market or recent transactions for similar assets within the same industry between knowledgeable and willing parties; (ii) value-in-use which is determined by discounting the estimated future cash flows based of the best information available at the moment of the assessment which is derived from: (a) the Company’s four-year plan approved by top management that provides information on the expected oil and gas production, sales volumes, capital expenditures, operating costs and margins and industrial and marketing set-up, as well as trends on the main monetary variables, including inflation, nominal interest rates and exchange rates. For the subsequent years beyond the four-year plan, a nominal growth rate is used ranging from 0% to 2%; (b) the commodity prices have been assessed based on the forward prices prevailing on the market place as of the balance sheet date for the first four years of the cash flow projections and the long-term price assumptions adopted by the Company’s top management for strategic planning purposes for the following years (see "Basis of presentation").
Value-in-use is determined by discounting post-tax cash flows at the following rates: (i) in the Exploration & Production and Refining & Marketing and Petrochemicals segments, impairment rates correspond to the Company’s weighted average cost of capital, as adjusted to consider risks specific to each country of activity (adjusted post-tax WACC). For 2009, the adjusted post-tax rates used for impairment testing showed an increase of 0.5 percentage points on average from the previous year as a result of a higher market premium for the equity risk and the country risk. Such increases were partially reduced by decreased nominal interest rates reflected in the cost of borrowings and in rates of assets risk-free. For 2009, the adjusted post-tax rates ranged from 9% to 13.5%; (ii) for the Gas & Power and Engineering & Construction segments, specific adjusted post-tax WACC have been used. For the Gas & Power segment it has been estimated on the basis of a sample of companies operating in the same segment, for the Engineering & Construction segment on the basis of market data. Rates used for impairments in the Gas & Power segment has been adjusted to take into consideration risks specific to each country of activity, while rates used in the Engineering & Construction segment has not been adjusted as most of the company assets are not permanently located in a specific country.

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Rates for the Gas & Power segment have ranged from 7% to 8%, representing a reduction of 0.5 percentage points on average from the previous year, which reflects decreased nominal interest rates, while the equity risk for utilities has remained unchanged. In the Engineering & Construction segment, rates at 8.5% have increased on average by 0.5 percentage points due to higher equity risk; (iii) for the regulated activities in the Italian natural gas sector, the discount rates have been assumed equal to the rates of return defined by the Italian Authority for Electricity and Gas.
Post-tax cash flows and discount rates have been adopted as they result in an assessment that is substantially equal to a pre-tax assessment.
Goodwill has been allocated to the following CGUs:

Gas & Power segment

(euro million) Dec. 31, 2008 Dec. 31, 2009

Domestic gas market	743	766
Foreign gas market	1,342	2,247
- of which European market (Distrigas)	1,248	2,148
Domestic natural gas transportation network	305	305
Other	10	10
	2,400	3,328

Goodwill allocated to the CGU domestic gas market primarily related to goodwill recognized upon the buy-out of minorities in Italgas SpA in 2003 through a public offering (euro 706 million). The key assumptions adopted for assessing the recoverable amount of the CGU which exceeds its carrying amount included commercial margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers has been collected from the four-year-plan approved by the Company’s top management that factored in revised downward prospects of gas demand growth in Italy. The terminal value was estimated based on the perpetuity method of the last-year-plan assuming a long-term nominal growth rate equal to zero. The excess of the recoverable amount of the domestic gas market CGU over its carrying amount including the allocated portion of goodwill (headroom) would be reduced to zero under each of the following hypothesis: (i) a decrease of 28.7% on average in the projected commercial margins; (ii) a decrease of 28.7% on average in the projected sales volumes; (iii) an increase of 3.4 percentage points in the discount rate; (iv) a negative nominal growth rate of 4.4%. The recoverable amount of the CGU domestic gas market and the relevant sensitivity analysis were calculated solely on the basis of retail margins, thus excluding wholesale and business client margins (industrial, thermoelectric and others).
Goodwill allocated to the CGU represented by the European gas market was recognized upon acquisition of the Belgian company Distrigas NV that was acquired in two different steps: (i) a controlling interest of 57.24% was acquired in October 2008 and (ii) a mandatory tender offer was finalized on the minorities of Distrigas and the subsequent squeeze-out at the same price of the acquisition of the controlling interest. Such goodwill has been allocated to the CGU that is expected to benefit from the synergies of the acquisition corresponding to the European market that includes the activities of Distrigas and other European marketing activities conducted by the Gas & Power Division of Eni SpA. Key assumptions adopted for assessing the recoverable amount of the European market CGU which exceeds its carrying amount included commercial margins, forecast sales volumes, the discount rate and the growth rates adopted to determine the terminal value. The determination of the value-in use is based on the four-year-plan approved by Eni’s top management which assumed full integration of the Distrigas activities with other European activities. The plan also factored in the revised downward prospects for gas demand growth in Europe and consistent projection on marketing margins. The terminal value was estimated based on the perpetuity method of the last-year-plan assuming a long-term nominal growth rate equal to 1.6%. The excess of the recoverable amount of the European market CGU over its carrying amount including the allocated portion of goodwill (headroom) would be reduced to zero under each of the following hypothesis: (i) a decrease of 40.9% on average in the projected marketing margins; (ii) a decrease of 40.9% on average in planned sales volumes; (iii) an increase of 3.9 percentage points in the discount rate; (iv) a negative nominal growth rate of 4.0%.
Goodwill allocated to the domestic natural gas transportation network CGU referred to the purchase of own shares by Snam Rete Gas SpA and it is equal to the difference between the purchase price over the carrying amount of the corresponding share of equity. The recoverable amount of the CGU is assessed based on its Regulatory Asset Base (RAB) as recognized by the Italian Authority for Electricity and Gas and it is higher than its carrying amount, including the allocated goodwill. Management believes that no reasonably possible change in the assumptions adopted would cause the headroom of the CGU to be reduced to zero.

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Engineering & Construction segment

(euro million) Dec. 31, 2008 Dec. 31, 2009

Offshore constructions	416	416
Onshore constructions	314	317
Other	16	16
	746	749

The Engineering & Construction segment’s goodwill in the amount of euro 749 million was mainly recognized following the acquisition of Bouygues Offshore SA, now Saipem SA (euro 711 million).
The key assumptions adopted for assessing the recoverable amount of the CGUs which exceeds the carrying amount referred to operating results, the discount rate and the growth rates adopted to determine the terminal value. Information on these drivers has been collected from the four-year-plan approved by the Company’s top management while the terminal value has been estimated by using a perpetual nominal growth rate of 2% applied to the cash flow of the four-year period. The following changes in each of the assumptions, ceteris paribus would cause the headroom of the Offshore construction CGU to be reduced to zero: (i) a decrease of 56% of the operating result of the four years of the plan; (ii) increase of 8 percentage points of the discount rate; and (iii) a negative real growth rate.
Changes in each of the assumptions, ceteris paribus that would cause the headroom of the Onshore construction CGU to be reduced to zero are greater than those of the Offshore construction CGU described above.
The Exploration & Production and the Refining & Marketing segments tested their goodwill, yielding the following results: (i) in the Exploration & Production segment (euro 249 million of carrying amount), management believes that there are no reasonably possible changes in the pricing environment and production/cost profiles that would cause the headroom of the relevant CGUs to be reduced to zero. Goodwill mainly refers to the portion of the acquisition cost that was not allocated to proved or unproved mineral interests from the business combinations of Lasmo, Burren Energy (Congo) and First Calgary. The change in goodwill recorded by the segment in the period derived from the completion of the purchase price allocation of First Calgary in the amount of euro 65 million; (ii) in the Refining & Marketing segment (euro 84 million), the Company recorded an impairment charge in the amount of euro 58 million, of which euro 48 million related to goodwill allocated to the fuel retail business assets and aviation fuel supply business recently acquired in Central-Eastern Europe driven by lower expectations for margins/volumes due to decreased fuel demand caused by the economic downturn and loss of market share and an impairment charge in the amount of euro 10 million related to goodwill allocated to minor assets. Net of this impairment, the residual goodwill primarily referred to the retail network CGUs which relates to the acquisitions in Czech Republic, Hungary and Slovakia.
Other changes in intangible assets with a indefinite useful lives in the amount of euro 864 million include the accounting of goodwill related to the acquisition of 42.757% of Distrigas NV, following the finalization of the mandatory tender offer for the minorities with a 41.617% adhesion of the share capital, including the 31.25% interest of Publigaz SCRL, the other major stakeholder of Distrigas, and the 1.14% interest through the squeeze-out procedure (euro 903 million) and, as a decrease, the impairments in the amount of euro 58 million related to the Refining & Marketing segment as described above.

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11 Investments

Investments accounted for using the equity method
Equity-accounted investments were as follows:

(euro million) Value at the beginning of the year Acquisition and subscriptions Share of profit of equity-accounted investments Share of loss of equity-accounted investments Deduction for dividends Currency translation differences Other changes Value at the end of the year

Dec. 31, 2008
Investments in unconsolidated entities controlled by Eni	141	41	27	(6	)	(5	)	3		(24	)	177
Joint ventures	3,310	47	536	(94	)	(444	)	(123	)	25		3,257
Associates	2,188	289	198	(5	)	(266	)	35		(402	)	2,037
	5,639	377	761	(105	)	(715	)	(85	)	(401	)	5,471
Dec. 31, 2009
Investments in unconsolidated entities controlled by Eni	177	1	42	(4	)	(8	)	(3	)	12		217
Joint ventures	3,257	25	478	(81	)	(254	)	(54	)	(44	)	3,327
Associates	2,037	200	173	(156	)	(122	)	(31	)	183		2,284
	5,471	226	693	(241	)	(384	)	(88	)	151		5,828

Acquisitions and subscriptions in the amount of euro 226 million relates to the increase in subscription of capital in the amount of euro 224 million, of which euro 181 million related to Angola LNG Ltd.
Share of profit of equity-accounted investments and the decrease following the distribution of the dividends referred to the following companies:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Share of profit of equity-accounted investments Deduction for dividends Eni’s interest % Share of profit of equity-accounted investments Deduction for dividends Eni’s interest %

Galp Energia SGPS SA	39	88	33.34	116	64	33.34
Unión Fenosa Gas SA	200	185	50.00	108	138	50.00
Artic Russia BV	29		60.00	103		60.00
Trans Austria Gasleitung GmbH	39	28	89.00	84	22	89.00
Eni BTC Ltd	16		100.00	35		100.00
Blue Stream Pipeline Co BV	34		50.00	33		50.00
United Gas Derivatives Co	107	127	33.33	24	40	24.55	(*)
EnBW Eni Verwaltungsgesellschaft mbH	40	22	50.00	15		50.00
Supermetanol CA	39	34	34.51	6	13	34.51
Other investments	218	231		169	107
	761	715		693	384

(*) Equity ratio 33.33.

Share of loss of equity-accounted investments in the amount of euro 241 million primarily relates to Ceska Rafinerska AS (euro 140 million) as a result of an impairment test on the refinery, Transmediterranean Pipeline Co Ltd (euro 30 million) and Super Octanos CA (euro 21 million) following the impairment on the relevant CGU mainly due to the negative trends in exchange rates.
Other changes in the amount of euro 151 million include the reclassification from receivables made for operating financing purposes associated with the contribution of the Venezuelan activities of Corocoro (euro 153 million) to PetroSucre SA. Also an increase was recorded upon reclassification from assets classified as held for sale of Fertilizantes Nitrogenados de Oriente (euro 68 million). A decrease was recorded as a capital reimbursement was made by the joint venture Artic Russia BV (euro 111 million) upon divestment of a 51% stake in the 60-40% owned joint-venture OOO SeverEnergia following the exercise of the call option by Gazprom on September 23, 2009. The transaction is worth U.S. $940 million net to Eni. Eni collected the first tranche of the price corresponding to approximately 25% of the whole amount for euro 155 million (or U.S. $230 million at the EUR/USD exchange rate of

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1.48 as of the transaction date). A gain was recognized in the profit and loss on equity-accounted evaluation of the investments in Artic Russia BV in the amount of euro 103, of which euro 100 million related to the contractual remuneration at an annual rate of 9.4% accruing on the initial investment in the venture when it was acquired on April 4, 2007 in accordance with the arrangements between Eni and Gazprom.
The following table sets out the net carrying amount relating to equity-accounted:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Net carrying amount Eni’s interest % Net carrying amount Eni’s interest %

Investments in unconsolidated entities controlled by Eni:
- Eni BTC Ltd	62	100.00	93	100.00
- Other investments (1)	115		124
	177		217
Joint ventures:
- Artic Russia BV	895	60.00	918	60.00
- Unión Fenosa Gas SA	499	50.00	473	50.00
- Blue Stream Pipeline Co BV	351	50.00	371	50.00
- EnBW Eni Verwaltungsgesellschaft mbH	268	50.00	284	50.00
- Azienda Energia e Servizi Torino SpA	166	49.00	170	49.00
- Eteria Parohis Aeriou Thessalonikis AE	158	49.00	161	49.00
- Toscana Energia SpA	136	49.38	143	49.38
- Raffineria di Milazzo ScpA	128	50.00	128	50.00
- Trans Austria Gasleitung GmbH	109	89.00	170	89.00
- Super Octanos CA	90	49.00	66	49.00
- Supermetanol CA	90	34.51	80	34.51
- Unimar Llc	65	50.00	72	50.00
- Eteria Parohis Aeriou Thessalias AE	42	49.00	43	49.00
- Starstroi Llc	19	50.00	31	50.00
- Transmediterranean Pipeline Co Ltd	40	50.00	8	50.00
- Transitgas AG	33	46.00	33	46.00
- Altergaz SA	25	38.91	28	41.62
- Other investments (1)	143		148
	3,257		3,327
Associates:
- Galp Energia SGPS SA	862	33.34	914	33.34
- Angola LNG Ltd	453	13.60	612	13.60
- Ceska Rafinerska AS	323	32.44	184	32.44
- PetroSucre SA	19	26.00	176	26.00
- United Gas Derivatives Co	128	33.33	84	24.55	(2)
- Fertilizantes Nitrogenados de Oriente CEC	68	20.00	68	20.00
- ACAM Gas SpA	46	49.00	47	49.00
- Distribuidora de Gas del Centro SA	32	31.35	29	31.35
- Other investments (1)	106		170
	2,037		2,284
	5,471		5,828

(1)	Each individual amount included herein did not exceed euro 25 million.
(2)	Equity ratio 33.33.

The net carrying amount of investments in unconsolidated entities controlled by Eni, joint ventures and associates include the differences between the purchase price and Eni’s equity in investments of euro 521 million. Such differences primarily related to Unión Fenosa Gas SA (euro 195 million), EnBW - Eni Verwaltungsgesellschaft mbH (euro 181 million) and Galp Energia SGPS SA (euro 106 million).

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The fair value of listed investments was as follows:

Shares Ownership
(%) Price per share
(euro) Fair value
(euro million)

Galp Energia SGPS SA	276,472,161	33.34	12.08	3,340
Altergaz SA	1,123,954	41.62	29.80	33

The table below sets out the provisions for losses included in the provisions for contingencies in the amount of euro 170 million (euro 119 million as of December 31, 2008), which primarily relate to the following equity-accounted investments:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Industria Siciliana Acido Fosforico - ISAF SpA (under liquidation)	27	64
Cardon IV SA	11	32
Polimeri Europa Elastomeres France SA (under liquidation)	31	32
Charville - Consultores e Serviços Lda	33	21
Southern Gas Constructors Ltd	17	13
Other investments		8
	119	170

Other investments
Other investments were as follows:

(euro million) Net value at the beginning of the year Acquisition and subscriptions Currency translation differences Other changes Net value at the end of the year Gross value at the end of the year Accumulated impairment charges

Dec. 31, 2008
Investments in unconsolidated entities controlled by Eni	25	1			4		30	41	11
Associates	10				(6	)	4	28	24
Other investments	437	5	11		(77	)	376	382	6
	472	6	11		(79	)	410	451	41
Dec. 31, 2009
Investments in unconsolidated entities controlled by Eni	30		(1	)	15		44	55	11
Associates	4				4		8	8
Other investments	376	4	(7	)	(9	)	364	371	7
	410	4	(8	)	10		416	434	18

Investments in unconsolidated entities controlled by Eni and associates are stated at cost net of impairment losses. Other investments, for which fair value cannot be reliably determined, were recognized at cost and adjusted for impairment losses.

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The net carrying amount of other investments in the amount of euro 416 million (euro 410 million as of December 31, 2008) was related to the following entities:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Net carrying amount Eni’s interest % Net carrying amount Eni’s interest %

Investments in unconsolidated entities controlled by Eni (*)	30		44
Associates	4		8
Other investments:
- Interconnector (UK) Ltd	135	16.06	134	16.06
- Nigeria LNG Ltd	85	10.40	82	10.40
- Darwin LNG Pty Ltd	83	10.99	78	10.99
- Other (*)	73		70
	376		364
	410		416

(*) Each individual amount included herein did not exceed euro 25 million.

Provisions for losses related to other investments, included within the provisions for contingencies, amounted to euro 41 million (euro 44 million as of December 31, 2008) and were primarily in relation to the following entities:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Burren Energy Ship Management Ltd	17	25
Caspian Pipeline Consortium R - Closed Joint Stock Co	24	15
Other investments	3	1
	44	41

Other information about investments
The following table summarizes key financial data, net to Eni, as disclosed in the latest available financial statements of unconsolidated entities controlled by Eni, joint ventures and associates:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Unconsolidated entities controlled by Eni Joint ventures Associates Unconsolidated entities controlled by Eni Joint ventures Associates

Total assets	1,361	7,761	4,020	2,215		6,981	4,218
Total liabilities	1,230	4,565	1,958	2,081		3,721	1,929
Net sales from operations	134	5,303	5,067	65		3,936	5,718
Operating profit	2	736	702	(48	)	564	141
Net profit	20	490	690	(9	)	474	101

The total assets and liabilities of unconsolidated controlled entities of euro 2,215 million and euro 2,081 million, respectively (euro 1,361 million and euro 1,230 million as of December 31, 2008) concerned for euro 1,873 million and euro 1,860 million (euro 923 million and euro 923 million as of December 31, 2008) entities for which the consolidation does not produce significant effects. The residual amount referred to controlled entities which are not consolidated due to their immateriality based on the criteria of significance indicated in the "Basis of presentation".

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12 Other financial assets
Other financing receivables were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Receivables for financing operating activities	1,084	1,112
Securities held for operating purposes	50	36
	1,134	1,148

Financing receivables are presented net of the allowance for impairment losses in the amount of euro 29 million (euro 26 million as of December 31, 2008).
Operating financing receivables in the amount of euro 1,112 million (euro 1,084 million as of December 31, 2008) primarily consist of loans entered into by the Exploration & Production segment (euro 580 million), Gas & Power segment (euro 311 million) and Refining & Marketing segment (euro 111 million), as well as receivables for financial leasing of euro 97 million (euro 128 million as of December 31, 2008). Receivables for financial leasing related to the disposal of the Belgian gas network by Finpipe GIE are included in the consolidation area after the acquisition of control by Gas & Power segment of Distrigas NV. The following table shows principal receivable by maturity date, which was obtained by summing future lease payment receivables discounted at the effective interest rate, interests and the nominal value of future lease receivables:

(euro million) Maturity range

Within 12 months Between one and five years Beyond five years Total

Principal receivable	19	77	20	116
Interests	6	11	1	18
Undiscounted value of future lease payments	25	88	21	134

Receivables with a maturity date within one year are shown in current assets in the trade receivables for operating purposes - current portion of long-term receivables in Note 3 – Trade and other receivables.
Receivables in currencies other than euro amounted to euro 716 million (euro 827 million as of December 31, 2008).
Receivables due beyond five years amounted to euro 460 million (euro 617 million as of December 31, 2008).
Securities in the amount of euro 36 million (euro 50 million as of December 31, 2008), designated as held-to-maturity investments, are listed securities, issued by the Italian Government (euro 21 million) and by foreign governments (euro 15 million). The decrease of euro 14 million relates to Banque Eni SA.
Securities with a maturity beyond five years amounted to euro 20 million.
The fair value of financing receivables and securities did not differ significantly from their carrying amount. The fair value of financing receivables has been determined based on the present value of expected future cash flows discounted at rates ranging from 1.0% to 4.5% (1.9% and 3.9% as of December 31, 2008). The fair value of securities was derived from quoted market prices.
Receivables with related parties are described in Note 36 – Transactions with related parties.

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13 Deferred tax assets
Deferred tax assets were recognized net of deferred tax liabilities able to be offset in the amount of euro 3,764 million (euro 3,468 million as of December 31, 2008).

(euro million) Value at
Dec. 31, 2008 Additions Deductions Currency translation differences Other changes Value at
Dec. 31, 2009

2,912 1,715 (1,078 ) (28 ) 37 3,558

Deferred tax assets are described in Note 23 – Deferred tax liabilities.

14 Other non-currentreceivables
The following table provides an analysis of other non-current receivables:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Tax receivables from:
- income tax	24	18
- interest on tax credits	58	55
- Value Added Tax (VAT)	2
	84	73
- foreign tax authorities	28	39
	112	112
Other receivables:
- in relation to disposals	780	710
- other non-current receivables	268	215
	1,048	925
Fair value of non-hedging derivatives	480	339
Fair value of cash flow hedge derivative instruments	197	129
Other asset	44	433
	1,881	1,938

Other receivables related to disposals in the amount of euro 710 million relate to: (i) a receivable of euro 421 million recognized upon the agreement signed with the Republic of Venezuela whereby Eni will receive a cash compensation for the expropriated Dación assets, part of which was already collected. Eni is set to collect seven annual installments which yield interest income from the date of the agreement. The 2009 installment of euro 71 million ($104 million) was paid through an equivalent assignment of hydrocarbons (compensation in-kind); (ii) a receivable of euro 279 million related to the disposal of the interest of 1.71% in the Kashagan project to the local partner KazMunaiGas on the basis of the agreements defined with the international partners of the North Caspian Sea PSA and the Kashagan government, which were effective starting from January 1, 2008.

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The fair value of derivative contracts which do not meet the criteria to be classified as hedges under IFRS was as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Fair value Purchase commitments Sale
commitments Fair value Purchase commitments Sale
commitments

Non-hedging derivatives on exchange rate
Interest Currency Swap	106	403	120	112	458	197
Currency swap	1	1	11	7	333	33
Other	29	13	48
	136	417	179	119	791	230
Non-hedging derivatives on interest rate
Interest rate swap	27	217	403	46	677	563
	27	217	403	46	677	563
Non-hedging derivatives on commodities
Over the counter	317	207	859	172	540	659
Other				2	37
	317	207	859	174	577	659
	480	841	1,441	339	2,045	1,452

The fair value of the derivative contracts is determined using market quotations provided by primary info-provider, or in the absence of such market information, the appropriate valuation methods generally accepted in the marketplace.
Fair values of non-hedging derivatives in the amount of euro 339 million (euro 480 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.
Fair value of the cash flow hedge derivatives in the amount of euro 129 million referred to Distrigas NV. Further information on cash flow hedge derivatives is provided in Note 19 – Other current liabilities. Fair value related to the contracts expiring beyond 2010 is provided in Note 24 – Other non-current liabilities; fair value related to the contracts expiring in 2010 is included in Note 7 – Other current assets and in Note 19 – Other current liabilities. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and in Note 30 – Operating expenses.
The nominal value of cash flow hedge derivatives relating to purchase and sale commitments amounted to euro 29 million and euro 427 million, respectively.
Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.
Other asset in the amount of euro 433 million (euro 44 million as of December 31, 2008) included a deferred cost that relates to amounts of gas which were collected below minimum take quantities for the year provided by take-or-pay clauses contained in certain long-term gas purchase contracts. Those volumes were recorded to offset a trade payable for an amount of euro 255 million based on the contractual purchase price formula provided in the relevant contractual arrangements and the contractual percentage of advance, as aligned to their net realizable value as of year end. The Company expects to collect the underlying gas volumes over a period longer than the next twelve months.

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Current liabilities

15 Short-term debt
Short-term debt was as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Banks	2,411	683
Ordinary bonds	3,663	2,718
Other financial institutions	285	144
	6,359	3,545

Short-term debt decreased by euro 2,814 million primarily due to the balance of repayments and new proceeds (euro 2,889 million), partially offset by currency translation differences (euro 97 million). Debt comprised of commercial paper in the amount of euro 2,718 million (euro 3,663 million as of December 31, 2008) which was mainly issued by the financial company Eni Finance USA Inc (euro 2,020 million) and Eni Coordination Center SA (euro 698 million).
Short-term debt per currency is shown in the table below:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Euro	3,801	1,143
U.S. dollar	1,332	2,321
Other currencies	1,226	81
	6,359	3,545

In 2009, the weighted average interest rate on short-term debt was 0.8% (4.2% in 2008).
As of December 31, 2009 Eni had undrawn committed and uncommitted borrowing facilities available in the amount of euro 2,241 million and euro 9,533 million, respectively (euro 3,313 million and euro 7,696 million as of December 31, 2008). These facilities were under interest rates that reflected market conditions. Charges in unutilized facilities were not significant.


16 Trade and other payables
Trade and other payables were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Trade payables	12,590	10,078
Advances	2,916	3,230
Other payables:
- related to capital expenditures	1,716	1,541
- others	3,293	4,325
	5,009	5,866
	20,515	19,174

The decrease in trade payables in the amount of euro 2,512 million was primarily related to the Gas & Power segment (euro 1,640 million), the Engineering & Construction segment (euro 619 million), the Exploration & Production segment (euro 566 million) which was offset by an increase in the Refining & Marketing segment (euro 266 million).
Advances in the amount of euro 3,230 million (euro 2,916 million as of December 31, 2008) were related to advances on contract work in progress in the amount of euro 2,590 million (euro 2,516 million as of December 31, 2008) and other advances in the amount of euro 640 million (euro 400 million as of December 31, 2008).
Advances on contract work in progress related to the Engineering & Construction segment.

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Other payables were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Payables due to:
- joint venture operators in exploration and production activities	2,007	2,305
- suppliers in relation to investments	1,057	809
- non-financial government entities	441	661
- employees	400	451
- social security entities	284	292
	4,189	4,518
Other payables	820	1,348
	5,009	5,866

Payables with related parties are described in Note 36 – Transactions with related parties.
The fair value of trade and other payables did not differ significantly from their carrying amount considering the short-term maturity of trade payables.


17 Income taxes payable
Income taxes payable were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Italian subsidiaries	808	363
Foreign subsidiaries	1,141	928
	1,949	1,291

Income taxes payable by Italian subsidiaries were affected by the fair value valuation of cash flow hedging derivatives (euro 137 million). Further information is provided in Note 19 – Other current liabilities.


18 Other taxes payable
Other taxes payable were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Excise and customs duties	920	832
Other taxes and duties	740	599
	1,660	1,431

19 Other current liabilities
Other current liabilities were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Fair value of non-hedging derivatives	1,418	691
Fair value of cash flow hedge derivatives	452	680
Other liabilities	1,993	485
	3,863	1,856

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Fair value of non-hedging derivative contracts was as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments

Non-hedging derivatives on exchange rate
Currency swap	211	1,234	2,379	113	3,044	2,487
Interest currency swap	78	694	60	8	113
Other	299	101	1,181	135	107	684
	588	2,029	3,620	256	3,264	3,171
Non-hedging derivatives on interest rate
Interest rate swap	5	500		15		816
	5	500		15		816
Non-hedging derivatives on commodities
Over the counter	769	2,528	191	415	1,244	549
Other	56	66	119	5	2	54
	825	2,594	310	420	1,246	603
	1,418	5,123	3,930	691	4,510	4,590

Fair value of derivative contracts was determined by using market quotations given by primary info-providers, or, absent market information, on the basis of valuation models generally accepted in the marketplace.
Fair values of non-hedging derivatives in the amount of euro 691 million (euro 1,418 million as of December 31, 2008) consisted of derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.
The fair value of cash flow hedges amounted to euro 680 million (euro 452 million as of December 31, 2008) and related to Exploration & Production segment in the amount of euro 369 million and Distrigas NV in the amount of euro 311 million (euro 37 million and euro 415 million as of December 31, 2008, respectively). Fair value related to the Exploration & Production segment referred to the fair value of the future sale agreements of the proved oil reserves with deadlines in 2010. Those derivatives were entered into to hedge exposure to variability in future cash flows deriving from the sales during the 2008-2011 period of approximately 2% of Eni’s proved reserves as of December 31, 2006 corresponding to 125.7 mmbbl, decreasing to 37.5 mmbbl as of December 31, 2009 due to transactions settled in the past year. These hedging transactions were undertaken in connection with acquisitions of oil and gas assets in the Gulf of Mexico and Congo that were executed in 2007. The Distrigas NV derivatives were designated to hedge surpluses or deficits of gas to achieve a proper balance in gas portfolio.
Fair value of contracts expiring by 2010 is provided in Note 7 – Other current assets; fair value of contracts expiring beyond 2010 is provided in Note 24 – Other non-current liabilities and in Note 14 – Other non-current assets. The effects of the evaluation at fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and in Note 30 – Operating expenses.
The nominal value of cash flow hedge derivatives relating to purchase and sale commitments amount to euro 1,882 million and euro 272 million, respectively (euro 989 million and euro 895 million as of December 31, 2008, respectively).
Information on the hedged risks and the hedging policies is provided in Note 28 – Guarantees, commitments and risks.
The decrease of other liabilities in the amount of euro 1,508 million mainly relate to the extinction of the euro 1,495 million put option exercised by Publigaz. Eni granted the put option to Publigaz (the Distrigas minority shareholder) to divest its 31.25% stake in Distrigas NV to Eni on the same per-share price of the mandatory tender offer to minorities as part of the Distrigas NV acquisition. The relevant liability was recognized with a corresponding entry in a reserve within equity.

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Non-current liabilities
20 Long-term debt and current maturities of long-term debt
Long-term debt included the current portion maturing during the year following the balance sheet date (current maturity). The table below analyzes debt by year of forecasted repayment:

(euro million) At December 31 Long-term maturity

Type of debt instrument Maturity range 2008 2009 Current maturity 2010 2011 2012 2013 2014 After Total

Banks	2010-2029	7,003	9,056	2,028	1,106	3,559	323	1,122	918	7,028
Ordinary bonds	2010-2037	6,843	11,687	1,111	141	38	1,589	1,314	7,494	10,576
Other financial institutions	2010-2021	632	512	52	95	63	55	51	196	460
		14,478	21,255	3,191	1,342	3,660	1,967	2,487	8,608	18,064

Long-term debt, including the current portion of long-term debt, of euro 21,255 million (euro 14,478 million as of December 31, 2008) increased by euro 6,777 million. The increase mainly reflected the balance of payments and new proceeds of euro 6,730 million as well as translation differences arising on debt taken on by euro-reporting subsidiaries denominated in a foreign currency which are translated into euros at the year-end exchange rates (euro 100 million). These increases were offset by currency translation differences resulting from the translation of financial statements denominated in currencies other than euro (euro 74 million).
Debt from banks in the amount of euro 9,056 million mainly relate committed and uncommitted borrowing facilities in the amount of euro 4,030 million.
Debt from other financial institutions in the amount of euro 512 million (euro 632 million as of December 31, 2008) included euro 24 million of finance lease transactions (euro 161 million as of December 31, 2008). The decrease of euro 137 million mainly referred to the exercise of the option to purchase a drilling rig by the Engineering & Construction segment.
Eni entered into long-term borrowing facilities with the European Investment Bank which were conditioned to the maintenance of certain performance indicators based on Eni’s consolidated financial statements or the maintenance of a minimum level of rating. According to the agreements, the lack of this latter condition required new guarantees, able to be accepted by the European Investment Bank, to be found. As of December 31, 2008 and 2009, the amount of short and long-term debt subject to restrictive covenants was euro 1,323 million and euro 1,508 million, respectively. Eni considers that the non-compliance with the above covenants does not produce relevant effects. Furthermore, Saipem SpA entered into certain borrowing facilities in the amount of euro 75 million (the same amount as of December 31, 2008) with a number of financial institutions subordinated to the maintenance of certain performance indicators based on the consolidated financial statements of Saipem. Eni and Saipem are in compliance with the covenants contained in their respective financing arrangements.
Bonds in the amount of euro 11,687 million consisted of bonds issued through the Euro Medium Term Notes Program for a total of euro 9,419 million and other bonds for a total of euro 2,268 million.

218

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table analyzes bonds per issuing entity, maturity date, interest rate and currency as of December 31, 2009:

Amount Discount on bond issue and accrued expense Total Currency Maturity % rate

(euro million) from to from to

Issuing entity
Euro Medium Term Notes
Eni SpA	1,500	58		1,558	EUR		2016		5.000
Eni SpA	1,500	44		1,544	EUR		2013		4.625
Eni SpA	1,500	8		1,508	EUR		2019		4.125
Eni SpA	1,250	66		1,316	EUR		2014		5.875
Eni SpA	1,250	(4	)	1,246	EUR		2017		4.750
Eni Coordination Center SA	733	6		739	GBP	2010	2019	4.875	6.125
Eni SpA	500	17		517	EUR		2010		6.125
Eni Coordination Center SA	350	10		360	EUR	2010	2028	2.876	5.600
Eni Coordination Center SA	346	2		348	YEN	2012	2037	1.150	2.810
Eni Coordination Center SA	176	3		180	USD	2013	2015	4.450	4.800
Eni Coordination Center SA	41	(1	)	40	EUR	2011	2015		variable
Eni Coordination Center SA	34			34	CHF		2010		2.043
Eni Coordination Center SA	31	(2	)	29	USD		2013		variable
	9,211	208		9,419
Other bonds
Eni SpA	1,000	7		1,007	EUR		2015		4.000
Eni SpA	1,000	(15	)	985	EUR		2015		variable
Eni USA Inc	277	(3	)	274	USD		2027		7.300
Eni UK Holding Plc	2			2	GBP		2013		variable
	2,279	(11	)	2,268
	11,490	197		11,687

As of December 31, 2009 bonds maturing within 18 months (euro 993 million) were issued by Eni Coordination Center SA in the amount of euro 476 million and by Eni SpA in the amount of euro 517 million. During 2009, Eni SpA issued bonds in the amount of euro 5,058 million.
The following table shows the currency composition of long-term debt and its current portion and the related weighted average interest rates on total borrowings.

Dec. 31, 2008
(euro million) Average rate
(%) Dec. 31, 2009
(euro million) Average rate
(%)

Euro	12,284	4.2	19,345	3.9
U.S. dollar	912	6.1	779	3.9
British pound	859	6.2	742	5.2
Japanese yen	367	2.0	348	2.0
Other currencies	56	3.8	41	3.0
	14,478		21,255

As of December 31, 2009 Eni had undrawn committed long-term borrowing facilities in the amount of euro 2,850 million (euro 1,850 million as of December 31, 2008). Interest rates on these contracts were at market conditions. Charges for unutilized facilities were not significant.

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ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Fair value of long-term debt, including the current portion of long-term debt amounted to euro 22,320 million (euro 15,247 million as of December 31, 2008) and consisted of the following:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Ordinary bonds	7,505	12,618
Banks	7,056	9,152
Other financial institutions	686	550
	15,247	22,320

Fair value was calculated by discounting the expected future cash flows at rates ranging from 1.0% to 4.5% (1.4% and 3.9% as of December 31, 2008).
As of December 31, 2009 Eni did not pledge restricted deposits as collateral against its borrowings (euro 151 million as of December 31, 2008).
Analysis of net borrowings, as defined in the "Financial Review", was as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Current Non-current Total Current Non-current Total

A. Cash and cash equivalents	1,939		1,939	1,608		1,608
B. Available-for-sale securities	185		185	64		64
C. Liquidity (A+B)	2,124		2,124	1,672		1,672
D. Financing receivables	337		337	73		73
E. Short-term debt towards banks	2,411		2,411	683		683
F. Long-term debt towards banks	147	6,856	7,003	2,028	7,028	9,056
G. Bonds	360	6,483	6,843	1,111	10,576	11,687
H. Short-term debt towards related parties	153		153	147		147
I. Long-term debt towards related parties		9	9
L. Other short-term debt	3,795		3,795	2,715		2,715
M. Other long-term debt	42	581	623	52	460	512
N. Total borrowings (E+F+G+H+I+L+M)	6,908	13,929	20,837	6,736	18,064	24,800
O. Net borrowings (N-C-D)	4,447	13,929	18,376	4,991	18,064	23,055

Available-for-sale securities in the amount of euro 64 million (euro 185 million as of December 31, 2008) were held for non-operating purposes. Not included in the calculation above were held-to-maturity and available-for-sale securities held for operating purposes amounting to euro 320 million (euro 360 million as of December 31, 2008), of which euro 284 million (euro 302 million as of December 31, 2008) were held to provide coverage of technical reserves for Eni’s insurance company, Eni Insurance Ltd.
Financing receivables in the amount of euro 73 million (euro 337 million as of December 31, 2008) were held for non-operating purposes.
Not included in the calculation above were financing receivables held for operating purposes amounting to euro 452 million (euro 487 million as of December 31, 2008), of which euro 245 million (euro 399 million as of December 31, 2008) were in respect of securities granted to unconsolidated subsidiaries, joint ventures and associates primarily in relation to the implementation of certain capital projects and a euro 179 million cash deposit (euro 47 million as of December 31, 2008) to provide coverage for Eni Insurance Ltd technical reserves. As of December 31, 2008, current financial receivables in the amount of euro 173 million referred to a restricted deposit held by Eni Lasmo Plc as a guarantee of a debenture.

220

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

21 Provisions for contingencies
Provisions for contingencies were as follows:

(euro million) Value at Dec. 31, 2008 Additions Changes of estimated expenditures Accretion discount Reversal of utilized provisions Reversal of unutilized provisions Other changes Value at Dec. 31, 2009

Provision for site restoration and abandonment	4,574		317	212		(191	)	(5	)	(110	)	4,797
Provision for environmental risks	1,980	280				(249	)	(22	)	(53	)	1,936
Provision for legal and other proceedings	812	372				(62	)	(39	)	85		1,168
Loss adjustments and actuarial provisions for Eni's insurance companies	404	135								(25	)	514
Provisions for the supply of goods	308	35		10								353
Provision for taxes	260	46						(1	)	(9	)	296
Provision for losses on investments	163	96						(39	)	(9	)	211
Provision for onerous contracts	4	115				(26	)			(3	)	90
Provision for OIL insurance	72	9				(1	)	(1	)			79
Other (*)	929	306	22	(4	)	(298	)	(72	)	(8	)	875
	9,506	1,394	339	218		(827	)	(179	)	(132	)	10,319

(*) Each individual amount included herein does not exceed euro 50 million.

Provision for site restoration and abandonment in the amount of euro 4,797 million primarily referred to the estimation of future costs relating to decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration (euro 4,500 million). The increase in the provision for the year amounted to euro 317 million and was primarily due to changes in the estimates of future costs made by Eni Petroleum Co Inc (euro 153 million), Eni UK Ltd (euro 76 million) and Eni SpA (euro 51 million). Also an amount of euro 212 million was recognized through profit and loss as the accretion charge for the period. The discount rates adopted ranged from 1.9% to 8.8% (from 3.3% to 6.2% for the year ended December 31, 2008). Other changes in the amount of euro 110 million mainly related to the reclassification of the liabilities directly associated with assets held for sale (euro 188 million).
Offsetting this effect were negative currency translation differences which resulted from the translation of financial statements denominated in currencies other than euro (euro 70 million).
Provision for environmental risks in the amount of euro 1,936 million primarily related to the estimated future costs of remediation in accordance with existing laws and regulations and the estimated costs of reclamation and restoration sanctioned by the competent authorities. These provisions mainly relate to Syndial SpA (euro 1,412 million) and to the Refining & Marketing segment (euro 394 million). The increases in the provision in the amount of euro 280 million were primarily related to Syndial SpA (euro 186 million) and the Refining & Marketing segment (euro 68 million). Decreases in the amount of euro 249 million were related to the reversal of utilized provisions primarily by the Refining & Marketing segment (euro 125 million) and Syndial SpA (euro 97 million).
Provision for legal and other proceedings in the amount of euro 1,168 million primarily included charges expected for the failure to perform certain contractual obligations and estimated future losses on pending litigation including legal, antitrust and administrative matters. These provisions are stated on the basis of Eni’s best estimate of the expected probable liability and primarily related to the Gas & Power segment (euro 476 million), Engineering & Construction segment (euro 278 million), Syndial SpA (euro 220 million), Eni Corporate (euro 79 million) and the Petrochemical segment (euro 34 million). The increases in the provision in the amount of euro 372 million includes the estimate of a non-recurring item represented by a charge amounting to euro 250 million that was estimated based on management’s best knowledge of the possible resolution of the TSKJ matter with US Authorities. The matter is fully disclosed in Note 28 – Guarantees, commitments and risks – Legal Proceedings. The charge is recognized in the segment results of the Engineering & Construction business as it relates to a project that was executed in Nigeria by the TSKJ joint venture. At the time of the project, the venture was participated by Snamprogetti Netherlands BV that was controlled by Snamprogetti SpA that was subsequently divested by the parent company Eni SpA to the subsidiary Saipem. On the occasion of the divestiture, Eni agreed to indemnify Saipem of all possible claims that might arise in connection with Snamprogetti involvement in the TSKJ venture. As a result, the future monetary settlement of the provision will be incurred by Eni SpA and Saipem’s minorities will be left unaffected altogether.
Loss adjustments and actuarial provisions for Eni’s insurance companies in the amount of euro 514 million represent the liabilities accrued for claims on insurance policies underwritten by Eni’s insurance company, Eni Insurance Ltd.
Provisions for the supply of goods in the amount of euro 353 million include the estimated costs of the supply contracts.

221

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Provision for taxes in the amount of euro 296 million primarily included charges for unsettled tax claims in connection with uncertain applications of tax regulations for foreign subsidiaries of the Exploration & Production segment (euro 176 million) and the Engineering & Construction segment (euro 66 million).
Provision for losses on investments in the amount of euro 211 million was made with respect to losses from investments in entities incurred to date, where the losses exceed the carrying amount of the investments.
Provision for onerous contracts in the amount of euro 90 million relate to contracts for which the termination or execution costs exceed the relevant benefits.
Provision for OIL insurance cover in the amount of euro 79 million include a mutual insurance provision related to future increase of insurance charges, as a result of accidents that occurred in past periods that will be paid in the next 5 years by Eni for participating in the mutual insurance of Oil Insurance Ltd.


22 Provisions for employee benefits
Provisions for employee benefits were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

TFR	458	445
Foreign pension plans	223	204
Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans	98	107
Other benefits	168	188
	947	944

Provisions for indemnities upon termination of employment primarily relate to the provisions accrued by Italian companies for employee termination indemnities ("TFR"), which are determined using actuarial techniques and is regulated by Article 2120 of the Italian Civil Code.
The indemnity is paid upon retirement as a lump sum payment in the amount which corresponds to the total provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in regime, starting from January 1, 2007 the amount already then accrued and future benefits will be put in pension funds or the treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, the allocation of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be classified as costs to provide benefits under a defined contribution plan. Past unpaid amounts accrued as of December 31, 2006 for post-retirement indemnities under the Italian TFR regime continue to represent costs to provide benefits under a defined benefit plan and must be assessed based on actuarial assumptions.
Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria and in Germany. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to retirement.
Group companies provide healthcare benefits to retired managers. Liability for these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the company.
Other benefits primarily related to a deferred cash incentive scheme for managers and certain Jubilee awards. The provision for the deferred cash incentive scheme is assessed based on the probability of the company reaching planned targets and employee reaching individual performance goals. Jubilee awards are benefits due following the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration.

222

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The value of employee benefits, estimated by applying actuarial techniques, consisted of the following:

Foreign pension plans

(euro million) TFR Gross liability Plan assets FISDE
and other foreign medical plans Other benefits Total

2008
Current value of benefit liabilities and plan assets at beginning of year	476		621		(362	)	92		118		945
Current cost			21				1		48		70
Interest cost	25		28				5		5		63
Expected return on plan assets					(25	)					(25	)
Employee contributions			(1	)	(41	)					(42	)
Actuarial gains (losses)	8		(11	)	102		3		3		105
Benefits paid	(65	)	(25	)	20		(7	)	(7	)	(84	)
Curtailments and settlements							(2	)			(2	)
Currency translation differences and other changes	(1	)	169		(147	)	2		1		24
Current value of benefit liabilities and plan assets at end of year	443		802		(453	)	94		168		1,054
2009
Current value of benefit liabilities and plan assets at beginning of year	443		802		(453	)	94		168		1,054
Current cost			27				2		45		74
Interest cost	26		22				6		6		60
Amendments			81				10				91
Expected return on plan assets					(16	)					(16	)
Employee contributions			1		(42	)					(41	)
Actuarial gains (losses)	18		301		(16	)	9		4		316
Benefits paid	(41	)	(45	)	22		(7	)	(39	)	(110	)
Curtailments and settlements			(15	)	14						(1	)
Currency translation differences and other changes	1		(28	)	(9	)	1		4		(31	)
Current value of benefit liabilities and plan assets at end of year	447		1,146		(500	)	115		188		1,396

The gross liability for foreign employee pension plans in the amount of euro 1,146 million (euro 802 million as of December 31, 2008) include the liabilities related to joint ventures operating in exploration and production activities in the amount of euro 77 million and euro 62 million as of December 31, 2008 and 2009, respectively. A receivable of an amount equivalent to such liability was recorded. Other benefits in the amount of euro 188 million (euro 168 million as of December 31, 2008) mainly relate to the deferred monetary incentive plan in the amount of euro 119 million (euro 107 million as of December 31, 2008) and Jubilee awards in the amount of euro 52 million (euro 47 million as of December 31, 2008).
The reconciliation analysis of benefit obligations and plan assets was as follows:

TFR Foreign pension plans FISDE and other foreign medical plans Other benefits

(euro million) Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009

Present value of benefit obligations with plan assets				610		935
Present value of plan assets				(453	)	(500	)
Net present value of benefit obligations with plan assets				157		435
Present value of benefit obligations without plan assets	443	447		192		211		94	115		168	188
Actuarial gains (losses) not recognized	15	(2	)	(126	)	(442	)	4	(6	)
Past service cost not recognized									(2	)
Net liabilities recognized in provisions for employee benefits	458	445		223		204		98	107		168	188

223

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Costs charged to the profit and loss account were as follows:

(euro million) TFR Foreign pension plans FISDE and other foreign medical plans Other benefits Total

2008
Current cost		21		1		48		70
Interest cost	25	28		5		5		63
Expected return on plan assets		(25	)					(25	)
Amortization of actuarial gains (losses)		1						1
Effect of curtailments and settlements				(2	)			(2	)
	25	25		4		53		107
2009
Current cost		27		2		45		74
Interest cost	26	22		6		6		60
Expected return on plan assets		(16	)					(16	)
Amortization of actuarial gains (losses)		10		7		4		21
Effect of curtailments and settlements		1				(3	)	(2	)
	26	44		15		52		137

The main actuarial assumptions used in the evaluation of post-retirement benefit obligations at year end and in the estimate of costs expected for 2010 were as follows:

(%) TFR Foreign pension plans FISDE and other foreign medical plans Other benefits

2008
Discount rate	6.0	3.5-13.0	6.0	5.2-6.0
Expected return rate on plan assets		4.5-13.0
Rate of compensation increase	2.7-3.0	2.4-13.0		2.7-4.0
Rate of price inflation	2.5	1.3-11.0	2.5	2.5
2009
Discount rate	5.0	2.7-11.0	5.0	2.0-5.0
Expected return rate on plan assets		4.0-13.0
Rate of compensation increase	3.0	2.7-14.0		2.7-4.0
Rate of price inflation	2.0	0.9-10.0	2.0	2.0

With regards to Italian plans, demographic tables prepared by Ragioneria Generale dello Stato (RG48) were used. Expected return rate by plan assets has been determined by reference to quoted prices expressed in regulated markets.
Plan assets consisted of the following:

(%) Plan assets Expected return

Securities	10.0	6.0-7.5
Bonds	28.8	2.4-13.0
Real estate	1.6	6.0-7.5
Other	59.6	0.5-13.0
Total	100.0

224

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The effective return of the plan assets amounted to zero (a cost in the amount of euro 77 million for the year ended December 31, 2008).
With reference to healthcare plans, the effects deriving from a 1% change of the actuarial assumptions of medical costs were as follows:

(euro million) 1% Increase 1% Decrease

Impact on the current costs and interest costs	1	(1	)
Impact on net benefit obligation	14	(12	)

The amount expected to be accrued for defined benefit plans in 2010 amounted to euro 88 million.
The analysis of changes in the actuarial valuation of the net liability with respect to prior year deriving from the non-correspondence of actuarial assumptions with actual values recorded at year-end was as follows:

(euro million) TFR Foreign pension plans FISDE and other foreign medical plans Other benefits

2008
Impact on net benefit obligation	7		15		3	1
Impact on plan assets			(62	)
2009
Impact on net benefit obligation	(7	)	4		3	2
Impact on plan assets			(16	)

23 Deferred tax liabilities
Deferred tax liabilities were recognized net of offsettable deferred tax assets in the amount of euro 3,764 million (euro 3,468 million as of December 31, 2008).

(euro million) Value at
Dec. 31, 2008 Additions Deductions Changes in the scope of consolidation Currency translation differences Other changes Value at
Dec. 31, 2009

5,784 631 (1,434 ) 3 (22 ) (55 ) 4,907

Deferred tax assets and liabilities consisted of the following:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Deferred tax liabilities	9,252		8,671
Deferred tax assets available for offset	(3,468	)	(3,764	)
	5,784		4,907
Deferred tax assets not available for offset	(2,912	)	(3,558	)
	2,872		1,349

225

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The most significant temporary differences giving rise to net deferred tax liabilities were as follows:

(euro million) Value at
Dec. 31, 2008 Additions Deductions Currency translation differences Other changes Value at
Dec. 31, 2009

Deferred tax liabilities:
- accelerated tax depreciation	5,366		238		(392	)	(6	)	(34	)	5,172
- site restoration and abandonment (tangible assets)	654		59		(132	)	27		(59	)	549
- capitalized interest expense	173		3		(15	)			(2	)	159
- application of the weighted average cost method in evaluation of inventories	79		31		(91	)			42		61
- other	2,980		300		(804	)	(43	)	297		2,730
	9,252		631		(1,434	)	(22	)	244		8,671
Deferred tax assets:
- site restoration and abandonment (provisions for contingencies)	(1,572	)	(84	)	100		(8	)	79		(1,485	)
- accruals for impairment losses and provisions for contingencies	(1,397	)	(334	)	309				32		(1,390	)
- depreciation and amortization	(910	)	(474	)	140		33		25		(1,186	)
- assets revaluation as per Laws No. 342/2000 and No. 448/2001	(735	)			58						(677	)
- carry-forward tax losses	(57	)	(150	)	40		(7	)			(174	)
- other	(1,709	)	(673	)	431		10		(469	)	(2,410	)
	(6,380	)	(1,715	)	1,078		28		(333	)	(7,322	)
Net deferred tax liabilities	2,872		(1,084	)	(356	)	6		(89	)	1,349

Deferred tax assets are recognized for deductible temporary differences to the extent that it is probable that sufficient taxable profit will be available against which part or all of the deductible temporary differences can be utilized. In the case where future taxable profit is no longer deemed to be sufficient to absorb all existing deferred tax assets, any surplus is written off.
Other changes in the amount of euro 89 million include the recognition of the deferred tax effect against equity on the fair value evaluation of derivatives designated as cash flow hedge in the amount of euro 65 million. Further information on cash flow hedge derivatives is provided in Note 19 – Other current liabilities.
Italian taxation law allows the carry-forward of tax losses over the five subsequent years. Losses suffered in the first three years of the company’s life can, however, be, for the most part, carried forward indefinitely. Foreign taxation laws allows, on average, the carry-forward of tax losses over a period higher than the five subsequent years, and in many cases, indefinitely. The tax rate applied by the Italian subsidiaries to determine the portion of carry-forwards tax losses to be utilized equaled 25.8%; this rate equaled on average to 28.2% for foreign entities.
Carry-forward tax losses in the amount of euro 1,532 million can be used in the following periods:

(euro million) Italian
subsidiaries Foreign
subsidiaries

2010
2011		2
2012		1
2013	7
2014	107	43
Beyond 2014	64	19
Without limit	16	1,273
	194	1,338

Carry-forward tax losses in the amount of euro 634 million expected to be offset against future taxable profit and were in respect of Italian subsidiaries in the amount of euro 194 million and of foreign subsidiaries in the amount of euro 440 million. Deferred tax assets recognized on these losses amounted to euro 50 million and euro 124 million, respectively.

226

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24 Other non-current liabilities
Other non-current liabilities were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Fair value of non-hedging derivatives	564	372
Fair value of cash flow hedge derivatives	499	436
Non-current liabilities for current income tax	254	52
Other payables	55	54
Other liabilities	1,730	1,566
	3,102	2,480

Fair value of derivative contracts was determined by using market quotations given by primary info-providers, or, in lack of market information, on the basis of generally accepted methods for financial valuations.
Fair value of non-hedging derivatives was as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Fair value Purchase commitments Sale commitments Fair value Purchase commitments Sale commitments

Non-hedging derivatives on exchange rate
Currency swap	82	694	100	10	296	94
Interest currency swap	4		40	23	394
Other	28	50	16
	114	744	156	33	690	94
Non-hedging derivatives on interest rate
Interest rate swap	129	141	3,002	137	41	4,030
	129	141	3,002	137	41	4,030
Non-hedging derivatives on commodities
Over the counter	321	769	197	199	850	219
Other				3	12	9
	321	769	197	202	862	228
	564	1,654	3,355	372	1,593	4,352

Fair value of non-hedging derivatives in the amount of euro 372 million (euro 564 million as of December 31, 2008) referred to derivative contracts that do not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage the net business exposures in foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives were not related to specific trade or financing transactions.
Fair value of cash flow hedge derivatives amounted to euro 436 million (euro 499 million as of December 31, 2008) related to Distrigas NV in the amount of euro 275 million (euro 235 million as of December 31, 2008) and the Exploration & Production segment in the amount of euro 161 million (euro 264 million as of December 31, 2008).
Further information on cash flow hedge derivatives is provided in Note 19 – Other current liabilities. Fair value of contracts expiring beyond 2010 is provided in Note 14 – Other non-current receivables; fair value of contracts expiring by 2010 is provided in Note 19 – Other current liabilities and Note 7 – Other current assets. The effects of the evaluation at the fair value of cash flow hedge derivatives are provided in Note 26 – Shareholders’ equity and Note 30 – Operating expenses.
The nominal value of the derivatives relating to purchase and sale commitments amounted to euro 1,544 million and euro 129 million, respectively (euro 1,878 million and 1,832 million as of December 31, 2008, respectively).
Information on the hedged risks and the hedging policies is shown in Note 28 – Guarantees, commitments and risks.
The group’s non-current liability for current income taxes in the amount of euro 52 million (euro 254 million as of December 31, 2008) was due as special tax (with a rate lower than the statutory tax rate), relating to the option to increase the deductible tax bases of certain tangible and other assets to their carrying amounts as permitted by the 2008 Budget Law.
Other liabilities in the amount of euro 1,566 million (euro 1,730 million as of December 31, 2008) included advances received by Suez following the long-term supplying of natural gas and electricity in the amount of euro 1,455 million (euro 1,552 million as of December 31, 2008).

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25 Assets held for sale and liabilities directly associated with assets held for sale
Non-current assets held for sale and liabilities directly associated with non-current assets held for sale amounted to euro 542 million and euro 276 million, respectively, which mainly relate to the divestment of certain mineral properties in Italy which were contributed in kind to two new entities Società Padana Energia SpA and Società Adriatica Idrocarburi SpA, for the disposal of Gas Brasiliano Distribuidora SA, a company operating in the distribution and marketing of natural gas in an area of São Paulo state in Brazil, and Distri RE SA, a company acquired following the acquisition of Distrigas NV. The disposals to third parties are under negotiation.


26 Shareholders’ equity

Minority interest
Profit attributable to minority interest and the minority interest in certain consolidated subsidiaries related to:

(euro million) Net profit Shareholders’ equity

2008 2009 Dec. 31, 2008 Dec. 31, 2009

Saipem SpA	407		567	1,560	2,005
Snam Rete Gas SpA	254		369	948	1,568
Hindustan Oil Exploration Co Ltd	(1	)	1	128	123
Tigàz Tiszàntùli Gàzszolgàltatò Részvénytàrsasàg	(11	)	8	65	72
Distrigas NV	74			1,162
Others	10		5	211	210
	733		950	4,074	3,978

The increase in Snam Rete Gas SpA equity is due to the increase in the share capital for the minority shareholders’ contribution (euro 1,542 million) partially offset by the effect of acquisition from Eni of Italgas SpA and Stogit SpA (euro 1,086 million). The zero amounts of the minority interests in Distrigas NV is due to the acquisition of the entire share capital of the company through the finalization of the mandatory tender offer on the minorities of Distrigas. Shareholders, including Publigaz with its entire interest (31.25%), tendered shares representing 41.617% of the share capital of Distrigas. The residual 1.14% of the share capital has been acquired by Eni through a squeeze-out.

Eni shareholders’ equity
Eni’s net equity as of December 31, 2008 and 2009 was as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Share capital	4,005		4,005
Legal reserve	959		959
Reserve for treasury shares	7,187		6,757
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect	(90	)	(439	)
Reserve related to the fair value of available-for-sale securities net of the tax effect	4		5
Other reserves	(1,054	)	1,492
Cumulative currency translation differences	(969	)	(1,665	)
Treasury shares	(6,757	)	(6,757	)
Retained earnings	34,685		39,160
Interim dividend	(2,359	)	(1,811	)
Net profit for the period	8,825		4,367
	44,436		46,073

Share capital
As of December 31, 2009 the parent company’s issued share capital consisted of 4,005,358,876 shares (nominal value euro 1 each) fully paid-up (the same amount as of December 31, 2008).
On April 30, 2009 Eni’s Shareholders’ Meeting declared a dividend distribution of euro 0.65 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2008 dividend of euro 1.30 per share, of which euro 0.65 per share paid as interim dividend. The balance was payable on May 21, 2009 to shareholders on the register as of May 18, 2009.

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Legal reserve
This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law.

Reserve for treasury shares
The reserve for treasury shares represents the reserve destined to purchase its own shares in accordance with the decisions reached at Eni’s Shareholders’ Meetings. The amount of euro 6,757 million (euro 7,187 million as of December 31, 2008) included treasury shares purchased. During the year 2009 the company has not purchased its own shares and the term established by Eni’s Shareholders’ Meetings for the purchase has expired. The residual amount of euro 430 million was taken to Retained earnings (euro 429 million) and Other reserves (euro 1 million).

Reserve referring to the valuation at fair value of cash flow hedging derivatives and available-for-sale securities, net of the related tax
The valuation of fair value of cash flow hedging derivatives and available-for-sale securities, net of the related tax, consisted of the following:

Available-for-sale securities Cash flow hedge derivatives Total

(euro million) Gross reserve Deferred tax liabilities Net reserve Gross reserve Deferred tax liabilities Net reserve Gross reserve Deferred tax liabilities Net reserve

Reserve as of December 31, 2007	2			2	(2,185	)	841		(1,344	)	(2,183	)	841		(1,342	)
Changes of the year 2008	3	(1	)	2	964		(364	)	600		967		(365	)	602
Changes in the scope of consolidation					(68	)	23		(45	)	(68	)	23		(45	)
Foreign currency translation differences					48		(23	)	25		48		(23	)	25
Amount recognized in the profit and loss account					1,005		(402	)	603		1,005		(402	)	603
Reserve as of December 31, 2008	5	(1	)	4	(236	)	75		(161	)	(231	)	74		(157	)
of which: Eni Group	5	(1	)	4	(128	)	38		(90	)	(123	)	37		(86	)
Changes of the year 2009	1			1	(636	)	246		(390	)	(635	)	246		(389	)
Foreign currency translation differences					3		(2	)	1		3		(2	)	1
Amount recognized in the profit and loss account					155		(44	)	111		155		(44	)	111
Reserve as of December 31, 2009	6	(1	)	5	(714	)	275		(439	)	(708	)	274		(434	)

The ineffective portion of the change in fair value of cash flow hedging derivatives (time value component) entered into by the Exploration & Production segment consisted of the following:

(euro million) Value at
Dec. 31, 2008 Changes recognized in profit and loss account Currency translation differences Value at
Dec. 31, 2009

(45 ) 6 1 (38 )

Other reserves
Other reserves of negative amount were euro 1,492 million (as of December 31, 2008 other reserves of negative amount were euro 1,054 million) and included:
- a reserve in the amount of euro 1,086 million related to the increase of Eni’s shareholders’ equity as a control to minority interest following the sale by Eni SpA of Italgas SpA and Stogit SpA to Snam Rete Gas SpA;
- a reserve in the amount of euro 247 million related to the increase of Eni’s shareholders’ equity as a control to minority interest following the sale by Eni SpA of Snamprogetti SpA to Saipem Projects SpA, both merged in Saipem SpA (same amount as of December 31, 2008);
- a reserve in the amount of euro 157 million deriving from Eni SpA’s equity (euro 194 million as of December 31, 2008);
- a reserve in the amount of euro 2 million related to the share of "Other comprehensive income" on equity-accounted entities;

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- as of December 31, 2008 other reserves of negative amount mainly related to the put option granted to Publigaz (the Distrigas minority shareholder) to divest its 31.25% stake in Distrigas NV valued at the same per-share price of the mandatory tender offer to minorities (euro 1,495 million). Publigaz agreed to the mandatory tender offer and the related reserve has been set to zero.

Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.

Treasury shares
A total of 382,952,240 ordinary shares (382,954,240 as of December 31, 2008) with a nominal value of euro 1 each, were held in treasury, for a total cost of euro 6,757 million (same amount as of December 31, 2008). During the year 2009 the company has not purchased its own shares and the term established by Eni’s Shareholders’ Meetings for the purchase has expired. 19,482,330 treasury shares (23,557,425 as of December 31, 2008) at a cost of euro 414 million (euro 505 million for the year-ended December 31, 2008) were available for 2002-2005 and 2006-2008 stock option plans.
The decrease of 4,075,095 shares consisted of the following:

Stock option

Number of shares at December 31, 2008	23,557,425
Rights exercised	(2,000	)
Rights cancelled	(4,073,095	)
	(4,075,095	)
Number of shares at December 31, 2009	19,482,330

As of December 31, 2009, options outstanding were 19,482,330 shares. Options refer to the 2002 stock plan for 97,000 shares with an exercise price of euro 15.216 per share, to the 2003 stock plan for 229,900 shares with an exercise price of euro 13.743 per share, to the 2004 stock plan for 671,600 shares with an exercise price of euro 16.576 per share, to the 2005 stock plan for 3,281,500 shares with an exercise price of euro 22.512 per share, to the 2006 stock plan for 3,018,155 shares with an weighted average exercise price of euro 23.119 per share, to the 2007 stock plan for 5,144,050 with an weighted average exercise price of euro 27.451 per share and to the 2008 stock plan for 7,040,125 with an exercise price of euro 22.540 per share.
Information about commitments related to stock grant and stock option plans is included in Note 30 – Operating expenses.

Interim dividend
Interim dividend for the year ended December 31, 2009 amounted of euro 1,811 million corresponding to euro 0.50 per share, as decided by the Board of Directors on September 10, 2009 in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 24, 2009.

Distributable reserves
As of December 31, 2009 Eni shareholders’ equity included distributable reserves in the amount of euro 41,100 million.

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Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity

Net profit Shareholders’ equity

(euro million) 2008 2009 Dec. 31, 2008 Dec. 31, 2009

As recorded in Eni SpA’s Financial Statements	6,745		5,061		30,049		32,144
Difference between the equity value of individual accounts of consolidated subsidiaries with respect to the corresponding carrying amount in the statutory accounts of the parent company	4,140		158		18,999		17,464
Consolidation adjustments:
- difference between cost and underlying value of equity	(330	)	(213	)	5,161		5,068
- elimination of tax adjustments and compliance with accounting policies	(1,373	)	(113	)	(2,852	)	(1,062	)
- elimination of unrealized intercompany profits	216		117		(3,127	)	(4,582	)
- deferred taxation	159		378		(15	)	1,175
- other adjustments	1		(71	)	295		(156	)
	9,558		5,317		48,510		50,051
Minority interest	(733	)	(950	)	(4,074	)	(3,978	)
As recorded in Consolidated Financial Statements	8,825		4,367		44,436		46,073

27 Other information
On February 4, 2010 Eni formally presented to the Directorate General for Competition of the European Commission a set of structural remedies for the conclusion of a legal proceeding related to some international gas pipelines.
The legal proceeding concerns the Statement of Objections that Eni received from the European Commission on March 9, 2009 which, under Article No. 82 of the EC Treaty and Article No. 54 of the SEE agreement, alleged that during the period 2000-2005, Eni was responsible for limiting the access of third parties to the gas pipelines TAG, TENP and Transitgas.
With prior agreement from its partners, Eni has committed to dispose of its interests in both the German Tenp gas pipeline and in Switzerland’s Transitgas pipeline which both transport gas from the sites in the North of Europe.
Given the strategic importance of the Austrian Tag pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake into an entity controlled by the Italian State. The remedies negotiated with the Commission do not affect Eni’s contractual gas transport rights.
The European Commission accepted commitments proposed by Eni and will implement a market test before adopting a decision under Article 9 of Regulation (EC) No. 1/2003.
Assets in hand refer to investments in Trans Austria Gasleitung GmbH (TAG), Trans Europa Naturgas Pipeline GmbH & Co KG (TENP) and Transitgas AG as well as assets and liabilities mainly referring to the marketing of the transportation capacity of the consolidated companies Eni Gas Transport Deutschland SpA and Eni Gas Transport International SA.
Considering the amounts as of December 31, 2009, the foreseen disposals concerns the investments accounted for using the equity method in the amount of euro 210 million, current assets in the amount of euro 258 million, liabilities in the amount of euro 98 million of which euro 8 million are non-current, and Group’s equity for a total amount of euro 160 million.

Main acquisitions
Distrigas NV
On October 30, 2008, following the acquisition of a 57.243% majority stake from the French company Suez-Tractebel, Eni acquired control over the Belgian company Distrigas NV. On March 19, 2009, Eni finalized the mandatory tender offer on the minorities of Distrigas. Shareholders, including Publigaz with its entire interest (31.25%), tendered shares representing 41.617% of the share capital of Distrigas. On May 4, 2009, the residual 1.14% of the share capital has been acquired by Eni through a squeeze-out procedure. At December 31, 2009 Eni owns 100% of share capital of Distrigas NV with the exception of a share with special rights owned by the Belgian State.
Consideration for the acquisition of control amounted to euro 2,751 million, which million includes euro 12 million related to additional costs directly attributable to the acquisition. The allocation of the cost, not including the minority interest, to assets and liabilities was made on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

Eni Hewett Ltd
On November 28, 2008, following the finalization of an agreement with the British company Tullow Oil Ltd Eni acquired a 52% stake and the operatorship of fields in the Hewett Unit and relevant facilities in the North Sea, with the aim to upgrade certain depleted

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fields in the area so as to achieve a gas storage facility. Total consideration for this transaction amounted to euro 224 million which was allocated to assets and liabilities on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

First Calgary Petroleums Ltd
On November 21, 2008, following the acquisition of all of the common shares Eni gained control of First Calgary Petroleums Ltd, a Canadian oil and gas company with exploration and development activities in Algeria. Total consideration for this transaction amounted to euro 605 million, of which euro 5 million related to additional costs directly attributable to the acquisition. The allocation of the cost to assets and liabilities was made on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

Hindustan Oil Exploration Co Ltd (HOEC)
On August 5, 2008, following the execution of a mandatory tender offer on a 20% stake of the HOEC share capital, Eni acquired control over the Indian company Hindustan Oil Exploration Co Ltd (HOEC). The mandatory tender offer was associated with Eni’s acquisition of 27.18% of HOEC as part of the Burren deal. Total consideration for this transaction in the amount of euro 107 million, not including the minority interest, has been allocated to assets and liabilities on a preliminary basis as of December 31, 2008, and on a definitive basis as of December 31, 2009.

The definitive allocation of the costs of the business combinations made during the year ended December 31, 2008 year consisted of the following:

(euro million) Distrigas NV ^(a) Eni Hewett Ltd First Calgary Petroleums Ltd Hindustan Oil Exploration Co Ltd

Preliminaryallocation atDec. 31,
2008 Definitiveallocation Preliminaryallocation atDec. 31,
2008 Definitiveallocation Preliminaryallocation atDec. 31,
2008 Definitiveallocation Preliminaryallocation atDec. 31,
2008 Definitiveallocation

Current assets	3,375	3,375	19	20	148	148	115	115
Property, plant and equipment	30	30	118	118	757	855	199	201
Intangible assets	1,395	1,390	208	217
Goodwill	1,245	1,248	39	37	88	65
Investments	112	112					1	1
Other non-current assets	203	203
Assets acquired	6,360	6,358	384	392	993	1,068	315	317
Current liabilities	1,796	1,796	17	22	45	82	37	37
Deferred tax liabilities	504	502	91	94	108	147	31	33
Provisions for contingencies	80	80	52	52	6	5	3	3
Other non-current liabilities	88	88			229	229	17	17
Liabilities acquired	2,468	2,466	160	168	388	463	88	90
Minority interest	1,141	1,141					120	120
Eni's shareholders equity	2,751	2,751	224	224	605	605	107	107

(a) It does not include the share of goodwill attributable to minorities whose equity interest has been acquired during 2009.

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28 Guarantees, commitments and risks

Guarantees
Guarantees were as follows:

Dec. 31, 2008 Dec. 31, 2009

(euro million) Unsecured guarantees Other
guarantees Total Unsecured guarantees Other
guarantees Total

Consolidated subsidiaries		13,139	13,139		9,863	9,863
Unconsolidated entities controlled by Eni		151	151		146	146
Joint ventures and associates	6,027	1,075	7,102	6,060	1,251	7,311
Others	8	245	253	5	266	271
	6,035	14,610	20,645	6,065	11,526	17,591

Other guarantees issued on behalf of consolidated subsidiaries in the amount of euro 9,863 million (euro 13,139 million as of December 31, 2008) primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds in the amount of euro 6,091 million (euro 7,004 million as of December 31, 2008), of which euro 4,936 million related to the Engineering & Construction segment (euro 5,965 million as of December 31, 2008); (ii) VAT recoverable from tax authorities in the amount of euro 1,171 million (euro 1,248 million as of December 31, 2008); (iii) insurance risk in the amount of euro 253 million reinsured by Eni (euro 257 million as of December 31, 2008). During 2009, guarantees for euro 2,739 million expired. Such guarantees were issued on behalf of Eni Gas & Power Belgium SA following the Share Purchase Agreement with Suez-Tractebel SA for the acquisition of a 57.24% majority stake in Distrigas NV. As of December 31, 2009 the underlying commitment covered by such guarantees was euro 9,783 million (euro 10,202 million as of December 31, 2008).
Other guarantees issued on behalf of unconsolidated subsidiaries in the amount of euro 146 million (euro 151 million as of December 31, 2008) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds in the amount of euro 141 million (euro 146 million as of December 31, 2008). As of December 31, 2009, the underlying commitment covered by such guarantees was euro 64 million (euro 79 million as of December 31, 2008).
Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates in the amount of euro 7,311 million (euro 7,102 million as of December 31, 2008) primarily consisted of: (i) an unsecured guarantee in the amount of euro 6,037 million (euro 6,001 million as of December 31, 2008) given by Eni SpA to Treno Alta Velocità - TAV SpA for the proper and timely completion of a project relating to the Milan-Bologna train link by CEPAV (Consorzio Eni per l’Alta Velocità) Uno; consortium members, excluding unconsolidated entities controlled by Eni, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) unsecured guarantees, letters of patronage and other guarantees given to banks in relation to loans and lines of credit received in the amount of euro 971 million (euro 871 million as of December 31, 2008), of which euro 692 million related to a contract released by Eni SpA on behalf of Blue Stream Pipeline Co BV (Eni 50%) to a consortium of international financial institutions (euro 716 million as of December 31, 2008); (iii) unsecured guarantees and other guarantees given to commissioning entities relating to bid bonds and performance bonds in the amount of euro 126 million (euro 107 million as of December 31, 2008). As of December 31, 2009, the underlying commitment covered by such guarantees was euro 814 million (euro 983 million as of December 31, 2008).
Unsecured and other guarantees given on behalf of third parties in the amount of euro 271 million (euro 253 million as of December 31, 2008) consisted primarily of: (i) guarantees issued on behalf of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%) as security against payment commitments for fees in connection with the re-gasification activity. The expected commitment has been valued at euro 206 million (euro 223 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (ii) guarantees issued by Eni SpA to banks and other financial institutions in relation to loans and lines of credit in the amount of euro 23 million on behalf of minor investments or companies sold (euro 19 million as of December 31, 2008).
As of December 31, 2009 the underlying commitment covered by such guarantees was euro 266 million (euro 232 million as of December 31, 2008).

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Commitments and contingencies
Commitments and contingencies were as follows:

(euro million) Dec. 31, 2008 Dec. 31, 2009

Commitments	13,382	16,668
Risks	1,660	1,277
	15,042	17,945

Other commitments in the amount euro 16,668 million (euro 13,382 million as of December 31, 2008) mainly related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities that was quantified on the basis of the capital expenditures expected to be incurred which is euro 10,302 million (euro 10,585 million as of December 31, 2008); (ii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Angola LNG Supply Service for the acquisition of regasified gas at the Pascagoula plant (USA) that will come into force when the regasification service starts during the period between 2011-2032. The expected commitment has been valued at euro 3,941 million and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (iii) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Gulf LNG Energy for the acquisition of regasification capacity of Pascagoula’s terminal (6 bcm/y) over a twenty-year period (2011-2031). The expected commitment has been valued at euro 1,151 million (euro 1,247 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (iv) a commitment entered into by Eni USA Gas Marketing Llc on behalf of Cameron Llc for the acquisition of regasification capacity at the Cameron plant (USA) (5.7 bcm/y) over a twenty-year period (until 2029). The expected commitment has been valued at euro 990 million (euro 1,222 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (v) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest euro 150 million in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oil fields in Val d’Agri (euro 180 million as of December 31, 2008). The commitment is included in the off-balance sheet commitments in the following paragraph "Liquidity risk"; (vi) a commitment entered into by Eni USA Gas Marketing Llc for the contract of gas transportation from the Cameron plant (USA) to the American network. The expected commitment has been valued at euro 110 million (euro 123 million as of December 31, 2008) and it is included in the off-balance sheet commitments in the following paragraph "Liquidity risk".
Risks in the amount of euro 1,277 million (euro 1,660 million as of December 31, 2008) primarily relate to potential risks associated with the value of assets of third parties under the custody of Eni in the amount of euro 899 million (euro 1,273 million as of December 31, 2008) and contractual assurances given to acquirers of certain investments and businesses of Eni in the amount of euro 378 million (euro 387 million as of December 31, 2008).

Non-quantifiable commitments
Under the convention signed on October 15, 1991 by Treno Alta Velocità - TAV SpA and CEPAV (Consorzio Eni per l’Alta Velocità) Due, Eni committed to guarantee the execution of design and construction of the works assigned to the CEPAV Consortium (to which it is party) and guaranteed to TAV the correct and timely execution of all obligations indicated in the convention in a subsequent integration deed and in any further addendum or change or integration to the same. The regulation of CEPAV Consortium contains the same obligations and guarantees contained in the CEPAV Uno Agreement.
Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain of Eni’s assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.

Risk factors
Foreword
The main risks that the Company is facing and actively monitoring and managing are the following: (i) market risk derived from exposure to fluctuations in interest rates, foreign currency exchange rates and commodity prices; (ii) credit risk derived from the possible default of a counterparty; (iii) liquidity risk derived from the risk that suitable sources of funding for the Group’s operations may not be available; (iv) country risk in the upstream business; (v) operational risk; (vi) the possible evolution of the Italian gas market; (vii) the specific risks derived from exploration and production activities.
Financial risks are managed in respect of guidelines defined by the parent company, targeting to align and coordinate Group companies policies on financial risks.

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Market risk
Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of conducting finance, treasury and risk management operations based on separate entities: the parent company’s (Eni SpA) finance department, Eni Coordination Center and Banque Eni which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk and Eni Trading & Shipping that has the mandate to manage and solely monitor commodity derivative contracts. In particular, Eni SpA and Eni Coordination Center manage subsidiaries’ financing requirements inside and outside of Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative financial contracts are managed by the parent company as well as the activity of trading certificates according to the European Union Emission Trading Scheme. The commodity risk is managed by each business unit with Eni Trading & Shipping ensuring the negotiation of hedging derivatives. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to changes in exchange rates and interest rates and to manage exposure to commodity prices fluctuations. Eni does not enter into derivative transactions on a speculative basis. The framework defined by Eni’s policies and guidelines prescribes that measurement and control of market risk be performed on the basis of maximum tolerable levels of risk exposure defined in accordance with value-at-risk techniques. These techniques make a statistical assessment of the market risk on the Group’s activity, i.e., potential gain or loss in fair values, due to changes in market conditions taking into account the correlation that exists among changes in fair value of existing instruments. Eni’s finance departments define maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates, pooling Group companies risk positions. Eni’s calculation and measurement techniques for interest rate and foreign currency exchange rate risks are in accordance with established banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the company. Eni’s guidelines prescribe that Eni’s Group companies minimize such market risks. With regard to the commodity risk, Eni’s policies and guidelines define rules to manage this risk aiming at the optimization of core activities and the pursuit of preset targets of industrial margins. The maximum tolerable level of risk exposure is pre-defined in terms of value-at-risk in connection with trading and commercial activities, while the strategic risk exposure to commodity prices fluctuations – i.e. the impact on the Group’s business results deriving from changes in commodity prices – is monitored in terms of value-at-risk, albeit not hedged in a systematic way. Accordingly, Eni evaluates the opportunity to mitigate its commodity risk exposure by entering into hedging transactions in view of certain acquisition deals of oil and gas reserves as part of the Group’s strategy to achieve its growth targets or ordinary asset portfolio management. The Group controls commodity risk with a maximum value-at-risk limit awarded to each business unit. Hedging needs from business units are pooled by Eni Trading & Shipping which also manages its own risk exposure. The three different market risks, whose management and control have been summarized above, are described below.

Exchange rate risk

Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly in the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro (translation risk). Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize economic and transactional exposures arising from foreign currency movements. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance departments which match opposite positions within Group companies, hedging the Group’s net exposure through the use of certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value on the basis of market prices provided by specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. The VAR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period.

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Interest rate risk
Changes in interest rates affect the market value of financial assets and liabilities of the company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. Borrowing requirements of the Group’s companies are pooled by the Group’s central finance department in order to manage net positions and the funding of portfolio developments consistently with management’s plans while maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to effectively manage the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be accounted for under the hedge accounting method in accordance with IAS 39. Value at risk deriving from interest rate exposure is measured daily on the basis of a variance/covariance model, with a 99% confidence level and a 20-day holding period.

Commodity risk
Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil and gas prices generally has a negative impact on Eni’s results of operations and vice-versa. Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable margins. In order to accomplish this, Eni uses derivatives traded on the organized markets of ICE and NYMEX (futures) and derivatives traded over the counter (swaps, forward, contracts for differences and options) with the underlying commodities being crude oil, refined products or electricity. Such derivatives are evaluated at fair value on the basis of market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable evaluation techniques. Changes in fair value of those derivatives are normally recognized through the profit and loss account as they do not meet the formal criteria to be recognized as hedges in accordance with IAS 39. Value-at-risk derived from commodity exposure is measured daily on the basis of a historical simulation technique, with a 95% confidence level and a one-day holding period. The following table shows amounts in terms of value-at-risk, recorded in 2009 (compared with 2008) relating to interest rate and exchange rate risks in the first section, and commodity risk in the second section. VAR values are stated in U.S. dollars, the currency used in oil products markets.

(Interest and exchange rate risk - Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)

2008 2009

(euro million) High Low Avg At year end High Low Avg At year end

Interest rate	12.31	0.73	4.17	6.54	6.85	1.65	3.35	1.98
Exchange rate	1.48	0.09	0.48	0.47	1.22	0.07	0.35	0.31

(Commodity risk: Value at risk - - Historic simulation method; holding period: 1 day; confidence level: 95%)

2008 2009

($ million) High Low Avg At year end High Low Avg At year end

Area oil, products	46.48	3.44	19.88	5.43	37.51	4.74	17.65	6.64
Area Gas & Power (*)	67.04	24.38	43.53	32.07	51.62	28.01	40.97	38.26

(*) Amounts relating to the Gas & Power business also include results of Distrigas NV starting from the date of acquisition.

Credit risk
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages credit risk differently depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units 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. The monitoring activity of credit risk exposure is performed at the Group level according to set guidelines and measurement techniques that establish counterparty limits and systems to monitor exposure against limits and report regularly on those exposures. Specifically, credit risk exposure to multi-business clients and exposures higher than the limit set at euro 4 million are closely monitored. Monitoring activities do not include retail clients and public administrations. The assessment methodology assigns a score to individual clients based on publicly available financial data and capital, profitability and liquidity ratios. Based on those scores, an internal credit rating is assigned to each counterparty and accordingly allocated to its proper risk category. The Group risk categories are comparable to those prepared by the main rating agencies on the marketplace. The Group’s internal ratings are also benchmarked against ratings prepared by a specialized external source.

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With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance departments, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions. Those are the sole Group entities entitled to be party to financial transactions due to 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. Eni has not experienced material non-performance by any counterparty. As of December 31, 2009, Eni did not have significant concentration of credit risk.

Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the market place as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group’s capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long term debt to total debt as well as fixed rate medium and long term debt to total medium and long term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks. The actions implemented as part of Eni’s financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. In particular in 2009, Eni issued bonds addressed to institutional investor and to the retail market in the amount of euro 3 billion and euro 2 billion, respectively. The above mentioned actions aimed at ensuring availability of suitable sources of funding to fulfill short term commitments and obligations due while preserving the necessary financial flexibility to support the Group’s development plans. In doing so, the Group has pursued an efficient balance of finance debt in terms of maturity and composition leveraging on the structure of its lines of credit particularly the committed ones. 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.
As of December 31, 2009, Eni maintained short term committed and uncommitted unused borrowing facilities in the amount of euro 11,774 million, of which euro 2,241 million were committed, and long term committed unused borrowing facilities in the amount of euro 2,850 million. These facilities were under interest rates that reflected market conditions. Fees charged for unused facilities were not significant.
Eni has a program in place for the issuance of Euro Medium Term Notes up to euro 15 billion, of which euro 9,211 million were drawn as of December 31, 2009.
The Group has debt ratings of AA- and A-1+ for long (outlook negative) and short-term debt, respectively, which has been assigned by Standard & Poor’s and Aa2 (outlook negative) and P-1 assigned by Moody’s for long and short-term debt, respectively.
The tables below summarize the maturities of the Group’s main contractual obligations for finance debt repayments, including expected payments for interest charges, and trade and other payables.

Finance debt

Maturity year

(euro million) 2010 2011 2012 2013 2014 2015 and thereafter Total

Non current debt	3,191	1,342	3,660	1,967	2,487	8,608	21,255
Current financial liabilities	3,545						3,545
Fair value of derivative instruments	1,371	517	133	46	14	98	2,179
	8,107	1,859	3,793	2,013	2,501	8,706	26,979
Interest on finance debt	654	570	545	510	426	1,159	3,864
Guarantees to banks	377						377

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Trade and other payables

Maturity year

(euro million) 2010 2011-2014 2015 and thereafter Total

Trade payables	10,078			10,078
Advances, other payables	9,096	31	23	9,150
	19,174	31	23	19,228

In addition to finance debt and trade payables presented in the financial statements, the Group has in place a number of contractual obligations arising in the normal course of business. To meet these commitments, the Group will have to make payments to third parties. The Company’s main obligations are certain arrangements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay clauses whereby the Company’s obligations consist of off-taking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company���s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities.
The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis.

Expected payments by period under contractual obligations and commercial commitments

Maturity year

(euro million) 2010 2011 2012 2013 2014 2015 and thereafter Total

Operating lease obligations (1)	886	889	561	470	415	1,034	4,255
Decommissioning liabilities (2)	79	55	112	161	1,640	9,280	11,327
Environmental liabilities	293	259	257	214	193	687	1,903
Purchase obligations (3)	14,845	14,151	13,923	14,634	14,651	175,888	248,092
Gas
- Natural gas to be purchased in connection with take-or-pay contracts	13,986	13,365	13,123	13,827	13,838	169,268	237,407
- Natural gas to be transported in connection with ship-or-pay contracts	546	538	545	559	567	3,658	6,413
Other take-or-pay and ship-or-pay obligations	162	154	139	133	131	1,068	1,787
Other purchase obligations (4)	151	94	116	115	115	1,894	2,485
Other obligations	21	4	3	3	3	152	186
of which:
- Memorandum of intent relating Val d’Agri	21	4	3	3	3	152	186
	16,124	15,358	14,856	15,482	16,902	187,041	265,763

(1)	Operating leases primarily regarded assets for drilling activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2)	Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(3)	Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
(4)	Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the U.S.

Over the next four-year period, Eni plans to invest euro 52.8 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects at December 31, 2009. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval and for which, usually, procurements have yet been arranged or set. Such costs are included in the amounts shown.

Capital expenditure commitments

Maturity year

(euro million) 2010 2011 2012 2013 2014 and thereafter Total

Committed on major projects	4,119	3,793	2,829	1,928	11,357	24,026
Other committed projects	9,330	5,284	3,467	3,640	7,489	29,210
	13,449	9,077	6,296	5,568	18,846	53,236

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Country risk
Substantial portions of Eni’s hydrocarbons reserves are located in countries outside the EU and North America, certain of which may be politically or economically less stable than the EU or North America. As of December 31, 2009, approximately 80% of Eni’s proved hydrocarbons reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2009, approximately 60% of Eni’s domestic supply of natural gas came from such countries. Developments in the political framework, economic crisis and social unrest can compromise temporarily or permanently Eni’s ability to operate or to economically operate in such countries, and to have access to oil and gas reserves. Further risks associated with activities in those countries are represented by: (i) lack of well established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws and regulations leading to expropriation of Eni’s titles and mineral assets, changes in unilateral contractual clauses reducing the value of Eni’s assets; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases; (v) civil and social unrest leading to sabotages, acts of violence and incidents. While the occurrence of these events is unpredictable, it is possible that they can have a material adverse impact on Eni’s financial condition and results of operations. Eni periodically monitors political, social and economic risks of approximately 60 countries where it has invested, or, with regard to upstream projects evaluation, where Eni is planning to invest in order to assess returns of single projects based also on the evaluation of each country’s risk profile. Country risk is mitigated in accordance with guidelines on risk management defined in the procedure "Project risk assessment and management". In the most recent years, unfavorable developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America.

Operational riskEni’s business activities conducted in and outside Italy are subject to a broad range of laws and regulations, including specific rules concerning oil and gas activities currently in force in countries in which it operates. In particular, those laws and regulations require the acquisition of a license before exploratory drilling may commence and compliance with health, safety and environment standards. Environmental laws impose restrictions on the types, quantities and concentration of various substances that can be released into the environment and on discharges to surface and subsurface water. In particular Eni is required to follow strict operating practices and standards to protect biodiversity when exploring for, drilling and producing oil and gas in certain ecologically sensitive locations (protected areas). Breach of environmental, health and safety laws exposes employees to criminal and civil liability and in the case of violation of certain rules regarding safety on the workplace also companies can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with Law Decree No. 231/2001.
Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations and expenses and liabilities that Eni may incur in relation to compliance with environmental, health and safety laws and regulations are expected to remain material to the group’s results of operations or financial position in future years. Recently enacted regulations on safety and health in the workplace in Italy (Legislative Decree No. 81/2008 and Legislative Decree No. 106/2009) impose a new array of obligations to the Company’s operations, particularly regarding contractors. New regulations prescribe that a company adopts certified operational and organizational systems whereby the Company can discharge possible liabilities due to a violation of health and security standards on condition that adopted operational systems and processes worked properly and were effective.
Eni has adopted guidelines for assessing and managing health, safety and environmental (HSE) risks, with the objective of protecting Eni’s employees, the populations involved in its activity, contractors and clients, and the environment and being in compliance with local and international rules and regulations. Eni’s guidelines prescribe the adoption of international best practices in setting internal principles, standards and solutions. The ongoing process for identifying, evaluating and managing HSE operations in each phase of the business activity is performed through the adoption of procedures and effective pollution management systems tailored to the peculiarities of each business and industrial site and on steady enhancement of plants and process. Additionally, coding activities and procedures on operating phases allow to reduce the human component in the plant risk management. Operating emergencies that may have an adverse impact on assets, people and the environment are managed by the business units for each site. These units manage the HSE risk in a systematic way that involves having emergency response plans in place with a number of corrective actions to be taken that minimize damage in the event of an incident. In the case of a major crisis, Divisions/Entities are assisted by the Eni Unit of Crisis to deal with the emergency through a team which has the necessary training and skills to coordinate in a timely and efficient manner resources and facilities. The integrated management system of health, safety and environmental matters is supported by the adoption of Eni’s Model of HSE operations in all the Division and companies of the Eni Group. This is a procedure based on an annual cycle of planning, implementation, control, review of results and definition of new objectives. The model is directed towards the prevention of risks, the systematic monitoring and control of HSE performance, in a continuous improvement cycle (Deming cycle).
Eni is reaching the goal of total certification of its plants. Industrial and commercial sites of the R&M segment have been certified as ISO 14001, and six of them are EMAS certified; in the petrochemical segment facilities are certified under ISO 14001, EMAS and OHSAS 18001. EniPower power stations are EMAS certified, while in other segments facilities are mainly certified under ISO 14001 and OHSAS 18001.

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The system for monitoring HSE operational risks is based on the monitoring of HSE indicators at quarterly intervals and on an audit plan addressed to three levels: HSE Corporate, HSE business unit and at site level consisting of:
- - internal audits of management systems (performed by Eni employees or external consultants)
- - audits for the confirmation or renewal of certification of management systems performed annually by external certifying entities;
- - control of compliance with existing HSE regulations;
- - specific audits on relevant issues (e.g. following events/accidents/reported failures).
Eni provides a program of specific training and development to its HSE staff in order to:
- - promote the execution of behaviors consistent with guidelines;
- - drive people’s learning growth process by developing professionalism, management and corporate culture;
- - support management knowledge and control of HSE risks.

Risk factors related to the natural gas market
Risks and uncertainties associated with the current outlook for gas demand and supply in Europe and Italy
In 2009 European gas demand was severely impacted by the economic downturn (down 7.4% from 2008, assuming normal average temperatures). As a result of that trend, both producing activities and request for electricity reduced. The Italian market was particularly hit by the downturn as demand fell by approximately 9 bcm from 2008, down 10%, and almost 10 bcm from the pre-crisis levels seen in 2007, down 12%, assuming normal average temperatures. In the meantime, new gas supplies entered the market as several operators, including Eni, completed plans to upgrade gas import pipelines from gas producing Countries or to build new facilities to import gas to Europe via LNG. Particularly, Eni has finalized plans to upgrade the import capacity of its two main pipelines from Russia and Algeria by 13 bcm/y (the gas pipelines TAG and TTPC), with new capacity entirely sold to third parties. A new LNG terminal with a capacity of 8 bcm/y commenced operations late in 2009, operated by a consortium of competitors. As a result, gas availability on the Italian market increased at a time when demand actually shrunk, resulting in a situation of oversupply. In this context, Eni’s results of the gas marketing business, sales volumes and average gas selling margins were driven down by rising competition and weak demand both in Italy and Europe. Large gas availability on European markets also prevented the Company from disposing of part of its gas availability by selling it on European markets. The outlook for gas supply and demand both in Europe and Italy is challenging as GDP growth in the 27 EU Countries will remain weak over the next few years and gas demand is expected to recover only gradually to precrisis levels. In addition, ongoing patterns towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt their Climate Action and Renewable Energy Package. This legislation was voted by the European Parliament in December 2008. The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020. To factor in those trends, management has revised down its long-term projections of European gas demand growth from a previous compound average growth rate (c.a.g.r.) of 2% till 2020 to a revised 1.5% c.a.g.r. These assumptions imply an overall consumption of approximately 600 bcm by 2020 compared to a previous forecast of 720 bcm. Management also expects the Italian market to grow less than anticipated at an annual rate that will be slightly lower than 2%, implying a level of consumption amounting to 94 bcm versus a previous forecast of 107 bcm at 2020. These demand trends of sluggish growth associated with ample gas availability on the marketplace might adversely affect the Company’s results of operations and cash flow in its gas marketing business over the next few years.

Current negative trends in gas demand and supply may impair the Company’s ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts
In order to secure long-term access to gas availability, particularly in view of supplying the Italian gas market, the Company has signed a number of long-term gas supply contracts with key producing Countries that supply European gas markets. These contracts will ensure approximately 62.4 bcm of gas availability in 2010 (excluding the contribution of other subsidiaries and associates) with a residual life of approximately 20 years, and provide take-or-pay clauses whereby the Company is required to collect minimum predetermined volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of it, of uncollected volumes up to the minimum contractual quantity. The take-or-pay clause entitles the Company to collect pre-paid volumes of gas in later years during the period of contract execution. Amounts of cash prepayments and time schedules for collecting pre-paid gas vary from contract to contract. Generally speaking, cash pre-payments are calculated on the basis of the energy prices current in the year of non-fulfillment with the balance due in the year when the gas is actually collected. Amounts of pre-payments range from 10 to 100 percent of the full price. The right to collect pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, rights to collect

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pre-paid gas in future years can be exercised provided that the Company has fulfilled its minimum take obligation in a given year and within the limit of the maximum annual quantity that can be collected in each contractual year. In this case, Eni will pay the residual price calculating it as the percentage that complements 100, based on the arithmetical average of monthly base prices in place in the year of the off-take. Similar considerations apply to ship-or-pay contractual obligations. Management believes that the current outlook for gas demand and large gas availability on the marketplace, as well as the possible evolution of sector-specific regulation, represent risks factors to the Company’s ability to fulfill its minimum take obligations associated with its long-term supply contracts. Under current contractual terms, in 2009 Eni collected lower volumes than its minimum take and recognized a trade payables corresponding to the amount of gas that the Company was contractually required to collect. Management believes that over the next three years the Company will experience failure to fulfill its take-or-pay obligations associated with significant volumes of gas, unless demand fundamentals improve substantially and a better balance between demand and supply is achieved on the marketplace. Currently, the Company is unable to forecast the timing of such a recovery. In addition, there also exist both a pricing risk as a portion of the gas purchase price is based on the prices of the energy parameters recorded in the year of non-fulfillment, and a volume risk in case the Company is actually unable to dispose of pre-paid volumes. In this context, the Company’s selling margins, results of operations and cash flow may be negatively affected. Based on management’s projections for sales volumes and prices for the four-year plan and subsequent years, volumes for which an obligation to pay cash advances might arise due to take or pay clauses will be off-taken within contractual terms, thus recovering cash advances. Even if financing associated with cash advances is factored in, the net present value associated with those long-term contracts discounted at the weighted average cost of capital for the Gas & Power segment still remains a positive and consequently those contracts do not fall within the category of the onerous contract provided by IAS 37. In the medium term Eni intends to preserve the profitability and cash flow generation of its gas marketing operations. A number of initiatives have been identified, including:
- - maximization of gas sales volumes leveraging on the multiple presence in a number of markets; market knowledge, the integration with Distrigas commercial operations and supply portfolio (which is not expected to have take-or-pay obligations in future years) and marketing policies aimed at increasing Eni’s market share in Europe;
- - renegotiations of the main long-term supply contracts through the exercise of the contractual right to amend terms and conditions of the contracts as provided by specific contractual clauses in case of significant changes in the market environment, as those that have been occurring from the second half of 2008. These renegotiations were finalized early in 2010 with a positive impact both on 2009 results and on future commercial plans giving Eni more flexibility in its marketing operations;
- - launching of innovative pricing formulas and improving the quality of services on the core Italian market;
- - reduction in the cost-to-serve;
- - monitoring and controlling working capital requirements.

Risks associated with sector-specific regulations in Italy
Legislative Decree No. 164/2000 opened the Italian natural gas market to competition, impacting on Eni’s activities, as the company is engaged in all the phases of the natural gas chain. The opening to competition was achieved through the enactment of certain antitrust thresholds on volumes input into the national transport network and on volumes sold to final customers. These enabled new competitors to enter the Italian gas market, resulting in declining selling margins on gas. Other material aspects regarding the Italian gas sector regulations are the regulated access to natural gas infrastructure (transport backbones, storage fields, distribution networks and LNG terminals), the provision that activities relating to infrastructures are mandatory charged to separate companies; the Code adopted by the Authority for Electricity and Gas on the issue of unbundling which forbids a controlling entity from interfering in the decision-making process of its subsidiaries running gas transport and distribution and other infrastructures and the circumstance that the Authority for Electricity and Gas is entrusted with certain powers in the matters of natural gas pricing and in establishing tariffs for the use of natural gas infrastructures. Specifically, the Authority for Electricity and Gas holds a general surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users consuming less than 200,000 cm/y (qualified as non eligible customers as of December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account the public goal of containing the inflationary pressure due to rising energy costs. Accordingly, decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the cost of fuels onto final consumers of natural gas. Following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority finally established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 cm/y, establishing, among other things that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account a new indexation mechanism of the raw material cost component. This indexation mechanism has been recently updated based on Resolution No. 64/2009 of the Authority, which provides that changes in a preset basket of hydrocarbons are

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transferred to the cost of the supply to those customers. Also a floor has been established in the form of a fixed amount that applies only at certain low level of international prices of hydrocarbons. Also certain provisions of law may limit the Company’s ability to set commercial margins. Specifically, Law Decree No. 112 enacted in June 2008 forbids energy companies like Eni to pass to prices to final customers the higher income taxes incurred in connection with a supplemental tax rate of 6.5 percentage points introduced by the same decree on energy companies with a yearly turnover in excess of euro 25 million. The Authority for Electricity and Gas is in charge of monitoring compliance with this rule. The Authority has subsequently established with a set of deliberations that energy companies have to adopt effective operational and monitoring systems in order to prevent unlawful increases in final prices of gas. Other risk factors and uncertainties deriving from the regulatory framework are associated with the regulation of the access to the Italian gas transport network that is currently set by Decision No. 137/2002 of the Authority for Electricity and Gas. The decision is fully incorporated into the network code presently in force as prepared by the system’s operator. The decision sets priority criteria for transport capacity entitlements at points where the Italian transport network connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, operators that are holders of take-or-pay contracts, as in the case of Eni, are entitled to a priority in allocating available transport capacity within the limit of average daily contractual volumes. Gas volumes exceeding average daily contractual volumes are not entitled to any priority and, in case of congestion at any entry points, they are entitled available capacity on a proportionate basis together with all pending requests for capacity assignments. The ability of Eni to collect gas volumes exceeding average daily volumes as provided by its take-or-pay supply contracts represents an important operational flexibility that the Company uses to satisfy demand peaks. In planning its commercial flows, the Company normally assumes to make full use of its contractual flexibility and to obtain the necessary capacity entitlements at the entry points to the national transport network. Those assumptions may be inconsistent with rules set by Decision No. 137/2002 specifically with regard to priority criteria governing capacity entitlements. Eni considers Decision No. 137/2002 to be illegitimate as it is supposedly in contrast with the rationale of the European regulatory framework on the gas market as provided in European Directive 55/2003/CE.
Based on that belief the Company has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court which recently confirmed in part Eni’s position. An upper grade court also confirmed the Company’s position. Specifically, the Court stated that the purchase of contractual flexibility is an obligation on part of the importer, which responds to a collective interest. According to the Court, there is no reasonable motivation whereby volumes corresponding to such contractual flexibility should not be granted priority in the access to the network, also in case congestion occurs. At the moment, however, no case of congestion occurred at entry points to the Italian transport infrastructure such to impair Eni’s marketing plans. Further uncertainty factors related to the regulatory framework are the so called gas release measures that are intended to increase flexibility and liquidity in the gas market. This measure strongly affected Eni’s marketing activity in Italy. In 2004, based on certain agreements with the Antitrust Authority, Eni released in a four-year period a total amount of 9.2 bcm (2.3 bcm per year between October 1, 2004 and September 30, 2008) and the related transport capacity. In addition, in 2007 Eni agreed to adhere to a new gas release program involving 4 bcm which were disposed of at the virtual exchange point (PSV) in a two-year period (from October 1, 2007 and September 30, 2009) For thermal year 2009-2010 Italian Law No. 99/2009 introduced a new obligation for Eni to make additional sales at the virtual exchange point for a total of 5 bcm of gas in yearly and half-yearly amounts. Although the allotment procedure (bid) was based on a minimum price set by the Ministry for Economic Development as proposed by the Authority (Eni considering this point discriminatory, filed a claim to the competent authority), only a 1.1 bcm portion of the gas release was awarded out of the 5 bcm which had been planned. For the next few years, based on indications of the Authority (in a report to the Parliament on the situation of the gas and electricity market in Italy as provided in Resolution PAS 3/2010), Eni cannot exclude the possibility that new gas release programs will be imposed on it.

Specific risks associated with exploration and production of oil and natural gas
Exploration and production of oil and natural gas requires high levels of capital expenditure and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or natural gas fields. Exploratory activity involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. Developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return of such long lead-time projects are exposed to the volatility of oil and gas prices and the risk of an increase in developing and lifting costs, resulting in lower rates of return. This set of circumstances is particularly important to those projects intended to develop reserves located in deep water and harsh environments, where the majority of Eni’s planned and ongoing projects are located.

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Risks associated with the cyclicality of the oil and gas sector
The global economic downturn and the associated reduction in industrial output recorded in 2008 and for most of 2009 triggered a sharp decline in worldwide demand for energy, resulting in significantly lower commodity prices.
In spite of weak fundamentals (level of global demand and level of inventories), international oil prices have shown a steady upward trend since the second half of 2009 driven by expectations for a global economic recovery and OPEC production cuts, settling by year end in a range of 70-80 $/bbl.
Volatile oil prices pose a critical issue to the sustainability of capital plans of oil and gas companies, considering that they are engaged in long lead-time projects. Such projects normally require lengthy and complex activities for assessing all technical and commercial aspects and developing and marketing hydrocarbons. As a consequence, return rates of projects are exposed to the volatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was made, resulting in lower rates of return. The Company, likewise other players in the industry, assesses its oil and gas projects based on long-term scenarios for oil prices, which reflect management’s best assumptions about the underlying fundamentals of global demand and offer. The adoption of long-term prices in assessing capital projects support the achievement of the planned rates of return.
Eni plans to invest euro 52.8 billion in the four-year period from 2010 through 2013, at the Company’s long-term price for Brent crude of 65 $/bbl (in real terms 2013). Of this, euro 37.7 billion, or 71%, will be dedicated to execute projects for exploring and developing oil and gas reserves. The plan shows an increase of 8% from the previous plan that was approved when the trading environment was particularly depressed. The main drivers which explain the increase are: (i) planned expenditures for developing new upstream projects, particularly those associated with reserves development in Iraq, Venezuela and certain fields offshore Angola; (ii) the circumstance that the Company is forecasting steady trends in costs for materials and sector specific services which have fallen far less than what management has anticipated due to the fast recovery in international oil prices, and the impact of the decision on part of most oil companies to maintain their spending patterns substantially unchanged. In the previous plan, management assumed a decline in those costs. These increasing trends will be partially offset by the impact of the US dollar depreciation versus the euro.
Volatile oil prices also influence the reserve replacement ratio. Changes in oil prices normally trigger two opposite impacts in proved reserves revisions. On one side, a larger or smaller amount of reserves is booked in connection with production sharing agreements and similar contractual schemes. Under such contracts, the Company is entitled to receive a portion of the production, the sale of which should cover expenditures incurred and earn the Company a share of profit. Accordingly, the higher the reference prices for crude oil used to determine production and reserves entitlements, the lower the number of barrels to cover the same dollar amounts hence the amounts of booked reserves; and vice versa. On the other side, downward revisions of reserves occur for those marginal amounts of reserves that are no longer economically producible based on oil prices that are significantly lower than those at which they were originally assessed and sanctioned; and the opposite occurs in case of higher oil prices.
In the Gas & Power segment, Eni’s outlook for the year 2010 factors in a modest improvement in Italian and European gas demand, recovering from the sharp decline suffered in 2009.
Eni also expects that the gas market will be well supplied as new import capacity to Europe and Italy is available in light of recent facility start-ups and upgrades of the main import pipelines made by Eni and other operators. Those trends, together with the recently enacted gas release programs in Italy, represent risk factors to the Company’s ability to maintain its margins in the marketing business also taking into account the take or pay clauses of certain long-term supply contracts which require the Company to collect minimum predetermined volumes of gas or, in case of failure, to pay the price, or a portion of it, for uncollected volumes. Under take or pay clauses the Company is entitled to collect pre-paid volumes of gas in future years, assuming a stronger recovery in gas demand.
For more information see the specific risk paragraph in the "Operating Review" of the Gas & Power section in this annual report.
The Refining & Marketing and the Petrochemical segments are particularly exposed to the volatility of the economic cycle, as their respective industries continue to be plagued by excess capacity, intense competitive pressure, low entry barriers and commoditized products. These industries are also exposed to movements in oil prices and the speed at which the prices of refined products and petrochemicals products adjust to reflect change in the cost of oil-based feedstock. Normally, a time lag occurs between movements in oil prices and those of refined and petrochemical products. As a consequence, in a period of rapidly escalating feedstock costs, margins on refined and petrochemical products are negatively affected.
For 2010, Eni’s management does not expect any appreciable recovery in the main trends that negatively affected the performances of these businesses last year. In 2009 Eni’s realized refining margins were sharply lower mirroring the environment for Brent margins (down 50%), while margins on a mix of light and heavy crude were further lower, down by 60%, both under break-even. A number of negative factors contribute to the reduction. Firstly, significantly compressed light-heavy crude differentials due to a reduction in heavy crude availability on the market place negatively affected the profitability of Eni’s complex refineries. Secondly, the industry continued to be plagued by weak fundamentals due to excess capacity, high inventory levels and stagnant demand affecting end-prices, while feedstock costs have been on an upward trend since the beginning of the

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second half. Finally, middle-distillates prices plunged to historical lows in terms of spread versus the cost of oil. At the moment, management does not expect a reversal in those trends on the short-term.
In its Petrochemical segment, management has been pursuing a number of initiatives designed to reduce fixed operating expenses and to realign the industrial set-up of Eni’s petrochemical operations with a view of enhancing areas of competitive advantage. In spite of all this, the achievement of the operating break-even in this segment depends on a global recovery in the economy that is uncertain at least in the short-term.
The Engineering & Construction segment followed a different trend, maintaining a steady order backlog and economic returns, thanks to a business model articulated across various market sectors combined with a strong competitive position in frontier areas, which are traditionally less exposed to the cyclical nature of this market. The start of operations of new distinctive assets in 2010 and 2011 coupled with the size and quality of the backlog and the strong operating performance on projects, underpin expectations for a further significant strengthening of Saipem’s competitive position in the medium term.

Other information about financial instruments
The carrying amount of financial instruments and relevant economic effect as of and for the years ended December 31, 2008 and 2009 consisted of the following:

2008 2009

Finance income (expense) recognized in: Finance income (expense) recognized in:

(euro million) Carrying amount Profit and loss account Equity Carrying amount Profit and loss account Equity

Held-for-trading financial instruments
Non-hedging derivatives (a)	(374	)	(558	)		(26	)	45
Held-to-maturity financial instruments
Securities (b)	50		2			36		1
Available-for-sale financial instruments
Securities (b)	495		19		3	348		13		1
Receivables and payables and other assets/liabilities valued at amortized cost
Trade and receivables and other (c)	22,446		(254	)		20,348		(361	)
Financing receivables (b)	1,908		117			1,637		72
Trade payables and other (d)	20,570		(53	)		19,174		(48	)
Financing payables (b)	20,837		(607	)		24,800		(552	)
Assets at fair value through profit or loss (fair value option)
Investments (b)	2,741		241					163
Net liabilities for hedging derivatives (e)	280		1,012		964	751		161		(636	)

(a)	In the profit and loss account, incomes were recognized within "Other operating income (loss)" for euro 49 million (expenses for euro 131 million at December 31, 2008) and within "Finance income (expense)" for euro 4 million (expenses for euro 427 million at December 31, 2008).
(b)	Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(c)	In the profit and loss account, essentially impairments were recognized within "Purchase, services and other" for euro 427 million (euro 385 million at December 31, 2008) while positive exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized within "Finance income (expense)" for euro 66 million (euro 131 million at December 31, 2009).
(d)	In the profit and loss account, primarily exchange differences arising from accounts denominated in foreign currency and translated into euro at year-end were recognized within "Finance income (expense)".
(e)	Income or expense were recognized in the profit and loss account within "Net sales from operations" and "Purchase, services and other" for euro 155 million (euro 1,005 million at December 31, 2008) within "Finance income (expense)" for euro 6 million (euro 7 million at December 31, 2008) (time value component).

Fair value of financial instruments
Following the classification of financial assets and liabilities, measured at fair value in the balance sheet, is provided according to the fair value hierarchy defined on the basis of the relevance of the inputs used in the measurement process. In particular, on the basis of the features of the inputs used in making the measurements, the fair value hierarchy shall have the following levels:

(a)	Level 1: quoted prices (unadjusted) in active markets for identical financial assets or liabilities;
(b)	Level 2: measurements based on the basis of inputs, other than quoted prices above, which, for assets and liabilities which have to be measured, can be observable directly (e.g. prices) or indirectly (e.g. deriving from prices);
(c)	Level 3: inputs not based on observable market data.

Financial instruments measured at fair value in the balance sheet as of at December 31, 2009 were classified as follows: (i) level 1, "Other financial assets held for trading or available for sale"; (ii) level 2, derivative instruments included in "Other current assets", "Other non-current assets", "Other current liabilities" and "Other non-current liabilities". During 2009 no transfers were done between the different hierarchy levels of fair value. More information about the amount of financial instruments valued at fair value

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are provided in Note 2 – Other financial assets held for trading or available for sale, Note 7 – Other current assets, Note 14 – Other non-current assets, Note 19 – Other current liabilities and Note 24 – Other non-current liabilities.

Legal Proceedings

Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni believes that the foregoing will not have an adverse effect on Eni’s Consolidated Financial Statements.
The following is a description of the most significant proceedings currently pending. Unless otherwise indicated below, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably.

1. Environment

1.1 Criminal proceedings

ENI SPA
(i) Subsidence. The Court of Rovigo conducted investigations concerning a subsidence phenomenon allegedly caused by hydrocarbon exploration and extraction activities in the Ravenna and North Adriatic area both on land and in the sea. Eni appointed an independent and interdisciplinary scientific commission, composed of prominent and highly qualified international experts of subsidence caused by hydrocarbon exploration and extraction activities, with the aim of verifying the magnitude and effects and any actions appropriate to reduce or to neutralize any subsidence phenomenon in the area. This commission produced a study which excludes the possibility of any risk to human health or damage to the environment. The study also states that worldwide there are no instances of accidents of harm to public safety caused by subsidence induced by hydrocarbon production. It also shows that Eni employs the most advanced techniques for monitoring, measuring and controlling the soil. This proceeding is in the first level hearing stage. The Veneto Region, other local bodies and two private entities have been acting as plaintiffs. Eni was admitted as a defendant. At the end of the renewed preliminary investigations the Court of Ravenna requested the closing of the proceeding. According to press news a number of plaintiffs would file appeals against this decision.
(ii) Alleged damage - Prosecuting body: Public Prosecutor of Gela. In 2002, the public prosecutor of Gela commenced a criminal investigation to ascertain alleged damage caused by emissions of the Gela plant, owned by Polimeri Europa SpA, Syndial SpA (formerly EniChem SpA) and Raffineria di Gela SpA. The judge for the preliminary hearing dismissed the accusation of adulteration of food products, while the proceeding for the other allegations regarding pollution and environmental damage remains underway. The trial ended in acquittal with regard to the general manager and officer pro tempore of the refinery. The sentence of the Gela Tribunal stated that the charges were lacking factual basis. A number of farmers of Gela area, who have been acting as plaintiffs in the first level hearing stage, filed an appeal against the acquittal sentence in the civil action. In the first hearing on December 17, 2009, the public prosecutor asked for the dismissal of the appeal confirming the motivations of the acquittal sentence in the first degree proceeding. The Court of Rome postponed the proceeding to the hearing of February 25, 2010. In February 25, 2010 the Court confirmed the acquittal sentence. The Court would file the grounds of the judgments within the next 60 days.
(iii) Alleged negligent fire in the refinery of Gela. In June 2002, in connection with a fire at the refinery of Gela, a criminal investigation began concerning alleged negligent fire, environmental crimes and crimes against natural beauty. First degree proceedings ended with an acquittal sentence. In November 2007, the public prosecutors of Gela and of Caltanissetta filed an appeal against this decision. In the first hearing the Court re-opened the examining phase, arranging a collegial appraiser. On December 10, 2009 the appraisers appointed by the Court filed their report. On January 21, 2010, the Court of Caltanissetta announced an acquittal sentence for all the defendants.
(iv) Investigation of the quality of ground water in the area of the refinery of Gela. In 2002, the public prosecutor of Gela commenced a criminal investigation concerning the refinery of Gela to ascertain the quality of ground water in the area of the refinery. Eni is charged of having breached environmental rules concerning the pollution of water and soil and of illegal disposal of liquid and solid waste materials. The preliminary hearing phase was closed for one employee who would stand trial, while the preliminary hearing phase is ongoing for other defendants. During the hearings the judge admitted as plaintiffs three environmental associations. The proceeding was subsequently assigned to a different judge and was disposed the renewal of the debate phase. In the said phase were examined indictment and defense witnesses. Subsequently it was examined the first technical appraiser of the defense. The proceeding continues with examination of another technical appraiser of the defense.
(v) Alleged negligent fire (Priolo). The public prosecutor of Siracusa commenced an investigation regarding certain Eni managers who were previously in charge of conducting operations at the Priolo refinery (Eni divested this asset in 2002) to

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ascertain whether they acted with negligence in connection with a fire that occurred at the Priolo plants on April 30 and May 1-2, 2006. After preliminary investigations the public prosecutor requested the opening of a proceeding against the mentioned managers for negligent behavior. The first hearing, in which the parties could present themselves as plaintiffs, was scheduled for February 26, 2010. On February 5, 2010, the Court of Siracusa following the exception of inadmissibility issued by the defendants, admitted as a plaintiff the only Ministry for the Environment excluding all the other counterparts, including the Council of Ministers. The proceeding continues with the examination of three witnesses of the Public Prosecutor.
(vi) Groundwater at the Priolo site - Prosecuting body: Public Prosecutor of Siracusa. The Public Prosecutor of Siracusa (Sicily) has started an investigation in order to ascertain the level of contamination of the groundwater at the Priolo site. The Company has been notified that a number of its executive officers are being investigated who were in charge at the time of the events subject to probe, including chief executive officers and plant general managers of the Company’s subsidiaries AgipPetroli SpA (now merged into the parent company Eni SpA in the Refining & Marketing division), Syndial and Polimeri Europa. Probes on technical issues required by the Prosecutor were finalized on October 15, 2009. On February 25, 2010 the technical survey was filed. According to this report the ground and the groundwater at the Priolo site should be considered polluted according to Law Decree 152/2006. This contamination was caused by a spill-over made in the period prior to 2001 and not subsequent to 2005; the equipments still operating on the site represent another source of risk, in particular the ones owned by another operator. According to the findings of this report the defense of Syndial, Polimeri Europa and Eni SpA (Refining & Marketing division) will file a defensive memorandum to request the dismissal of the proceeding.

SYNDIAL SPA
(vii) Porto Torres - Prosecuting body: Public Prosecutor of Sassari. In March 2009, the Public Prosecutor of Sassari (Sardinia) resolved to commence a criminal trial against a number of executive officers and managing directors of companies engaging in petrochemicals operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial. The charge involves environmental damage and poisoning of water and stuff destined to feeding. In the preliminary hearing on July 17, 2009, the Province of Sassari, the Association Anpana (animal preservation) and the company Fratelli Polese Snc situated in the industrial site have been acting as plaintiffs. None of these parties claimed the identification of the civil responsible and the damage quantification that will be asked in a second step. The legal defense of Syndial requested further time for the recognition of the proceeding plaintiffs and the verification of their right to institute proceedings. The defense of Syndial filled a number of exceptions on the admissibility in acting as plaintiffs of the counterpart; the judge will resolve the question in the hearing which has been scheduled for February 19, 2010. In this hearing the judge, based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, excluded all the counterparts that have been acting as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the fishing talent of the industrial port of Porto Torres; the judge admitted as plaintiffs the Municipality of Sassari, the Environmental Association Anpana and the company Fratelli Polese Snc. The judge also requested that Syndial SpA, Polimeri Europa SpA, Ineos Vinyls and Sasol Italy SpA stand trial. The proceeding continues for the constitution as defendants of the said parts.

1.2 Civil and administrative proceedings

SYNDIAL SPA (FORMER ENICHEM SPA)
(i) Alleged pollution caused by the activity of the Mantova plant. In 1992, the Ministry of Environment summoned EniChem SpA (now Syndial SpA) and Edison SpA before the Court of Brescia. The Ministry requested, primarily, environmental remediation for the alleged pollution caused by the activity of the Mantova plant from 1976 until 1990, and provisionally, in case there was no possibility to remediate, the payment of environmental damages. Edison agreed on a settlement with the Ministry whereby Edison quantified compensation for environmental damage freeing from any obligation Syndial, which purchased the plant in 1989. Negotiations between the parts for the quantification of the environmental damage (relating only to 1990) are underway; the judgment has been postponed a number of times until the next hearing that has been scheduled for January 28, 2010. This hearing has been adjourned again to July 22, 2010 because negotiations between the parties are underway.
(ii) Summon before the Court of Venice for environmental damages allegedly caused to the lagoon of Venice by the Porto Marghera plants. On December 2002, EniChem SpA (now Syndial SpA), jointly with Ambiente SpA (now merged into Syndial SpA) and European Vinyls Corporation Italia SpA (EVC Italia, then Ineos Vinyls SpA, actually Vinyls Italia SpA) was summoned before the Court of Venice by the Province of Venice. The province requested compensation for environmental damages that initially were not quantified, allegedly caused to the lagoon of Venice by the Porto Marghera plants, which were already the

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subject of two previous criminal proceedings against employees and managers of the defendants. EVC Italia and the actual company, Vinyls, presented an action to be indemnified by Eni’s Group companies in case the alleged pollution is proved. The Province of Venice, in the preliminary stage of the proceeding, filed claims amounting to euro 287 million. Syndial submitted its written reply evidencing that the abovementioned damage quantification has been made lacking of probations for the damage and based on evidence that allowed the Court of First and Second Instance to disclaim EniChem of any responsibility through definitive sentence. In the hearing on October 16, 2009, scheduled to review the technical appraisal, the Court declared the interruption of the proceeding because Vinyls Italia had undergone a reorganization procedure. The proceeding is suspended until the eventual action as plaintiff of the Province of Venice.
(iii) Claim of environmental damages, allegedly caused by industrial activities in the area of Crotone - Prosecuting Bodies: the Council of Ministers, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region. The council of Ministers, the Ministry for the Environment, the Delegated Commissioner for Environmental Emergency in the Calabria Region and the Calabria Region requested Syndial to appear before the Court of Milan in order Syndial is condemned to compensate for the environmental damage caused by the operations of Pertusola Sud SpA (merged in EniChem, now Syndial) in the Crotone site. This first degree proceeding was generated in January 2008 by the unification of two different actions, the first brought by Calabria Region in October 2004, the second one by the council of Ministers, the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the Calabria Region commenced in February 2006. The Calabria Region is claiming compensation amounting to euro 129 million for the site environmental remediation and clean-up on the basis of the cost estimation provided in the remediation plan submitted by the Delegated Commissioner, plus additional compensation amounting to a preliminary estimate of euro 800 million relating to environmental damage, estimated increases in the regional health expenditures and damage to the public image to be fairly determined during the civil proceeding. The council of Ministers, the Ministry for the Environment and the Delegated Commissioner is claiming compensation amounting to euro 129 million for the site environmental remediation and clean-up (this request is analogous to that of the Calabria Region) and eventual compensation for other environmental damage to be fairly determined during the civil proceeding. In February 2007 the Ministry for the Environment filed with the Court an independent appraiser’s report issued by APAT that estimated a refundable environmental damage amounting to euro 1,920 million, including the remediation and clean-up expenditures, increased by euro 1,620 million from the original amount of euro 129 million, and an estimation of environmental damage and other damage items amounting approximately to euro 300 million. The amounts estimated by the independent appraiser, added to the claim of the Calabria Region, generate a total of euro 2,720 million of potential compensation. In May and September 2007 Syndial presented its own technical advice that, based on what the Company believes to be well-founded circumstances, vigorously object the independent appraiser’s findings filed by the Ministry for the Environment on site contamination, the responsibility of Syndial in the contamination of the site, the criteria of estimate remediation costs, which according to the Company are erroneous, arbitrary and technically inadequate. On October 7, 2009 an independent appraiser report was filed that reviewed the environmental status of the site and estimated the remediation costs while the estimate of both the health damage caused by the pollution and the environmental damage would be issued in a further independent appraiser report. The findings of the independent appraisers are substantially in line with the issues expressed by Syndial on the measures for the environmental remediation and clean-up, based on a risk analysis aimed to define effective and specific actions. The clean-up project, approved to a great extent by the ministry for the Environment and the Calabria Region, has been considered substantially adequate. The independent appraisers affirmed the necessity of clean-up measures that were not planned by Syndial on one of the external areas (the so-called archaeological area) and considered being unnecessary the dredging of sea sediments. The estimated clean-up costs are in line with the estimate made by Syndial. The independent appraiser report is less favorable to Syndial because it identifies as source of the contamination the production slag management, even recent. The independent appraiser report evaluated that the production technology was a BAT (best available technology), instead the slag treatment could be performed in a more respectful way for the environment and the products (the so-called Cubilot) lacked the physic-chemical characteristic of stability that would avoided the emission of polluting agents in the soil. As regards the quantification of the environmental damage different by the remediation, the independent report APAT provided by the Ministry of Environment quantified the damage for the lack of fruition of the site basing on the remediation costs that were significantly reduced by the independent appraiser report. In case the judge resolves on the responsibility of Syndial in the contamination of the site based on the conclusions of the independent appraiser report, the Company could be liable, for the environmental damage different from the goods fruition (damage to the community, increases in the regional health expenditures), at least in part and as far as the damage is actually probed. On November 14, 2009 Syndial filed its objections to the independent appraiser report, sharing the conceptual model adopted by the independent appraiser report but demonstrating that the site contamination should be charged mainly to

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past management of the pollution slag on part of other operators that operated the site until the ’70s. On November 11, 2009 the Calabria Region filed its objection to the independent appraiser report affirming that the environmental damage to the surrounding areas of the site has not been assessed by the independent appraisers. The hearing for the review of the independent appraiser report and of the parts objections has been scheduled for April 13, 2010, as it has been assigned to another judge.
In order to arrange for a possible resolution of all environmental claims, in 2007 Eni’s subsidiary Syndial took charge of the management of the clean-up activities and on December 5, 2008 presented a new clean-up project. As for the approval procedure of the abovementioned project all interested parties approved the removal of the dump from the seafront to another area, the construction of an hydraulic barrier and of the related treatment plant of the groundwater (providing that if the subsequent monitoring would demonstrate the efficiency of the plant, Eni’s subsidiary would build up a physical barrier in the seafront) and the start-up of the first lot of activities on the soil through in situ technologies on condition that all the waste present in the areas, recognized after a specific inspection.
Initially, the environmental provision made by Syndial in its financial statements amounted to euro 103 million based on the cost estimation of the original clean-up project, as the Eni’s subsidiary believes to have no responsibility for the environmental damage considering the limited period during which it conducted industrial activities in the site and the Delegated Commissioner responsibility for not having properly managed the site cleanup activities. In the 2008 financial statements, Eni increased the environmental provision by euro 154 million bringing the total amount of the environmental provision related to the clean-up project to euro 257 million. The provision doesn’t cover the entire amount of clean-up project expenses (euro 300 million) considering the circumstance that it has been only partially approved. It must be noted that in 2003 the Delegated Commissioner for Environmental Emergency, Calabria Region and Province of Crotone presented a first claim for the payment of damages. With a decision in May 2007, the Court of Milan declared the invalidity of the power of proxy conferred to the Delegated Commissioner to act on behalf of the Calabria Region with the notice served to Syndial SpA and decided the liquidation of expenses born by the defendant. The appeal against that decision is pending. The claims made in this first instance are substantially absorbed in the two subsequent proceedings.
(iv) Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore - Prosecuting body: Ministry of the Environment. With a temporarily executive decision dated July 3, 2008 the District Court of Turin sentenced the subsidiary Syndial SpA (former EniChem) to compensate for environmental damages that were allegedly caused when EniChem managed an industrial plant at Pieve Vergonte during the 1990-1996 period. Specifically, the Court sentenced Syndial to pay the Italian Ministry of the Environment compensation amounting to euro 1,833.5 million, plus legal interests that accrue from the filing of the decision. Syndial and Eni technical-legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary deem the amount of the environmental damage to be absolutely ill-founded as the sentence has been considered to lack sufficient elements to support such a material amount of the liability charged to Eni and its subsidiary with respect to the volume of pollutants ascertained by the Italian Environmental Minister. On occasion of the 2008 consolidated financial statements, management confirmed its stance of making no loss provision for this proceeding on the basis of the abovementioned technical legal advice, in concert with external consultants on accounting principles. In July 2009, Eni’s subsidiary Syndial filed an appeal against the abovementioned sentence, also requesting suspension of the sentence effectiveness. The Ministry of the Environment, in the appeal filed, requested to the Second Instance Court to adjust the first degree sentence condemning Syndial to the payment of euro 1,900 million or alternatively euro 1,300 million in addition to the amount assessed by the First Degree Court. In the hearing on December 11, 2009, the Second Instance Court considering the modification of Environmental Damage regulation introduced by the Article 5 of the Law Decree 135/2009 and following a request of the Board of State lawyers decided the postponement to May 28, 2010, pending the Decree of the Ministry of the Environment related to the determination of the quantification criteria for the monetary compensation of the environmental damage pursuant to the abovementioned Article 5-bis of the Law Decree No. 135/2009. The Board of State lawyers committed itself to not examine the sentence until the next hearing. Another administrative proceeding is ongoing regarding a ministerial decree enacted by the Italian Ministry for the Environment. The decree provides that Syndial executes the following tasks: (i) the upgrading of a hydraulic barrier to protect the site; and (ii) the design of a project for the environmental remediation of Lake Maggiore. The Administrative Court of Piemonte rejected Syndial’s opposition against the outlined environmental measures requested by the Ministry of the Environment. However, the Court judged the prescriptions of the Ministry regarding the remediation of the site to be plain findings of an environmental enquiry to ascertain the state of the lake. Syndial has filed an appeal against the decision of the Court before an upper degree body, also requesting suspension of the effectiveness of the decision.
The appeal has been put on hold considering that a plan to ascertain the environmental status of the site has been approved by all interested parties, including the Ministry and local municipalities pursuant to the statement on April 28, 2009, which included certain recommendations. Syndial appealed against this statement and the related Ministerial Decree of approval

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in order to avoid the case to give implicit consent to the request (appealed by the Company) of the Minister that claimed that Syndial is obliged to execute the clean-up. On the contrary, Syndial has agreed on the scope of the plan to ascertain the environmental status of the site, as it has been actually implementing it.
Syndial also presented a clean-up project for the groundwater and the soil, that hasn’t been approved, as the abovementioned prescriptions that have been prescribed are the object of the Company opposition in the abovementioned proceeding. In case Syndial should be found guilty, it would incur remediation and cleanup expenses, actually not quantifiable, that would be offset against any compensation for the environmental damage that Eni’s subsidiary is condemned to pay with regard to civil proceeding pending before the second instance court of Turin.
(v) Action commenced by the Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage. The Municipality of Carrara commenced an action before the Court of Genova requesting Syndial SpA to remediate and restore previous environmental conditions at the Avenza site and the payment of unavoidable environmental damage (amounting to euro 139 million), further damages of various types (e.g. damage to the natural beauty of this site) amounting to euro 80 million as well as damages relating to loss of profit and property amounting to approximately euro 16 million. This request is related to an accident that occurred in 1984, as a consequence of which EniChem Agricoltura SpA (later merged into Syndial SpA), at the time owner of the site, carried out safety and remediation works. The Ministry of the Environment joined the action and requested environmental damage payment – from a minimum of euro 53.5 million to a maximum of euro 93.3 million – to be broken down among the various companies that ran the plant in the past. Syndial summoned Rumianca SpA, Sir Finanziaria SpA and Sogemo SpA, who ran the plant in previous years, in order to be guaranteed. A report produced by an independent expert charged by the judge was filed with the Court. The findings of this report quantify the residual environmental damage at euro 15 million. With a sentence of March 2008, the Court of Genova rejected all claims made by the Municipality of Carrara and the Ministry of Environment. Both plaintiffs filed an appeal against this decision in June 2008 confirming the requests issued in the first judgment degree and a total compensation in the amount of euro 189.8 million. Syndial filed in the appeal hearing, disputing the plaintiffs’ claims. The proceeding is underway without any further investigation. The hearing has been postponed to July 2010 for the filing of the pleadings.
(vi) Ministry for the Environment Augusta harbor. The Italian Ministry for the Environment with various administrative acts prescribed companies running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Polimeri Europa, Syndial and Eni R&M. Pollution has been detected in this area primarily due to a high mercury concentration which is allegedly attributed to the industrial activity of the Priolo petrochemical site. The abovementioned companies opposed said administrative actions, objecting in particular to the way in which remediation works have been designed and information on concentration of pollutants has been gathered. The Regional Administrative Court of Catania with the Sentence No. 1254/2007 annulled the said decisions. The Ministry and the municipalities of Augusta and Melilli filed a claim for the revocation of the decision and requested the suspension of sentence effectiveness with the Administrative Council of the Sicily Region which accepted the claim. The recommendations which the Council’s decision related, have been restated by the Ministry for the Environment with further administrative resolutions that have been appealed by the Eni companies. Again the Regional Administrative Court of Catania reiterated its decision to suspend the effectiveness of the Ministry’s acts.
In January 2008 the Regional Court of Catania accepted further claims on this matter. In June 2008 the Ministry for the Environment and the Municipalities of Melilli and Augusta filed an appeal against the decision of the Regional Court of Catania with the Administrative Council of the Sicily region, without a resolution of the issue of suspending the effectiveness of the Regional Court’s decisions.
The hearing for the examination of both appeal pending with the Administrative Council of the Sicily Region that has been originally scheduled on December 11, 2008, has been postponed sine die due to preliminary issues pending with the Court of Justice of the European community.
In April 2008, the Eni companies challenged certain administrative acts of December 20, 2007 related to the execution of further clean-up and remediation works of sediments in the Augusta harbor. In this proceeding the Regional Court of Catania has ordered an independent appraiser report, issued on February 20, 2009, that resulted favorable to the objections of the recurring companies. The proceeding is pending.
In May 2008, the Eni companies also challenged with the Regional Court of Catania, requesting the suspension of administrative act effectiveness, certain decisions of an Administrative Body on March 6, 2008 (and other subsequent decisions). Those decisions were intended to enlarge the scope of the already approved project of environmental remediation and clean-up of the groundwater trough works of physic limitation and the new criteria used by the Administration Body in the restitution of the areas to their legitimate use. With regard to this last proceeding, basing on a request of the appealing companies, the Regional

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Court of Catania requested the decision of the Court of Justice of EU to decide on the correct application of the community principle, that represent the basis for the all appeals’ decision particularly the principles of the liability associated with the environmental damage, the proportionality in bearing the expenditures associated with environmental remediation and clean-up, as well as a criteria of reasonableness and diligent execution in remedying an environmental damage. On March 9, 2010 the European Court gave a sentence that basically represented a favorable outcome for Eni’s subsidiaries involved in the matter. Specifically, the European Court confirmed the community principle of the liability associated with the environmental damage, whereby central to its correct interpretation is the relation between cause and effect and the identification of the entity that is actually liable for polluting.
It must be noted that the Public Prosecutor of Siracusa commenced a criminal action against unknown in order to verify the effective contamination of the Augusta harbor and the connected risks on the execution on the clean-up project proposed by the Ministry. The technical assessment disposed by the Public Prosecutor generated the following outcomes: a) no public health risk in the Augusta harbor; b) absence of any involvement on part of Eni companies in the contamination; c) drainages dangerousness. Based on those findings, the Public Prosecutor decided to dismiss the proceeding.

ENI SPA
(vii) Reorganization procedure of the airlines companies Volare Group, Volare Airlines and Air Europe - Prosecuting body: Delegated Commissioner. In March 2009 Eni and its subsidiary Sofid (now Eni Adfin) were notified of a bankruptcy claw-back as part of a reorganization procedure filed by the airlines companies Volare Group, Volare Airlines and Air Europe which commenced under the provisions of Ministry of Production Activities, on November 30, 2004. The request regarded the override of all the payments made by those entities to Eni and Eni Adfin, as Eni agent for the receivables collection, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, for a total estimated amount of euro 46 million plus interest. Eni and Eni Adfin were admitted as defendants and the trial has been postponed to the hearing on May 5, 2010 for the related investigation. Eni accrued a risk provision with respect to this proceeding.

2. Other judicial or arbitration proceedings

SYNDIAL SPA (FORMER ENICHEM SPA)
(i) Serfactoring: disposal of receivables. In 1991, Agrifactoring SpA commenced proceedings against Serfactoring SpA. The claim relates to an amount receivable of euro 182 million for fertilizer sales (plus interest and compensation for inflation), originally owed by Federconsorzi to EniChem Agricoltura SpA and Terni Industrie Chimiche SpA (both merged into Syndial). Such receivables were transferred by Agricoltura and Terni Industrie Chimiche to Serfactoring, which appointed Agrifactoring as its agent to collect payments. Agrifactoring guaranteed to pay the amount of such receivables to Serfactoring, regardless of whether or not it received payment on the due date. Following payment by Agrifactoring to Serfactoring, Agrifactoring was placed in liquidation and the liquidator of Agrifactoring commenced proceedings in 1991 against Serfactoring to recover such payments (equal to euro 182 million) made to Serfactoring based on the claim that the foregoing guarantee became invalid when Federconsorzi was itself placed in liquidation, claiming for the reimbursement of the amount paid to Serfactoring and not liquidated to Agrifactoring by Federconsorzi. Syndial and Serfactoring filed counterclaims against Agrifactoring (in liquidation) for damages amounting to euro 97 million relating to acts carried out by Agrifactoring SpA as agent. The amount of these counterclaims was subsequently reduced to euro 46 million following partial payment of the original receivables by the liquidator of Federconsorzi and various setoffs. These proceedings, which were unitized, were decided with a partial judgment, deposited on February 24, 2004; the request of Agrifactoring – that was reduced by an independent accounting consultant to the amount of euro 42.3 million – was rejected and the company was ordered to pay the sum requested by Serfactoring and Syndial to be determined following the decision. Agrifactoring appealed this decision and in June 2008, the trial was decided with a partial judgment that, reforming the previous judgment of the Court of Rome, granted the requests of Agrifactoring and condemned Serfactoring to reimburse Agrifactoring the sum paid by the latter to the former and not refunded by Federconsorzi. The Court resolved to charge an independent accounting consultant with quantifying the total amount paid by Agrifactoring to Serfactoring and the amount paid by Federconsorzi to Agrifactoring in order to determine the sum to be reimbursed to Agrifactoring.
The proceeding will continue with the recognition of the assessment made by the independent accounting consultant. Serfactoring and Syndial (as precautionary measure, since they have already filed a preliminary appeal) appealed the above mentioned partial sentence of 2008 of the second instance Court of Rome with an upper degree Court. Agrifactoring in turn filed counterclaim, requesting the declaration of inadmissibility or the rejection of the appeal. The judgment is still pending. Eni accrued a provision with respect to this proceeding.

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SAIPEM SPA
(ii) CEPAV Uno and CEPAV Due. Saipem holds interests in the CEPAV Uno (50.36%) and CEPAV Due (52%) consortia that in 1991 signed two contracts with TAV SpA for the construction of two railway tracks for high speed/high capacity trains from Milan to Bologna (under construction) and from Milan to Verona (in the design phase). With regard to the project for the construction of the line from Milan to Bologna, an Addendum to the contract between CEPAV Uno and TAV was signed on June 27, 2003, redefining certain terms and conditions of the contract. Subsequently, the CEPAV Uno consortium requested a time extension for the completion of works and a claim amounting to euro 800 million then increased to euro 1,770 million. CEPAV Uno and TAV failed to solve this dispute amicably. CEPAV Uno opened an arbitration procedure as provided for under terms of the contract on April 27, 2006. The deadline for the submission of the arbitration determination has been scheduled for December 27, 2011. With regard to the project for the construction of a high-speed railway from Milan to Verona, in December 2004, CEPAV Due presented the final project, prepared in accordance with Law No. 443/2001 on the basis of the preliminary project approved by an Italian governmental authority (CIPE). As concerns the arbitration procedure, commenced on December 28, 2000, requested by CEPAV Due against TAV for the recognition of costs incurred by the Consortium in the ten-year period from 1991 through 2000 plus damages suffered, in January 2007, the arbitration committee determined the Consortium’s right to recover the costs incurred in connection with the design activities performed. The technical independent survey to assess the amount of compensation was submitted on October 19, 2009. The trial ended on February 23, 2010 with the resolution of the arbitration that condemned TAV to pay to CEPAV Due consortium an amount of euro 44,176,787 plus legal interest and compensation for inflation accrued from the submission of the arbitration until the date of effective damage payment; the Court also condemned TAV to pay euro 1,115,000 plus interest and compensation for inflation accrued from October 30, 2000 until the date of effective damage payment. TAV filed with the second instance court of Rome an appeal against the partial arbitration committee’s determination of January 2007. The hearing for the examination of the pleadings has been scheduled for January 28, 2011. In February 2007, the Consortium CEPAV Due notified to TAV a second request of arbitration following the Decree No. 7 of December 31, 2007, that revoked the concessions awarded to TAV resulting in the annulment of arrangements signed between TAV and the Consortium to build the high-speed railway section from Milan to Verona. The European Court of Justice was requested to judge on this matter. Subsequently, Law 133/2008 re-established the concessions awarded to TAV resulting in the continuation of the arrangements between the consortium CEPAV Due and a new entity in charge of managing the Italian railway system. The second arbitration proceeding, which continued in order to determinate the damages suffered by the Consortium even in the period prior to the revocation of the concession through an independent appraiser report. The deadline for the submission of the arbitration determination has been scheduled for December 31, 2010.

3. Antitrust, EU Proceedings, Actions of the Authority for Electricity and Gas and of Other Regulatory Authorities

3.1 Antitrust

(i) Abuse of dominant position of Snam alleged by the Italian Antitrust Authority. In March 1999, the Italian Antitrust Authority concluded its investigation started in 1997 and: (i) found that Snam SpA (merged in Eni SpA in 2002) abused its dominant position in the market for the transportation and primary distribution of natural gas relating to the transportation and distribution tariffs applied to third parties and the access of third parties to infrastructure; (ii) fined Snam for euro 2 million; and (iii) ordered a review of the practices relating to such abuses. Snam believes it has complied with existing legislation and appealed the decision with the Regional Administrative Court of Lazio requesting its suspension. On May 26, 1999, stating that these decisions are against Law No. 9/1991 and the European Directive 98/30/EC, this Court granted the suspension of the decision. The Authority did not appeal this decision. The decision on the merit of this dispute is still pending before the same Administrative Court.
(ii) European Commission’s investigations on players active in the natural gas sector. In the context of its initiatives aimed at verifying the level of competition in the natural gas sector within the European Union, the Commission adopted a decision – notified to Eni in May, 2006 – whereby it ordered Eni and all companies solely or jointly controlled by the latter to submit to inspections pursuant to Article 20, paragraph 4 of the Council Regulation No. 1/2003. The inspections were intended to verify the possible existence of behaviors or commercial practices violating EC competition rules and aimed at limiting access to the Italian wholesale natural gas market or at sharing the market with other companies active in the sale or transport of natural gas. The Commission undertook similar initiatives with respect to the other largest European players in the natural gas sector in Germany, France, Austria and Belgium. On March 9, 2009, Eni received a statement of

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objections by the European Commission relating to a proceeding under Article 82 EC and Article 54 of the EEA Agreement and concerning an alleged unjustified refusal to grant access to the TAG (Austria), TENP/Transitgas (Germany/Switzerland) pipelines, connected with the Italian gas transport system. In particular, according to the Statement of Objections, the alleged refusal to grant access would have been carried out through "capacity hoarding, capacity degradation and strategic underinvestment" and would have had the effect of "hindering the development of effective competition in the downstream market and [...] harming consumers". In the Statement of Objections, the Commission envisages the possible imposition upon Eni of structural remedies and a fine, which, if imposed, could be significant. Eni after the completion of the assessment of the allegations set forth by the Commission in Statement of Objections with respect to both the existence of the alleged behaviors and whether they can be properly qualified as infringements of EC competition rules submitted its written reply that was exposed before the representatives of the Commission in November 27, 2009. On February 4, 2010 Eni, reaffirming the legitimacy of its activity, filed with the European Commission a number of structural remedies with a view to resolving the proceeding without the ascertainment of the illicit behavior and consequently without sanctions. Eni has committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines. Given the strategic importance of the Austrian Tag pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. The European Commission has announced its intention to submit those remedies to a market test. According to the results of the market test, the Commission may issue a decision pursuant to Article 9 of Council Regulation No. 1/2003, making the remedies mandatory thus excluding the imposition of any fines upon Eni. In case the Commission, after the performance of the market test, resolves to reject Eni’s remedies, or the Company decides to withdraw those remedies for any reasons, the ordinary antitrust proceeding would resume and in this eventuality an adverse conclusion cannot be excluded, thus resulting in a sentence of conviction including a fine and possibly structural remedies during the course of 2010. Eni would in any event be entitled to file an appeal for the annulment of such a sentence before the EC Courts.
(iii) TTPC. In April 2006, Eni filed a claim before the Regional Administrative Court of Lazio against the decision of the Italian Antitrust Authority of February 15, 2006 stating that Eni’s behavior pertaining to implementations of plans for the upgrading of the TTPC pipeline for importing natural gas from Algeria represented an abuse of dominant position under Article 82 of the European Treaty and fined Eni. The initial fine amounted to euro 390 million and was reduced to euro 290 million in consideration of Eni’s commitment to perform actions favoring competition including the upgrade of the gasline. Eni accrued a provision with respect to this proceeding. With a decision filed on November 29, 2006, the Regional Administrative Court of Lazio partially accepted Eni’s claim, annulling such part of the Authority’s decision where the fine was quantified. Eni is waiting for the filing of the motivations of the Court decision to ascertain the impact of said decision. Pending this development, the payment of the fine has been voluntarily suspended. In 2007, the Regional Administrative Court of Lazio accepted in part Eni’s claim and cancelled the quantification of the fine based on the Antitrust Authority’s inadequate evaluation of the circumstances presented by Eni. Eni filed an appeal with the Council of State, as did the Antitrust Authority and TTPC. Pending the final outcome, Eni awaits for the determination of the amount of the fine to be paid.
(iv) Italian Antitrust Authority’s inquiry in the distribution and selling of gas in the retail sector. On May 7, 2009, the Italian Antitrust Authority, based on complaints sent by the company Sorgenia, started a preliminary investigation against various operators engaging in the gas retail market in Italy by means of integrated operations in both gas distribution via local low-pressure network and gas marketing to retail customers in urban areas, among them the Company and its fully-owned subsidiary Italgas. The investigation targets an alleged abuse of dominant position in the gas retail market in Italy associated with commercial practices intended to make it difficult for retail customers consuming less than 200,000 cubic meters per year to change the supplier. According to the Italian Antitrust Authority, these commercial practices would enable selling companies that belong to integrated group companies to preserve their market shares in the areas operated by Group’s distributors. The deadline for the finalization of the preliminary investigation against Eni and Italgas has been scheduled for June 30, 2010.

ENI SPA, POLIMERI EUROPA SPA AND SYNDIAL SPA
(v) Inquiries in relation to alleged anti-competitive agreements in the area of elastomers - Prosecuting Body: European Commission. In December 2002, inquiries were commenced concerning alleged anti-competitive agreements in the field of elastomers. These inquiries were commenced concurrently by European and U.S. authorities. At present, a proceeding is still pending before the European Commission regarding the NBR product. In December 2007, the European Commission dismissed Syndial’s position on CR and imposed on Eni and Polimeri a fine amounting to euro 132.16 million. The two companies have filed an appeal with the EU Court of First Instance against this decision and, at the same time, paid the fine in March 2008. Investigations relating to other elastomers products (BR and SBR) resulted in the ascertainment of Eni having infringed European competition laws. On November 29, 2006, the Commission fined Eni and its subsidiary Polimeri Europa for an

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amount of euro 272.25 million. Eni and its subsidiary filed claims against this decision before the European Court of First Instance in February 2007. The hearings took place in October 2009 and the filing of the Court’s decisions is still pending. Pending the outcome, Polimeri Europa presented a bank guarantee for euro 200 million and paid the residual amount of the fine. In August 2007, with respect to the above mentioned decision of the European Commission, Eni submitted a request for a negative ascertainment with the Court of Milan aimed at proving the non-existence of alleged damages suffered by tire BR/SBR manufacturers. The Court of Milan declared the appeal inadmissible appealing against a sentence of the District Court of Milan; the related hearing has been scheduled for May 2010.

3.2 Regulation

(i) Toscana Energia Clienti SpA. Eni’s subsidiary Toscana Energia Clienti SpA started an action against a customer regarding alleged lack of measurement of gas consumption due to inability to access a measurement facility at the customer’s site, also in connection with the application of Resolution No. 229/2001 of the Italian Authority for Electricity and Gas. This customer has annual consumption in excess of 5,000 cm. The defendant has filed a counter-claim in relation to this proceeding. During the hearing on November 12, 2008, the judge resolved to partially accept the Eni’s subsidiary reasons and to limit compensation to be paid to the defendant to only euro 1,475 with interests amounting to euro 90. The sum was paid and the defendant in December 2009 filed an appeal against the said decision.
(ii) Distribudora de Gas Cuyana SA. Formal investigation of the agency entrusted with the regulations for the natural gas market in Argentina. Enargas started a formal investigation on some operators, among them Distribuidora de Gas Cuyana SA, a company controlled by Eni. Enargas stated that the company improperly applied conversion factors to volumes of natural gas invoiced to customers and requested the company to apply the conversion factors imposed by local regulations from the date of the default notification (March 31, 2004) without prejudice to any damage payment and fines that may be decided after closing the investigation. In April 2004 the company filed a defensive memorandum. On April 28, 2006, the company formally requested the acquisition of documents from Enargas in order to have access to the documents on which the allegations are based.
(iii) Preliminary investigation of the Authority for Electricity and Gas on the application of the regulation on the issue of the transparency of invoices. On September 25, 2009 the Authority for Electricity and Gas sentenced (Sentence VIS 93/2009) to commence a preliminary investigation against 5 marketing companies in the electricity sector, including Eni, to ascertain the eventual violation of the regulation on the issue of the transparency of the invoices (Resolutions 152/2006, 156/2007 and 272/2007) and to eventually inflict administrative monetary penalties. The preliminary investigation should be finalized within a 120-day term from the communication of the proceeding to the parties.

4. Tax Proceedings

ITALY - ENI SPA
(i) Dispute for the omitted payment of the municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. Dispute for the omitted payment of the municipal tax related to oil platforms located in territorial waters in the Adriatic Sea. With a formal assessment presented by the Municipality of Pineto (Teramo) in December 1999, Eni SpA has been accused of not having paid a municipal tax on real estate for the period from 1993 to 1998 on four oil platforms located in the Adriatic Sea which constitute municipal waters in front of the coast of Pineto. Eni was requested to pay a total of approximately euro 17 million including interest and a fine. Eni filed a claim against this request stating that the sea where the platforms are located is not part of the municipal territory and the tax application as requested by the municipality lacked objective fundamentals. The claim has been accepted in the first two degrees of judgment at the Provincial and Regional Tax Commissions. However, the Court overturned both judgments, declaring that a municipality can consider requesting a tax on real estate in the sea facing its territory and with the decision of February 2005 sent the proceeding to another section of the Regional Tax Commission in order to judge on the matters of the proceeding. This commission charged an independent consultant with assessing all the accounting/technical aspects of the matter. The independent consultant confirmed that Eni’s offshore installations lack any ground to be subject to the municipal tax that was claimed by the local Municipality. Those findings were accepted by the Regional Tax Commission with a rule made on January 19, 2009, and filed on December 14, 2009.
Also, on December 28, 2005, the Municipality of Pineto presented similar claims relating to the same Eni’s platforms for the years 1999 to 2004. The total amount requested was euro 24 million including interest and penalties. Eni filed a claim against this claim which was accepted by the first degree judge with a decision of December 4, 2007. Similar formal assessments related

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to Eni oil and gas offshore platforms were presented by the Municipalities of Falconara Marittima, Tortoreto, Pedaso, and also from 2009, the Gela Municipality. The total amounts of those claims were approximately euro 7.5 million. The company filed appeal against all those claims.

OUTSIDE ITALY - AGIP KARACHAGANAK BV
(ii) Claims concerning unpaid taxes and relevant payment of interest and penalties. In July 2004, relevant Kazakh Authorities informed Agip Karachaganak BV and Karachaganak Petroleum Operating BV, shareholder and operator of the Karachaganak contract, respectively, on the final outcome of 2000 to 2003 tax audits. Both companies counterclaimed against the assessment and a preliminary agreement was reached on November 18, 2004. Final assessments have now been issued by the Kazakh Authorities, and payment has been made. The final amount assessed and paid was $39 million net to Eni; this figure included taxes and interest. The companies continue to dispute the assessments and reserve the right to engage in International Arbitration proceedings with the Kazakh Authorities.
In October 2009, Kazakh Tax Authorities conducted a complex tax audit of Agip Karachaganak BV Branch and Karachaganak Petroleum Operating Co BV Branch, for the period 2004-2007.
In December 2009, the tax authorities issued Tax Audit Act and relevant Notification for the year 2004 but so far nothing has been finalized for the later years. The 2004 audit resulted in an assessment of $21.6 million relating to CIT and WHT ($0.3 million). These amounts are disputed and appeals have been submitted to the Higher Level Tax Authority. There is also a dispute in relation to certain unresolved items of expenditure incurred by the operating company Karachaganak Petroleum Operating BV which has led to the Kazakh Authorities making certain claims against the company on the base of audits performed relating to prior years 2003-2006. Parties are negotiating in order to settle the dispute.
(iii) Tax proceeding Eni Angola Production BV. In the first months of 2009 the Ministry of the Finance of Angola, following to a fiscal audit commenced at the end of 2007, filed a notice of tax assessment for fiscal years 2002 to 2007 by which objected to the deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as co-operator of Cabinda concession. The company filed an appeal against this decision with the Provincial Court of Luanda for all the years of the claim. The Court of First Instance declared that it lacked competence in judging the matter. The judgment is still pending before the Supreme Court. Eni accrued a provision with respect to this proceeding.

5. Court Inquiries

(i) EniPower. In June 2004, the Milan Public Prosecutor commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. These inquiries were widely covered by the media. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately dismissed. The Court presented EniPower (commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of process in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In its meeting of August 10, 2004, Eni’s Board of Directors examined the aforementioned situation and Eni’s CEO approved the creation of a task force in charge of verifying the compliance with Group procedures regarding the terms and conditions for the signing of supply contracts by EniPower and Snamprogetti and the subsequent execution of works. The Board also advised divisions and departments of Eni to cooperate fully in every respect with the Court. From the inquiries performed, no default in the organization emerged, nor deficiency in internal control systems. External experts have performed inquiries with regard to certain specific aspects. In accordance with its transparency and firmness guidelines, Eni took the necessary steps in acting as plaintiff in the expected legal action in order to recover any damage that could have been caused to Eni by the illicit behavior of its suppliers and of their and Eni employees. In the meantime, preliminary investigations have found that both EniPower and Snamprogetti are not to be considered defendants in accordance with existing laws regulating the administrative responsibility of companies (Legislative Decree No. 231/2001). In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the preliminary hearing requested all the parties that have not requested the plea-bargain to stand in trial, excluding Romeo Franco Musazzi and ABB Instrumentation SpA as a result of the statute of limitations. During the hearing on March 2, 2010 the Court confirmed the admission as plaintiffs of Eni SpA, EniPower SpA and Saipem SpA against the inquired parts under the provisions of Legislative Decree No. 231/2001. The trial has been postponed to the

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hearing on April 13, 2010 in order to permit the identification of the defendants of further companies involved.
(ii) Trading. An investigation is pending regarding two former Eni managers who were allegedly bribed by third parties in favor to the closing of certain transactions with two oil product trading companies. Within such investigation, on March 10, 2005, the public prosecutor of Rome notified Eni of two judicial measures for the seizure of documentation concerning Eni’s transactions with the said companies. Eni is acting as plaintiff in this proceeding. The judge for preliminary hearings rejected most of the dismissal requests issued by the public prosecutor. Basing on the decision of the judge for preliminary hearings, the public prosecutor of Rome notified Eni, as injured part, the summon against two former managers of the company charged of aggravated fraud related to the relevant patrimonial damage caused to the injured part through the abuse of working relations and activities. The first hearing, scheduled for January 27, 2010, has been postponed to March 30, 2010 due to the cancellation of the hearings deliberated by the Association of Italian Criminal Courts.
(iii) TSKJ Consortium Investigations by U.S., Italian, and Other Authorities. Snamprogetti Netherlands BV has a 25% participation in the TSKJ Consortium companies. The remaining participations are held in equal shares of 25% by Halliburton/KBR, Technip, and JGC. Beginning in 1994 the TSKJ Consortium has been involved in the construction of natural gas liquefaction facilities at Bonny Island in Nigeria. Snamprogetti SpA, the holding company of Snamprogetti Netherlands BV, was a wholly owned subsidiary of Eni until February 2006, when an agreement was entered into for the sale of Snamprogetti to Saipem SpA and Snamprogetti was merged into Saipem as of October 1, 2008. Eni holds a 43% participation in Saipem. In connection with the sale of Snamprogetti to Saipem, Eni agreed to indemnify Saipem for a variety of matters, including potential losses and charges resulting from the investigations into the TSKJ matter referred to below, even in relation to Snamprogetti subsidiaries. The U.S. Securities and Exchange Commission (SEC), the U.S. Department of Justice (DOJ), and other authorities, including the Public Prosecutor’s office of Milan, are investigating alleged improper payments made by the TSKJ Consortium to certain Nigerian public officials. The proceedings in the US: beginning in June 2004, Eni and Saipem/Snamprogetti have been voluntarily providing information in response to requests by the SEC and the DOJ in connection with the investigations. In February 2009, KBR and its former parent company, Halliburton, announced that they had reached a settlement with the SEC and the DOJ with respect to the TSKJ matter as well as other unspecified matters. KBR/Halliburton pleaded guilty to Foreign Corrupt Practices Act (FCPA) charges, for the conduct stemming from their participation in TSKJ, and they have agreed to pay a criminal fine of $402 million to the DOJ and a civil penalty of $177 million to the SEC. In view of the agreements entered into by KBR/Halliburton with the DOJ and SEC, the TSKJ matter could result in legal liability on the part of individuals as well as the other members of the TSKJ Consortium Entities found in violation of the FCPA, and those entities could be subject to substantial fines and the imposition of ongoing measures by the US government to prevent future violations, including potentially a monitor of internal controls, and debarment from government contracts.
In a press release on February 12, 2010, the French company Technip announced, as a result of the circumstances that its discussions with US authorities have intensified over the last weeks, the recognition of a provision for an amount of euro 245 million reflecting the estimated cost of resolution with such Authorities. The decision was made according to the status of ongoing discussions with DOJ and SEC that allowed Technip to estimate a global resolution of all potential claims against the company arising from the investigation.
As to Eni, the contacts with the US authorities have been intensified recently. Based on the ongoing status of the discussions, the Company has been able to estimate the cost of a global resolution of all potential claims arising from the investigation with the US authorities, similarly to Technip. As a result of this, a provision in the amount of euro 250 million has been accrued, also considering the contractual obligations assumed by Eni to indemnify Saipem as part of the divestment of Snamprogetti. Discussions with the US authorities are underway.
The proceedings in Italy: beginning in 2004, the TSKJ matter has prompted investigations by the Public Prosecutor’s office of Milan against unknown persons. Since March 10, 2009, the company received requests of exhibition of documents by the Public Prosecutor’s office of Milan. On July 17, 2009, the date on which a search and attachment warrant was served on Saipem/Snamprogetti, the Public Prosecutor’s office of Milan indicated to the company that it is investigating one or more people, including at least one former manager of Snamprogetti; previously, as far as the company knew, nobody was under formal investigation. The events under investigation cover the period since 1994 and also concern the period of time subsequent to the June 8, 2001 enactment of the Italian Legislative Decree No. 231 concerning the liability of legal entities. A violation of Legislative Decree June 8, 2001, No. 231 can result in the confiscation of criminal profits in addition to administrative penalties. During the preliminary investigations, the preventive attachment of such profits and other precautionary measures are possible.
On July 31, 2009, a decree issued by the Judge for Preliminary Investigation at the Court of Milan was served on Saipem SpA (as legal entity incorporating Snamprogetti SpA). The decree sets for September 22, 2009 a hearing in Court in relation to a proceeding ex Legislative Decree No. 231 of June 8, 2001 whereby the Public prosecutor of Milan is investigating Eni

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SpA and Saipem SpA for liability of legal entities arising from offences involving international corruption charged to two former managers of Snamprogetti SpA. The Public Prosecutor of Milan requested Eni SpA and Saipem SpA to be debarred from activities involving – directly or indirectly – any agreement with the Nigerian National Petroleum Corporation and its subsidiaries. The above mentioned hearing allow Eni and Saipem to conduct own defense before any decision is made on the requested disqualification. The events referred to the request of precautionary measures of the Public Prosecutor of Milan cover TSKJ Consortium practices in the period from 1995 to 2004. To this regard, the Public Prosecutor claims the inadequacy and violation of the organizational, management and control Model adopted to prevent those offences charged to people subject to direction and supervision. At the time of the events under investigation, the company had adopted a code of practice and internal procedures with reference to the best practices at the time. Subsequently, such code and internal procedures have been improved aiming at the continuous improvement of internal controls. Furthermore, on March 14, 2008 Eni approved a new Code of Ethics and a new Model 231 reaffirming that the belief that one is acting in favor or to the advantage of Eni can never, in any way, justify – not even in part – any behaviors that conflict with the principles and contents of the Code. Since April 23, 2009, with regard to investigations on the TSKJ matter the Company’s Board of Directors has timely recalled the analysis of the existing internal procedures against corruption, in order to implement any upgrading to be possibly needed, and to continue the cooperation with the relevant authorities and also resolved to promote all legal measures for protecting the Company’s interests and reputation, in case the responsibility of its employees or collaborators is verified. The jury room of September 22, 2009 has been postponed to the hearing of October 21, 2009 when the judge for the preliminary investigation rejected the request of precautionary measures of disqualification filed by the Public Prosecutor of Milan against Eni and Saipem. The Public Prosecutor of Milan appealed the decision of the Judge for Preliminary Investigation. The hearing for the review of the appeal, scheduled initially for January 20, 2010 has been anticipated, through a measure communicated to the defense on January 12, 2010, on January 19, 2010 when the Judge of Re-examination dismissed as unfounded the appeal of the Public Prosecutor. In February 19, 2010 the Public Prosecutor of Milan filed an appeal with the Third Instance Court, asking for the cancellation of the abovementioned decision of the Judge of Re-examination. At the same time in February 11, 2010 the Public Prosecutor of Milan requested, according to Article 248 of Penal Code the collection of documentation and information related to companies participated by Eni SpA and Saipem SpA (former Snamprogetti SpA) involved in Bonny Island project.
(iv) Gas Metering. On May 28, 2007, a seizure order (in respect to certain documentation) was served upon Eni and other Group companies as part of a proceeding brought by the Public Prosecutor at the Courts of Milan. The order was also served upon five top managers of the Group companies in addition to third party companies and their top managers. The investigation alleges behavior which breaches Italian criminal law, starting from 2003, regarding the use of instruments for measuring gas, the related payments of excise duties and the billing of clients as well as relations with the Supervisory Authorities. The allegation regards, interalia, the offense contemplated by Legislative Decree of June 8, 2001, No. 231, which establishes the liability of the legal entity for crimes committed by its employee in the interests of such legal entity, or to its advantage. Accordingly, notice of the commencement of investigations was served upon Eni Group companies (Eni, Snam Rete Gas and Italgas) as well as third party companies. On November 26, 2009 a notice of conclusion of the preliminary investigation was served to Eni’s Group companies whereby 14 Eni employees, also including former employees, are under investigation. The exceptions filed in the notice include: (i) violations pertaining recognition and payment of certain amounts of the excise on natural gas; (ii) violations or failure in submitting the annual statement of gas consumption and/or in the annual declarations to be filed with the Duty Authority or the Authority for Electricity and Gas; (iii) a related obstacle which has been allegedly posed to the monitoring functions performed by the Authority for Electricity and Gas. Based on information reported by the press on March 9, 2010, it has been disseminated that the Public Prosecutor of Milan requested that a number of investigated Eni’s employees and former employees would stand trial.
On February 23, 2010 Eni, Snam Rete Gas and Italgas have been received a notification requesting the collection of documents related to procedures of constitution, definition, update and implementation of Model 231 in the period from 2003 to 2008.
The Group companies are cooperating with the Supervising Authorities in the investigations.
(v) Agip KCO NV. In November 2007, the public prosecutor of Kazakhstan informed Agip KCO of the start of an inquiry for an alleged fraud in the award of a contract to the Overseas International Constructors GmbH in 2005.
(vi) Kazakhstan. On October 1, 2009 the Public Prosecutor of Milan requested a number of documents pursuant to Article 248 of the Penal Code. Through this decision, part of a criminal proceeding against unknown, Eni SpA was requested to transmit – in relation to the alleged international corruption, embezzling pillage, and other crimes – audit reports and other documentation related to anomalies and critical issues on the management of the Karachaganak plant and the Kashagan project. The crime of "international corruption" mentioned in the said request of transmission of documents is sanctioned, in addition to the Italian criminal code, by Legislative Decree June 8, 2001, No. 231 which establishes the administrative responsibility of companies for crimes committed by their employees on their behalf. Eni commenced the collection of the documentation in order to rapidly

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fulfill the requests of the Public Prosecutor. The company has deposited in different phases the documents collected. The Company continues to fully collaborate with the Public Prosecutor providing also further documentation when available.

6. Settled Proceedings

(i) Preliminary investigation of the Authority for Electricity and Gas about application of the "K" conversion factors for volumes adjustments. In May 2009 the Authority for Electricity and Gas, based on evidence collected during certain inspections and subsequent requests of information, communicated to the Company the results of an inquiry that stated that the company improperly applied the conversion factor "K" for natural gas volumes accounting at a number of Eni’s delivery points. The company filed its conclusions in a defensive memorandum, objecting to the Authority’s findings. On the basis of a comparative evaluation of the sanctions imposed at the end of analogous inquiries commenced against other gas companies, Eni accrued a risk provision with respect to this proceeding. On October 5, 2009, the Authority for Electricity and Gas with sentence VIS 94/2009 upheld partially Eni’s objections and recognized that the obligation to apply the "K" conversion index for marketing companies as determined by the distribution companies was effective from 2004 as opposed to the year 2001 as initially stated by the Authority for Electricity and Gas. This decision determined in one case the ceasing of the infringement as well as the reduction of the liability and associated duration in all the other cases. The Authority for Electricity and Gas imposed a fine amounting to euro 1,023,000 on Eni that was fully covered by the accrued risk provision. Eni paid the sanction even if the Company considers its motivations to be well grounded in the appeal proposed against the Authority for Electricity and Gas findings before the Administrative Court in December 2009.
(ii) Formal assessment commenced by the Commission of the European Communities for the evaluation of alleged participation to activities limiting competition in the field of paraffin. On April 28, 2005, the Commission of the European Communities commenced a formal assessment to evaluate the alleged participation of Eni and its subsidiaries in activities limiting competition in the field of paraffin. The alleged violation of competition is for: (i) the determination of an increase in prices; (ii) the subdivision of customers; and (iii) exchange of trade secrets, such as production capacity and sales volumes. After the Commission requested information on Eni’s activities in the field of paraffin and certain documentation acquired by the Commission during an inspection, Eni filed the requested information. In October 2008, the Commission of the European Communities issued the final decision on the matter condemning Eni to the payment of a sanction amounting to euro 29,120,000. Eni paid the fine which was fully covered by the accrued risk provision, filing however for recourse against this decision.
(iii) Alleged unauthorized waste management activities - EniPower. In 2004, the public prosecutor of Rovigo commenced an investigation for alleged crimes related to unauthorized waste management activities in Loreo relating to the samples of soil used during the construction of the new EniPower power station in Mantova. The prosecutor requested the CEO of EniPower and the managing director of the Mantova plant at the time of the alleged crime to stand trial. In the hearing on April 6, 2009, the Judge dismissed the accusation as a result of the statute of limitations.

Assets under concession arrangements
Eni operates under concession arrangements mainly in the Exploration & Production segment and in some activities of the Gas & Power segment and the Refining & Marketing segment. In the Exploration & Production segment contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. Eni sustains all the operation risks and costs related to the exploration and development activities and it is entitled to the productions realized. In Production Sharing Agreement and in buy-back contracts, realized productions are defined on the basis of contractual agreements drawn up with State oil companies which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to the own portion of the realized productions (profit oil). With reference to natural gas storage in Italy, the activity is conducted on the basis of concessions with a duration that does not exceed twenty years and it is granted by the Ministry of Productive Activities to persons that are consistent with legislation requirements and that can demonstrate to be able to conduct a storage program that meets the public interest in accordance with the laws. In the Gas & Power segment the gas distribution activity is primarily conducted on the basis of concessions granted by local public entities. At the expiration date of the concession, compensation is paid, defined by using criteria of business appraisal, to the outgoing operator following the sale of its own gas distribution network. Service tariffs for distribution are defined on the basis of a method established by the Authority for Electricity and Gas. Legislative Decree No.

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164/2000 provides the grant of distribution service exclusively by tender, with a maximum length of 12 years.
In the Refining & Marketing segment several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. Such assets are amortized over the length of the concession (generally, 5 years for Italy). In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties on the basis of quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession.

Environmental regulations
Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the risk section above, under the paragraph "Operational risks". In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s consolidated financial statements, taking account of ongoing remedial actions, existing insurance policies and the environmental risk provision accrued in the consolidated financial statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of the ongoing surveys and the other possible effects of statements required by Decree No. 471/1999 of the Ministry of Environment; (iii) new developments in environmental regulation; (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries.

Emission trading
Legislative Decree No. 216 of April 4, 2006 implemented the Emission Trading Directive 2003/87/EC concerning greenhouse gas emissions and Directive 2004/101/EC concerning the use of carbon credits deriving from projects for the reduction of emissions based on the flexible mechanisms devised by the Kyoto Protocol. This European emission trading scheme has been in force since January 1, 2005, and on this matter, on November 27, 2008, the National Committee for Emissions Trading Scheme (Ministry of Environment-Mse) published the Resolution 20/2008 defining emission permits for the 2008-2012 period.
Eni was assigned permits corresponding to 126.4 million tonnes of carbon dioxide (of which, 25.8 in 2008, 25.8 in 2009, 25.1 in 2010, 25.0 in 2011, 24.7 in 2012) and in addition to approximately 8.6 million of permits expected to be assigned with respect to new plants in the five-year period 2008-2012. Emissions of carbon dioxide from Eni’s plants were lower than permits assigned in 2009. Against emissions of carbon dioxide amounted to approximately 24.8 millions tonnes, emission permits amounting to 25.9 million tonnes were assigned, determining a 1.1 million tonnes surplus. In addition to such surplus, a 0.3 million tonnes of permits (as increase in the availability of Eni) are to be included following the contract of Virtual Power Plan GDF Suez Energia Italia, primarily assigned to cover the emissions of the EniPower plants. For this reason, the total surplus amounted to about 1.4 million tonnes.

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29 Revenues
The following is a summary of the main components of "Revenues". For more information about changes in revenues, see "Financial Review" of the "Report of Directors".
Net sales from operations were as follows:

(euro million) 2007 2008 2009

Net sales from operations	87,051	107,777	83,519
Change in contract work in progress	153	305	(292	)
	87,204	108,082	83,227

Net sales from operations were net of the following items:

(euro million) 2007 2008 2009

Excise taxes	13,292	13,142	12,122
Exchanges of oil sales (excluding excise taxes)	2,728	2,694	1,680
Services billed to joint venture partners	1,554	2,081	2,435
Sales to service station managers for sales billed to holders of credit cards	1,480	1,700	1,531
Exchanges of other products	121	83	55
	19,175	19,700	17,823

Net sales from operations by business segment and geographic area of destination are presented in Note 35 – Information by business segment and geographic financial information.

Other income and revenues
Other income and revenues were as follows:

(euro million) 2007 2008 2009

Gains from sale of assets	66	48	306
Lease and rental income	95	98	100
Compensation for damages	87	15	54
Contract penalties and other trade revenues	181	23	31
Gains on price adjustments under overlifting/underlifting transactions	79	180	148
Other proceeds (*)	325	364	479
	833	728	1,118

(*) Each individual amount included herein does not exceed euro 50 million.

Gains from sale of assets amounted to euro 306 million of which, euro 283 million related to the Exploration & Production segment.

30 Operating expenses
The following is a summary of the main components of "Operating expenses".
For more information about changes in operating expenses, see "Financial Review" of the "Report of Directors".

Purchases, services and other
Purchases, services and other included the following:

(euro million) 2007 2008 2009

Production costs - raw, ancillary and consumable materials and goods	44,850		58,662		40,311
Production costs - services	10,828		13,355		13,520
Operating leases and other	2,276		2,558		2,567
Net provisions for contingencies	573		884		1,055
Other expenses	1,101		1,660		1,527
	59,628		77,119		58,980
less:
- capitalized direct costs associated with self-constructed assets - tangible assets	(1,357	)	(680	)	(576	)
- capitalized direct costs associated with self-constructed assets - intangible assets	(138	)	(89	)	(53	)
	58,133		76,350		58,351

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Production costs-services included brokerage fees related to Engineering & Construction segment in the amount of euro 79 million (euro 37 million and euro 155 million for the years ended December 31, 2007 and 2008, respectively).
Costs incurred in connection with research and development activity recognized in the profit and loss account amounted to euro 207 million (euro 189 million and euro 216 million for the years ended December 31, 2007 and 2008, respectively) as they do not meet the requirements to be capitalized.
The item "Operating leases and other" included operating leases in the amount of euro 1,220 million (euro 1,081 million and euro 957 million for the years ended December 31, 2007 and 2008, respectively) and royalties on hydrocarbons extracted in the amount of euro 641 million (euro 772 million and euro 871 million for the years ended December 31, 2007 and 2008, respectively). Future minimum lease payments expected to be paid under non-cancelable operating leases were as follows:

(euro million) 2007 2008 2009

To be paid within 1 year	588	618	886
Between 2 and 5 years	1,401	2,585	2,335
Beyond 5 years	942	1,084	1,034
	2,931	4,287	4,255

Operating leases primarily relate to assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of Eni to pay dividends, use assets or to take on new borrowings
Increase of provisions for contingencies net of reversal of unutilized provisions amounted to euro 1,055 million (euro 573 million and euro 884 million for the years ended December 31, 2007 and 2008, respectively) and mainly related to legal or other proceedings in the amount of euro 333 million (euro 79 million and euro 55 million for the years ended December 31, 2007 and 2008, respectively) and environmental risks in the amount of euro 258 million (euro 327 million and euro 360 million for the years ended December 31, 2007 and 2008, respectively). More information is included in Note 21 – Provisions for contingencies.

Payroll and related costs
Payroll and related costs were as follows:

(euro million) 2007 2008 2009

Wages and salaries	2,906		3,204		3,330
Social security contributions	690		694		706
Cost related to defined benefits plans and defined contributions plans	161		107		137
Other costs	275		282		342
	4,032		4,287		4,515
less:
- capitalized direct costs associated with self-constructed assets - tangible assets	(184	)	(235	)	(280	)
- capitalized direct costs associated with self-constructed assets - intangible assets	(48	)	(48	)	(54	)
	3,800		4,004		4,181

Average number of employees
The average number and break-down of employees by category of Eni’s subsidiaries were as follows:

(number) 2007 2008 2009

Senior managers	1,594	1,621	1,653
Junior managers	11,816	12,597	13,255
Employees	35,725	36,766	37,207
Workers	25,582	26,387	26,533
	74,717	77,371	78,648

The average number of employees was calculated as the average between the number of employees at the beginning and end of the respective period. The average number of senior managers includes managers employed and operating in foreign countries, whose position is comparable to that of a senior manager.

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Stock-based compensation

STOCK OPTION
In 2009, Eni suspended the incentive plan based on the stock option assignment to managers of Eni and its subsidiaries as defined in Article 2359. The following is the information about the residual plans of past periods.

As of December 31, 2009 19,482,330 options were outstanding for the purchase of 19,482,330 Eni ordinary shares (nominal value euro 1 each). The break-down of outstanding options are as followings:

Rights outstanding
as of Dec. 31, 2009 Average strike price (euro)

Stock option plan 2002	97,000	15.216
Stock option plan 2003	229,900	13.743
Stock option plan 2004	671,600	16.576
Stock option plan 2005	3,281,500	22.512
Stock option plan 2006	3,018,155	23.119
Stock option plan 2007	5,144,050	27.451
Stock option plan 2008	7,040,125	22.540
	19,482,330

As of December 31, 2009 the weighted-average remaining contractual life of the 2002, 2003, 2004, 2005, 2006, 2007 and 2008 plans were 7 months, 1 year and 7 months, 2 years and 7 months, 3 years and 7 months, 2 years and 7 months, 3 years and 7 months and 4 years and 7 months, respectively.
The 2006-2008 stock option plans have introduced a performance condition for the exercise of the options. At the end of each three-year period (vesting period) from the assignment, the Board of Directors determines the percentage of exercisable options, from 0 to 100, in relation to the Total Shareholders’ Return (TSR) of Eni’s shares as benchmarked against the TSR delivered by a panel of the six largest international oil companies for market capitalization. Options can be exercised after three years from the assignment (vesting period) and for maximum period of three years. The strike price is calculated as an arithmetic average of official prices registered on the Mercato Telematico Azionario in the month preceding the assignment.
In 2009, changes of stock option plans consisted of the carry-over of the previous plans. The following table summarizes these changes:

2007 2008 2009

Number
of shares Average strike price (euro) Market price ^(a) (euro) Number
of shares Average strike price (euro) Market price ^(a) (euro) Number
of shares Average strike price (euro) Market price ^(a) (euro)

Rights outstanding as of January 1	15,290,400		21.022	25.520	17,699,625		23.822	25.120	23,557,425		23.540	16.556
New rights granted	6,128,500		27.451	27.447	7,415,000		22.540	22.538
Rights exercised in the period	(3,028,200	)	16.906	25.338	(582,100	)	17.054	24.328	(2,000	)	13.743	16.207
Rights cancelled in the period	(691,075	)	24.346	24.790	(975,100	)	24.931	19.942	(4,073,095	)	13.374	14.866
Rights outstanding as of December 31	17,699,625		23.822	25.120	23,557,425		23.540	16.556	19,482,330		23.576	17.811
of which exercisable at December 31	2,292,125		18.440	25.120	5,184,250		21.263	16.556	7,298,155		21.843	17.811

(a) Market price relating to new rights granted, rights exercised in the period and rights cancelled in the period corresponds to the average market value (arithmetic average of official prices recorded on Mercato Telematico Azionario in the month preceding: (i) the date of the Board of Directors resolution regarding the stock grant assignment; (ii) the date on which the emission/transfer of the shares granted were recorded in the grantee’s securities account; and (iii) the date of the unilateral termination of employment for rights cancelled), weighted with the number of shares. Market price of stock at the beginning and end of the year is the price recorded at December 31.

The fair value of stock options granted during the years 2002, 2003, 2004 and 2005 was euro 5.39, euro 1.50, euro 2.01 and euro 3.33 per share, respectively. For 2006, 2007 and 2008 the weighted average considering options granted was euro 2.89, euro 2.98 and euro 2.60 per share, respectively.

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The fair value was determined by applying the following assumptions:

2002 2003 2004 2005 2006 2007 2008

Risk-free interest rate	(%)	3.5	3.2	3.2	2.5	4.0	4.7	4.9
Expected life	(years)	8	8	8	8	6	6	6
Expected volatility	(%)	43.0	22.0	19.0	21.0	16.8	16.3	19.2
Expected dividends	(%)	4.5	5.4	4.5	4.0	5.3	4.9	6.1

Costs of the year related to stock option plans amounted to euro 12 million (euro 27 million and euro 25 million for the years ended December 31, 2007 and 2008, respectively).

Compensation of key management
Compensation of persons responsible for key positions in planning, direction and control functions of Eni Group, including executive and non-executive officers, general managers and managers with strategic responsibility (key management) in office for the years ended December 31, 2007, 2008 and 2009 amounted to euro 25 million, euro 25 million and euro 35 million, respectively, and consisted of the following:

(euro million) 2007 2008 2009 ^(*)

Wages and salaries	17	17	20
Post-employment benefits	1	1	1
Other long-term benefits	3	3	10
Stock grant/option	4	4	4
	25	25	35

(*) Comparing with the previous years, the increase is attributable to a different composition of key managers and to the introduction, as substitution of stock options, of deferred bonus. The fair value of such bonus is recognized in the year while the fair value of stock options was recognized pro-quota along the duration of the plan.

Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to euro 8.9 million, euro 6.4 million and euro 9.9 million for the years ended December 31, 2007, 2008 and 2009, respectively. Compensation of Statutory Auditors amounted to euro 0.678 million, euro 0.634 million and euro 0.475 million for the years ended December 31, 2007, 2008 and 2009, respectively.
Compensation included emoluments and all other retributive and social security compensations due for the function of directors or statutory auditor assumed by Eni SpA or other companies included in the scope of consolidation, representing a cost for Eni.

Other operating income (loss)
Other operating income (loss) related to the recognition in the profit and loss account the effects related to the valuation of fair value, including the effects deriving from the settlement, of those derivatives on commodities which cannot be recognized according to the hedge accounting under IFRS. Net gain on commodity derivatives in the amount of euro 55 million (euro 129 million and euro 124 million for the years ended December 31, 2007 and 2008, respectively) included euro 6 million related to the ineffective portion of the negative change in the fair value of cash flow hedging derivatives (time value component) entered into by the Exploration & Production segment (a loss of euro 52 million and a gain of euro 7 million for the years ended December 31, 2007 and 2008, respectively).

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Depreciation, depletion, amortization and impairments
Depreciation, depletion, amortization and impairments charges consisted of the following:

(euro million) 2007 2008 2009

Depreciation, depletion and amortization:
- tangible assets	5,031		6,103		6,779
- intangible assets	2,000		2,327		1,989
	7,031		8,430		8,768
Impairments:
- tangible assets	145		1,343		990
- intangible assets	62		53		62
	207		1,396		1,052
less:
- reversal of impairments - tangible assets			(2	)	(1	)
- reversal of impairment - intangible assets			(1	)
- capitalized direct costs associated with self-constructed assets - tangible assets	(2	)	(6	)	(4	)
- capitalized direct costs associated with self-constructed assets - intangible assets			(2	)	(2	)
	7,236		9,815		9,813

31 Finance income (expense)
Finance income (expense) consisted of the following:

(euro million) 2007 2008 2009

Finance income (expense)
Finance income	4,445		7,985		5,950
Finance expense	(4,554	)	(8,198	)	(6,497	)
	(109	)	(213	)	(547	)
Gain (loss) on derivative financial instruments	155		(427	)	(4	)
	46		(640	)	(551	)

Net finance income (expense) consisted of the following:

(euro million) 2007 2008 2009

Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds	(258	)	(248	)	(423	)
Interest due to banks and other financial institutions	(445	)	(745	)	(330	)
Interest from banks	236		87		33
Interest and other income on financing receivables and securities held for non-operating purposes	55		82		47
	(412	)	(824	)	(673	)
Exchange differences
Positive exchange differences	2,877		7,339		5,572
Negative exchange differences	(2,928	)	(7,133	)	(5,678	)
	(51	)	206		(106	)
Other finance income (expense)
Capitalized finance expense	180		236		223
Income from equity instruments	188		241		163
Interest and other income on financing receivables and securities held for operating purposes	96		62		39
Interest on tax credits	31		37		4
Finance expense due to passage of time (accretion discount) (a)	(186	)	(249	)	(218	)
Other finance income	45		78		21
	354		405		232
	(109	)	(213	)	(547	)

(a) The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.

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Income from equity instruments in the amount of euro 163 million (euro 188 million and euro 241 million for the years ended December 31, 2007 and 2008, respectively) related to the contractual remuneration of 9.4% on the 20% interest in OAO Gazprom Neft according to the contractual arrangements between Eni and Gazprom. Income has been recognized up to the date of the payment from Gazprom of the strike price on the call option, including the recovery of any additional costs, on April 24, 2009 (more information is included in Note 2 – Other financial assets held for trading or available for sale).
The fair value gain (loss) on derivative financial instruments consisted of the following:

(euro million) 2007 2008 2009

Derivatives on exchange rate	120	(300	)	40
Derivatives on interest rate	35	(127	)	(52	)
Derivatives on commodities				8
	155	(427	)	(4	)

Net loss from derivatives in the amount of euro 4 million (euro 155 million of net gain for the years ended December 31, 2007 and euro 427 million of net loss for the years ended December 31, 2008) was primarily due to the recognition in the profit and loss account of the change in the fair value of those derivatives which cannot be recognized according to the hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. The lack of these formal requirements to qualify these derivatives as hedging instruments under IFRS also included the recognition in the profit and loss account the negative impact from currency translation differences on assets and liabilities denominated in currencies other than the functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.

32 Income (expense) from investments

Share of profit (loss) of equity-accounted investments
Share of profit (loss) of equity-accounted investments consisted of the following:

(euro million) 2007 2008 2009

Share of profit of equity-accounted investments	906		761		693
Share of loss of equity-accounted investments	(135	)	(105	)	(241	)
Decreases (increases) in the provision for losses on investments	2		(16	)	(59	)
	773		640		393

More information is provided in Note 11 – Investments.

Other gain (loss) from investments
Other gain (loss) from investments consisted of the following:

(euro million) 2007 2008 2009

Dividends	170		510		164
Gains on disposals	301		218		16
Losses on disposals	(1	)	(1	)
Other income (expense), net			6		(4	)
	470		733		176

Dividends in the amount of euro 164 million mainly relate to Nigeria LNG (euro 101 million).
Gains on disposals in 2009 amounted to euro 16 million and primarily related to a price revision for the sale of Gaztransport et Technigaz SAS (euro 10 million), which occurred in 2008. Gains on disposals in 2008 amounted to euro 218 million and primarily for the sale of Gaztransport et Technigaz SAS (euro 185 million), Agip España SA (euro 15 million) and Padana Assicurazioni SpA (euro 10 million). Gains on disposals in 2007 amounted to euro 301 million and primarily related to the sale of Haldor Topsøe AS (euro 265 million) and Camom SA (euro 25 million).

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33 Income tax expense
Income tax expense consisted of the following:

(euro million) 2007 2008 2009

Current taxes:
- Italian subsidiaries	2,380		1,916		1,724
- foreign subsidiaries of the Exploration & Production segment	6,695		9,744		5,989
- foreign subsidiaries	482		426		483
	9,557		12,086		8,196
Net deferred taxes:
- Italian subsidiaries	(582	)	(1,603	)	(534	)
- foreign subsidiaries of the Exploration & Production segment	246		(827	)	(733	)
- foreign subsidiaries	(2	)	36		(173	)
	(338	)	(2,394	)	(1,440	)
	9,219		9,692		6,756

Current income taxes in the amount of euro 1,724 million consist of IRES (euro 1,485 million) and IRAP (euro 219 million) for Italian subsidiaries and foreign taxes (euro 20 million).
The effective tax rate was 56.0% (46.0% and 50.3% for the years ended December 31, 2007 and 2008, respectively) compared with a statutory tax rate of 40.1% (37.9% and 38.2% for the years ended December 31, 2007 and 2008, respectively) and calculated by applying a 34.0%¹⁸ tax rate (IRES) to profit before income taxes and 3.9% tax rate (IRAP) to the net value of production as provided for by Italian laws.

The difference between the statutory and effective tax rate was due to the following factors:

(%) 2007 2008 2009

Statutory tax rate	37.9		38.2		40.1
Items increasing (decreasing) statutory tax rate:
- higher foreign subsidiaries tax rate	10.2		15.2		13.3
- changes in Italian statutory tax rate and adjustment of tax base of amortizable assets for Italian subsidiaries	(2.0	)
- impact pursuant to Law Decree No. 112 of June 25, 2008, the Budget Law 2008 and enactment of a renewed tax framework in Libya			(3.8	)	2.4
- permanent differences and other adjustments	(0,1	)	0.7		0.2
	8.1		12.1		15.9
	46.0		50.3		56.0

The increase in the tax rate of foreign subsidiaries primarily related to a 16.1 percentage points increase in the Exploration & Production segment (15.0% and 17.1% for the years ended December 31, 2007 and 2008, respectively).
The impact pursuant to Law Decree No. 112 of June 25, 2008, the Budget Law 2008 and enactment of a renewed tax framework in Libya consisted of the following: in the 2009 (i) the equalization in Libya of the 2008 income taxes in the amount of euro 230 million following adjustments to the valorization criteria of revenues; (ii) a reduced deductibility in Italy of the cost of goods sold following the reduction in the gas volumes of inventories in the amount of euro 64 million; in the 2008 (iii) the utilization of deferred tax liabilities recognized on higher carrying amounts of year-end inventories of oil, gas and refined products stated at the weighted-average cost with respect to their tax base according to the last-in-first-out method (LIFO) (euro 528 million). In fact, pursuant to the Law Decree No. 112 of June 25, 2008 (become Law No. 133/2008), energy companies in Italy were required from 2008 to state inventories of hydrocarbons at the weighted-average cost for tax purposes as opposed to the previous LIFO evaluation and to recognize a one-off tax calculated by applying a special tax with a 16% rate on the difference between the two amounts. Accordingly, the profit and loss account benefited from the difference between utilization of deferred tax liabilities accrued on hydrocarbons inventories and the one-off tax (euro 229 million), for a total positive impact of euro 176 million, which consider previously applicable statutory tax rate (Ires) of 33% pursuant to the Law Decree No. 112 of June 25, 2008 instead of 27.5% of the previous tax regime. This one-off tax will be paid in three annual installments of same amount, due from

(18) Includes a 5.5% supplemental tax rate on taxable profit of energy companies in Italy (whose primary activity is the production and marketing of hydrocarbons and electricity and with annual revenues in excess of euro 25 million) effective from January 1, 2008 and a further 1% increase effective from January 1, 2009, pursuant to the Law Decree No. 112 of June 25, 2008.

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2009 onwards; (iv) application of the Italian Budget Law for 2008 that provide an increase in limits whereby carrying amounts of assets and liabilities of consolidated subsidiaries can be recognized for tax purposes by paying a one-off tax calculated by applying a special rate of 6% (positive impact on the profit and loss account in the amount of euro 370 million; euro 290 million net of the special tax); (v) enactment of a renewed tax framework in Libya regarding oil companies operating in accordance with production sharing schemes. Based on the new provisions, the tax base of the Company’s Libyan oil properties has been reassessed resulting in the partial utilization of previously accrued tax liabilities in the amount of euro 173 million; (vi) the impact of above mentioned Law Decree No. 112/2008 on energy companies calculated by applying statutory tax rate (Ires) of 33% pursuant to the Law Decree No. 112/2008 instead of the previously applicable statutory tax rate (Ires) of 27.5% (euro 94 million).
The adjustment to deferred tax assets and liabilities and to the 2007 tax rate for Italian subsidiaries were recognized in connection with certain amendments to the Italian tax regime enacted by the 2008 Budget Law and the subsequent modification introduced by the Law Decree No. 112/2008. These included an option regarding the increase of the tax bases of certain tangible and other assets to their carrying amounts (euro 773 million) by paying a special tax (euro 325 million) and a lower statutory tax rate (Ires from 33% to 27.5%, Irap from 4.25% to 3.9%, euro 54 million).
In 2009, permanent differences and other adjustments for 0.2 percentage points included: (i) as an increase, a non-recurring item represented by a charge amounting to euro 250 million that was estimated on the base of the management’s best knowledge of the possible resolution of the TSKJ matter with US Authorities. More information is provided in Note 28 – Guarantees, commitments and risks; (ii) as a decrease, deferred tax assets accounted for following an adjustment of the fiscal value to the carrying amount of oil & gas properties related to a reorganization of the Italian activities by paying a special tax and the partial deductibility of Irap of income taxes from previous years (euro 222 million).


34 Earnings per share
Basic earnings per ordinary share are calculated by dividing net profit for the year attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the year, excluding treasury shares.
The average number of ordinary shares used for the calculation of the basic earnings per share outstanding as of December 31, 2007, 2008 and 2009, was 3,668,305,807, 3,638,835,896 and 3,622,405,852 respectively.
Diluted earnings per share is calculated by dividing net profit for the year attributable to Eni’s shareholders by the weighted average number of fully-diluted shares which includes issued and outstanding shares during the year, excluding treasury shares and including the number of shares that could potentially be issued in connection with stock-based compensation plans.
As of December 31, 2008 and 2009, the number of shares that could potentially be issued were related to stock options plans.
As of December 31, 2007, the number of shares that could potentially be issued were related to stock options and stock grant plans.
The average number of shares fully diluted used in the calculation of diluted earnings was 3,669,172,762, 3,638,854,276 and 3,622,438,937 for the years ended December 31, 2007, 2008 and 2009, respectively.
Reconciliation of the average number of shares used for the calculation for both basic and diluted earning per share was as follows:

2007 2008 2009

Average number of shares used for the calculation of the basic earnings per share		3,668,305,807	3,638,835,896	3,622,405,852
Number of potential shares following stock grant plans		302,092
Number of potential shares following stock options plans		564,863	18,380	33,085
Average number of shares used for the calculation of the diluted earnings per share		3,669,172,762	3,638,854,276	3,622,438,937
Eni’s net profit	(euro million)	10,011	8,825	4,367
Basic earning per share	(euro per share)	2.73	2.43	1.21
Diluted earning per share	(euro per share)	2.73	2.43	1.21

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35 Information by industry segment and geographic financial information

Information by industry segment

(euro million) Exploration & Production Gas & Power Refining & Marketing Petrochemicals Engineering & Construction Other activities Corporate and financial companies Intra-group profits Total

2007
Net sales from operations (a)	26,920		27,793		36,349		6,934		8,678		205		1,313
Less: intersegment sales	(16,280	)	(757	)	(1,276	)	(363	)	(1,182	)	(31	)	(1,099	)
Net sales to customers	10,640		27,036		35,073		6,571		7,496		174		214				87,204
Operating profit	13,433		4,465		686		100		837		(444	)	(312	)	(26	)	18,739
Provisions for contingencies	7		35		238		15		11		264		3				573
Depreciation, amortization and writedowns	5,574		739		491		116		248		10		68		(10	)	7,236
Share of profit (loss) of equity-accounted investments	23		449		216				79		6						773
Identifiable assets (b)	32,382		25,583		13,767		3,427		8,017		275		854		(692	)	83,613
Unallocated assets																	17,847
Equity-accounted investments	1,926		2,152		1,267		15		230		49						5,639
Identifiable liabilities (c)	10,955		5,915		5,420		939		4,349		1,827		1,380				30,785
Unallocated liabilities																	27,808
Capital expenditures	6,480		1,511		979		145		1,410		59		108		(99	)	10,593
2008
Net sales from operations (a)	33,042		37,062		45,017		6,303		9,176		185		1,331		75
Less: intersegment sales	(18,917	)	(873	)	(1,496	)	(398	)	(1,219	)	(29	)	(1,177	)
Net sales to customers	14,125		36,189		43,521		5,905		7,957		156		154		75		108,082
Operating profit	16,239		4,030		(988	)	(845	)	1,045		(346	)	(743	)	125		18,517
Provisions for contingencies	154		238		190		2		36		99		165				884
Depreciation, amortization and writedowns	7,488		798		729		395		335		8		76		(14	)	9,815
Share of profit (loss) of equity-accounted investments	173		413		16		(9	)	43		4						640
Identifiable assets (b)	40,815		33,151		11,081		2,629		10,630		362		789		(641	)	98,816
Unallocated assets																	17,857
Equity-accounted investments	1,787		2,249		1,227		25		130		53						5,471
Identifiable liabilities (c)	10,481		11,802		4,481		664		6,177		1,638		1,780		(75	)	36,948
Unallocated liabilities																	31,215
Capital expenditures	9,281		2,058		965		212		2,027		52		95		(128	)	14,562
2009
Net sales from operations (a)	23,801		30,447		31,769		4,203		9,664		88		1,280		(66	)
Less: intersegment sales	(13,630	)	(635	)	(965	)	(238	)	(1,315	)	(24	)	(1,152	)
Net sales to customers	10,171		29,812		30,804		3,965		8,349		64		128		(66	)	83,227
Operating profit	9,120		3,687		(102	)	(675	)	881		(382	)	(474	)			12,055
Provisions for contingencies	(2	)	277		154		1		311		139		175				1,055
Depreciation, amortization and writedowns	7,365		981		754		204		435		8		83		(17	)	9,813
Share of profit (loss) of equity-accounted investments	142		310		(70	)			50		(39	)					393
Identifiable assets (b)	42,729		32,135		12,244		2,583		11,611		355		1,031		(553	)	102,135
Unallocated assets																	15,394
Equity-accounted investments	1,989		2,044		1,494		37		213		51						5,828
Identifiable liabilities (c)	10,918		9,161		4,684		742		5,967		1,639		1,690		(8	)	34,793
Unallocated liabilities																	32,685
Capital expenditures	9,486		1,686		635		145		1,630		44		57		12		13,695

(a)	Before elimination of intersegment sales.
(b)	Includes assets directly associated with the generation of operating profit.
(c)	Includes liabilities directly associated with the generation of operating profit.

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Intersegment revenues are conducted on an arm’s length basis.

Geographic financial information
IDENTIFIABLE ASSETS AND INVESTMENTS BY GEOGRAPHIC AREA OF ORIGIN

(euro million) Italy Other European Union Rest of Europe America Asia Africa Other areas Total

2007
Identifiable assets (a)	39,742	11,071	3,917	6,260	6,733	15,368	522	83,613
Capital expenditures	3,246	1,246	469	1,004	1,253	3,152	223	10,593
2008
Identifiable assets (a)	40,432	15,071	3,561	6,224	10,563	22,044	921	98,816
Capital expenditures	3,674	1,660	582	1,240	1,777	5,153	476	14,562
2009
Identifiable assets (a)	40,861	15,571	3,520	6,337	11,187	23,397	1,262	102,135
Capital expenditures	3,198	1,454	574	1,207	2,033	4,645	584	13,695

(a) Includes assets directly related to the generation of operating profit.

SALES FROM OPERATIONS BY GEOGRAPHIC AREA OF DESTINATION

(euro million) 2007 2008 2009

Italy	37,294	42,843	27,950
Other European Union	23,074	29,341	24,331
Rest of Europe	5,507	7,125	5,213
America	6,447	7,218	7,080
Asia	5,840	8,916	8,208
Africa	8,010	12,331	10,174
Other areas	1,032	308	271
	87,204	108,082	83,227

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36 Transactions with related parties
In the ordinary course of business, Eni enters into transactions relating to:

a)	the exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries;
b)	the exchange of goods and provision of services with entities directly and indirectly owned or controlled by the Government;
c)	transactions with Cosmi Holding Group, which is related to Eni through a member of the Board of Directors, for certain acquisition of engineering, construction and maintenance services. Relevant transactions which were executed at an arm’s length basis amounted to approximately euro 18 million, euro 13 million and euro 21 million in 2007, 2008 and 2009, respectively. As of December 31, 2009, there were outstanding receivables in the amount of euro 4 million and payables in the amount of euro 9 million (euro 4 million and euro 8 million as of December 31, 2008, respectively);
d)	contributions to entities, controlled by Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment as well as research and development. Transactions with Eni Foundation related to contributions for the year ended December 31, 2008 in the amount of euro 200 million to the solidarity fund pursuant to Italian Law Decree No. 112/2008 and the payable as of December 31, 2008 and 2009 in the amount of euro 100 million related to the portion of the contribution that had not yet been paid. Transactions in the periods preceding 2008 were not material; (ii) Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Transactions with Enrico Mattei Foundation were not material.

Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities with the aim to develop solidarity, culture and research initiatives, at an arm’s length basis.

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Trade and other transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities directly and indirectly owned or controlled by the Government in the years ended December 31, 2007, 2008 and 2009, respectively, consisted of the following:

(euro million) Dec. 31, 2007 2007

Costs Revenues

Name Receivables and other assets Payables and other liabilities Guarantees Goods Services Goods Services Other operating (charge) income

Joint ventures and associates
ASG Scarl	6	43	121		108		3
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH	11					86
Blue Stream Pipeline Co BV	19				183		1
Bronberger & Kessler und Gilg & Schweiger GmbH	18					106
CEPAV (Consorzio Eni per l'Alta Velocità) Uno	84	70	5,870				263
CEPAV (Consorzio Eni per l'Alta Velocità) Due	1	1	64		1		1
Eni Oil Co Ltd	7	60			141	1
Fox Energy SpA	49					139
Gasversorgung Süddeutschland GmbH	54					195	4
Gruppo Distribuzione Petroli Srl	26					50
Karachaganak Petroleum Operating BV	43	102		24	301		7
Mellitah Oil & Gas BV	10	137			105	1	6
OOO "EniNeftegaz"	215						1
Petrobel Belayim Petroleum Co		60			211
Raffineria di Milazzo ScpA	17	21			245	118	5
Supermetanol CA		11		78			1
Super Octanos CA		18		201			1
Trans Austria Gasleitung GmbH	6	80		43	147		47
Transitgas AG		8			64
Transmediterranean Pipeline Co Ltd		6			70		1
Unión Fenosa Gas SA	1		61			193
Other (*)	120	127	56	76	374	122	118
	687	744	6,172	422	1,950	1,011	459
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV	49	111		11	534		52
Eni BTC Ltd			138				1
Other (*)	23	8	11	2	18	5	18
	72	119	149	13	552	5	71
	759	863	6,321	435	2,502	1,016	530
Entities owned or controlled by the Government
Gruppo Alitalia	4					363	1
Gruppo Enel	384	8			245	894	408
GSE - Gestore Servizi Elettrici	124	63		239	37	870	7	10
Terna SpA	19	69		106	105		31
Other (*)	45	79		19	89	75	3
	576	219		364	476	2,202	450	10
	1,335	1,082	6,321	799	2,978	3,218	980	10

(*) Each individual amount included herein does not exceed euro 50 million.

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(euro million) Dec. 31, 2008 2008

Costs Revenues

Name Receivables and other assets Payables and other liabilities Guarantees Goods Services Other Goods Services Other Other operating (charge) income

Joint ventures and associates
Agiba Petroleum Co		11			60
Altergaz SA	30						135
ASG Scarl	2	25	49		57
Bayernoil Raffineriegesellschaft mbH	3	4	1	6	62		4
Bernhard Rosa Inh. Ingeborg Plöchinger GmbH	5						98
Blue Stream Pipeline Co BV	23	17			171			1
Bronberger & Kessler und Gilg & Schweiger GmbH	12						175
CEPAV (Consorzio Eni per l'Alta Velocità) Uno	95	37	6,001		17	3		397
CEPAV (Consorzio Eni per l'Alta Velocità) Due	4	1	64		1			1
Eni Oil Co Ltd	9	28			660			6
Fox Energy SpA	37			2			329	1
FPSO Mystras - Produção de Petròleo Lda				94		10
Gasversorgung Süddeutschland GmbH	64						337	18
Gruppo Distribuzione Petroli Srl	20						111
InAgip doo	24	45			116		3	35
Karachaganak Petroleum Operating BV	72	207		874	380	25		12
Mellitah Oil & Gas BV	10	121			329		2	4
Petrobel Belayim Petroleum Co		77			181
Raffineria di Milazzo ScpA	11	4			276		135	3
Saipon Snc	4		58					12
Super Octanos CA		24		286
Supermetanol CA		5		90
Trans Austria Gasleitung GmbH	8	78		60	153			64
Transitgas AG		5			1	64
Unión Fenosa Gas SA	1	25	62	25			257	1
Other (*)	231	115	18	36	319	46	71	129	8
	665	829	6,253	1,473	2,783	148	1,657	684	8
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV	144	166			720	11	1	367	10
Eni BTC Ltd			146
Other (*)	22	18	4	2	20	2	4	6	4
	166	184	150	2	740	13	5	373	14
	831	1,013	6,403	1,475	3,523	161	1,662	1,057	22
Entities owned or controlled by the Government
Gruppo Alitalia	4						417	2
Gruppo Enel	153	12		13	223		941	380
Gruppo Ferrovie dello Stato	19	7			27	1	57
GSE - Gestore Servizi Elettrici	92	63		315		79	347	16	6	58
Terna SpA	33	35		14	128		12	83	10
Other (*)	28	72		33	88	5	72	2	1
	329	189		375	466	85	1,846	483	17	58
	1,160	1,202	6,403	1,850	3,989	246	3,508	1,540	39	58

(*) Each individual amount included herein does not exceed euro 50 million.

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(euro million) Dec. 31, 2009 2009

Costs Revenues

Name Receivables and other assets Payables and other liabilities Guarantees Goods Services Other Goods Services Other Other operating (charge) income

Joint ventures and associates
Agiba Petroleum Co		5			64
Altergaz SA	50						142
ASG Scarl		10	54		25
Azienda Energia e Servizi Torino SpA	1	30			62			1
Bayernoil Raffineriegesellschaft mbH		31	1	15	77		2
Blue Stream Pipeline Co BV	17	15	34		163
Bronberger & Kessler und Gilg & Schweiger GmbH	16						95
CEPAV (Consorzio Eni per l'Alta Velocità) Uno	38	12	6,037		5			84
CEPAV (Consorzio Eni per l'Alta Velocità) Due	6	1	76		1			2
Fox Energy SpA	44			1			241
Gasversorgung Süddeutschland GmbH	17						196	8
Gruppo Distribuzione Petroli Srl	15						71
InAgip doo	44	23			86			71
Karachaganak Petroleum Operating BV	61	196		588	344	27	9	10
Kwanda Suporto Logistico Lda	72							20
Mellitah Oil & Gas BV	30	190			306		2	31
Petrobel Belayim Petroleum Co	4	12			205			4	2
Raffineria di Milazzo ScpA	14	8			242		98	5
Saipon Snc	8	2	61					45
Super Octanos CA		24		133
Trans Austria Gasleitung GmbH	4	71		36	157			40
Transitgas AG					1	61
Unión Fenosa Gas SA	8		62	12			53		1
Other (*)	143	58	15	62	188	41	117	125	10
	592	688	6,340	847	1,926	129	1,026	446	13
Unconsolidated entities controlled by Eni
Agip Kazakhstan North Caspian Operating Co NV	194	224		1	914	7	15	466	7
Eni BTC Ltd			141					1
Other (*)	29	23	4	1	52	4	14	6	1
	223	247	145	2	966	11	29	473	8
	815	935	6,485	849	2,892	140	1,055	919	21
Entities owned or controlled by the Government
Gruppo Enel	96	32		9	286	77	342	428	1
Gruppo Finmeccanica	33	37		16	56		21	7
GSE - Gestore Servizi Elettrici	83	74		373		79	342	15		19
Terna SpA	7	37		52	52	19	7	86	4	25
Other (*)	78	71		1	71	6	62	16
	297	251		451	465	181	774	552	5	44
	1,112	1,186	6,485	1,300	3,357	321	1,829	1,471	26	44

(*) Each individual amount included herein does not exceed euro 50 million.

272

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The most significant transactions with joint ventures, associates and non-consolidated subsidiaries consisted of the following:

- transactions related to the planning and the construction of the tracks for high speed/high capacity trains from Milan to Bologna with ASG Scarl, CEPAV (Consorzio Eni per l’Alta Velocità) Uno, and related guarantees;

- transportation and distribution activity with Azienda Energia e Servizi Torino SpA;

- acquisition of refining services from Bayernoil Raffineriegesellschaft mbH and Raffineria di Milazzo ScpA in relation to incurred costs;

- supply of oil products to Bronberger & Kessler und Gilg & Schweiger GmbH, Fox Energy SpA, Gruppo Distribuzione Petroli Srl and Raffineria di Milazzo ScpA on the basis of prices related to the quotations on international markets of the main oil products, as they would be conducted at an arm’s length basis;

- acquisition of natural gas transport services outside Italy from Blue Stream Pipeline Co BV, Trans Austria Gasleitung GmbH and Transitgas AG and the issuing of guarantees on behalf of Blue Stream Pipeline Co BV;

- guarantees issued on behalf of CEPAV (Consorzio Eni per l’Alta Velocità) Due and Saipon Snc in relation to contractual commitments related to the execution of project planning and realization;

- provision of specialized services in upstream activities and payables for investment activities from Agip Kazakhstan North Caspian Operating Co NV, Agiba Petroleum Co, InAgip doo, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co and, only for Karachaganak Petroleum Operating BV supply of oil products; services are invoiced on the basis of costs incurred;

- logistic support by Kwanda Suporto Logistico Lda;

- sale of natural gas to Altergaz SA and Gasversorgung Süddeutschland GmbH;

- acquisition of petrochemical products from Super Octanos CA on the basis of prices related to the quotations on international markets of the main products;

- performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations;

- guarantees issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd.

The most significant transactions with entities owned or controlled by the Government consisted of the following:

- sale and transportation of natural gas, the sale of fuel oil and the sale and purchase of electricity and the acquisition of electricity transmission service with Enel;

- a long term contract for the maintenance of the newly combined cycle power plants with Gruppo Finmeccanica;

- sale and purchase of electricity, green certificates and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with GSE - Gestore Servizi Elettrici;

- sale and purchase of electricity, the acquisition of domestic electricity transmission service and the fair value of derivative financial instruments included in prices of electricity related to sale/purchase transactions with Terna SpA.

Financing transactions with joint ventures, associates and non-consolidated subsidiaries as well as with entities directly and indirectly owned or controlled by the Government for the years ended December 31, 2007, 2008 and 2009, respectively, consisted of the following:

(euro million) Dec. 31, 2007 2007

Name Receivables Payables Guarantees Charges Gains

Joint ventures and associates
Blue Stream Pipeline Co BV		1	711		20
Raffineria di Milazzo ScpA			60
Trans Austria Gasleitung GmbH	65				3
Transmediterranean Pipeline Co Ltd	97				9
Other (*)	108	120	52	19	11
	270	121	823	19	43
Unconsolidated entities controlled by Eni
Other (*)	114	26	1	1	6
	114	26	1	1	6
	384	147	824	20	49

(*) Each individual amount included herein does not exceed euro 50 million.

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(euro million) Dec. 31, 2008 2008

Name Receivables Payables Guarantees Charges Gains

Joint ventures and associates
Bayernoil Raffineriegesellschaft mbH	131
Blue Stream Pipeline Co BV			752		14
PetroSucre SA	153
Raffineria di Milazzo ScpA			70
Trans Austria Gasleitung GmbH	186				7
Transmediterranean Pipeline Co Ltd	103				6
Other (*)	123	124	27	16	9
	696	124	849	16	36
Unconsolidated entities controlled by Eni
Other (*)	115	38	1	1	6
	115	38	1	1	6
	811	162	850	17	42

(*) Each individual amount included herein does not exceed euro 50 million.

(euro million) Dec. 31, 2009 2009

Name Receivables Payables Guarantees Charges Gains

Joint ventures and associates
Artic Russia BV	70	1	170		1
Bayernoil Raffineriegesellschaft mbH	133
Blue Stream Pipeline Co BV			692		12
Raffineria di Milazzo ScpA			85
Trans Austria Gasleitung GmbH	171				5
Transmediterranean Pipeline Co Ltd	149				3
Other (*)	125	112	24	2	3
	648	113	971	2	24
Unconsolidated entities controlled by Eni
Other (*)	78	34	1	2	3
	78	34	1	2	3
	726	147	972	4	27

(*) Each individual amount included herein does not exceed euro 50 million.

The most significant transactions with joint ventures, associates and non-consolidated subsidiaries consisted of the following:

- bank debt guarantee issued on behalf of Artic Russia BV, Blue Stream Pipeline Co BV and Raffineria di Milazzo ScpA, and, exclusively with Artic Russia BV, financing loans and cash deposit at Eni’s financial companies;

- financing loan to Bayernoil Raffineriegesellschaft mbH;

- financing of the Austrian section of the gasline from the Russian Federation to Italy and the construction of natural gas transmission facilities and transport services with Trans Austria Gasleitung GmbH and Transmediterranean Pipeline Co Ltd, respectively.

274

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows
The impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows consisted of the following:

Dec. 31, 2007 Dec. 31, 2008 Dec. 31, 2009

(euro million) Total Related parties Impact % Total Related parties Impact % Total Related parties Impact %

Trade and other receivables	20,676	1,616	7.82	22,222	1,539	6.93	20,348	1,355	6.66
Other current assets	790			1,870	59	3.16	1,307	9	0.69
Other non-current financial assets	923	87	9.43	1,134	356	31.39	1,148	438	38.15
Other non-current assets	1,400	16	1.14	1,881	21	1.12	1,938	40	2.06
Current financial liabilities	7,763	131	1.69	6,359	153	2.41	3,545	147	4.15
Trade and other payables	17,116	1,021	5.97	20,515	1,253	6.11	19,174	1,241	6.47
Other liabilities	1,523	4	0.26	3,863	4	0.10	1,856	5	0.27
Long-term debt and current portion of long-term debt	12,067	16	0.13	14,478	9	0.06	21,255
Other non-current liabilities	2,117	57	2.69	3,102	53	1.71	2,480	49	1.98

The impact of transactions with related parties on the profit and loss account consisted of the following:

2007 2008 2009

(euro million) Total Related parties Impact % Total Related parties Impact % Total Related parties Impact %

Net sales from operations	87,204		4,198		4.81	108,082		5,048		4.67	83,227		3,300		3.97
Other income and revenues	833				..	728		39		5.36	1,118		26		2.33
Purchases, services and other	58,133		3,777		6.50	76,350		6,298		8.25	58,351		4,999		8.57
Other operating income (expense)	(129	)	10		..	(124	)	58		..	55		44		80.00
Financial income	4,445		49		1.10	7,985		42		0.53	5,950		27		0.45
Financial expense	(4,554	)	(20	)	0.44	(8,198	)	(17	)	0.21	(6,497	)	(4	)	0.06

Transactions with related parties during the ordinary course of Eni’s business were mainly conducted at an arm’s length basis.
Main cash flows with related parties were as follows:

(euro million) 2007 2008 2009

Revenues and other income	4,198		5,087		3,326
Costs and other expenses	(3,777	)	(6,298	)	(4,999	)
Other operating income (loss)	10		58		44
Net change in trade and other receivables and liabilities	(492	)	351		34
Dividends and net interests	610		740		407
Net cash provided from operating activities	549		(62	)	(1,188	)
Capital expenditures in tangible and intangible assets	(779	)	(2,022	)	(1,364	)
Investments	8
Change in accounts payable in relation to investments	(8	)	27		19
Change in financial receivables	(43	)	397		83
Net cash used in investing activities	(822	)	(1,598	)	(1,262	)
Change in financial liabilities	20		14		(14	)
Net cash used in financing activities	20		14		(14	)
Total financial flows to related parties	(253	)	(1,646	)	(2,464	)

275

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The impact on the statement of cash flows with related parties consisted of the following:

2007 2008 2009

(euro million) Total Related parties Impact % Total Related parties Impact % Total Related parties Impact %

Cash provided from operating activities	15,517		549		3.54	21,801		(62	)	..	11,136		(1,188	)	..
Cash used in investing activities	(20,097	)	(822	)	4.09	(16,958	)	(1,598	)	9.42	(10,254	)	(1,262	)	12.31
Cash used in financing activities	2,909		20		0.69	(5,025	)	14		..	(1,183	)	(14	)	1.18

37 Significant non-recurring events and operations
Non-recurring income (charges) consisted of the following:

(euro million) 2007 2008 2009

Estimate of the charge from the possible resolution of the TSKJ matter				250
Curtailment of post-retirement benefits for Italian employees	83
Risk provisions for proceedings against Antitrust authorities	(130	)	21
Risk provisions for proceedings against the Italian Authority for Electricity and Gas	39
	(8	)	21	250

Estimate of the charge from the possible resolution of the TSKJ matter represents a charge in the amount of euro 250 million that was estimated based on management’s best knowledge of the possible resolution of the TSKJ matter with US Authorities. The matter is fully disclosed in Note 28 – Guarantees, commitments and risks – Legal Proceedings. The charge is recognized in the results of the Engineering & Construction segment as it relates to a project that was executed in Nigeria by the TSKJ joint venture. However, the charge will be incurred by Eni due to the contractual obligations assumed by Eni related to the indemnification of Saipem as part of the divestment of Snamprogetti. At the time of the project, the TSKJ venture was participated by Snamprogetti Netherlands BV which was controlled by Snamprogetti. As a result, the future monetary settlement of the provision will be incurred by Eni SpA and Saipem’s minorities will be left unaffected.
Non-recurring income consist of a gain resulting from the curtailment of the provisions accrued by Italian companies for employee termination indemnities ("TFR") following the changes introduced by Italian Budget Law for 2007 and related decrees (euro 83 million). Non-recurring charges for 2007 consist of risk provisions related to ongoing antitrust proceedings against the European Antitrust authorities (euro 130 million).


38 Positions or transactions deriving from atypical and/or unusual operations
There were no positions or transactions deriving from atypical and/or unusual operations for the years ended December 31, 2007, 2008 and 2009.

276

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Supplemental oil and gas information (unaudited)

The following information pursuant to "International Financial Reporting Standards" (IFRS) is presented in accordance with SFAB Extractive Activities – Oil & Gas (Topic 932). Amounts related to minority interests are not significant.

Capitalized costs

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. Capitalized costs by geographical area consist of the following:

(euro million) Italy Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾

December 31, 2008
Proved mineral interests	10,772		7,852		10,116		11,368		1,663		3,939		4,737		392		50,839		813
Unproved mineral interests	32		316		638		2,267		37		1,461		2,418		43		7,212		928
Support equipment and facilities	283		24		1,205		520		51		16		43		4		2,146		14
Incomplete wells and other	1,374		249		1,006		1,443		2,631		713		632		362		8,410		267
Gross Capitalized Costs	12,461		8,441		12,965		15,598		4,382		6,129		7,830		801		68,607		2,022
Accumulated depreciation, depletion and amortization	(7,943	)	(5,327	)	(6,318	)	(7,027	)	(560	)	(3,224	)	(3,638	)	(173	)	(34,210	)	(441	)
Net Capitalized Costs (a) (b)	4,518		3,114		6,647		8,571		3,822		2,905		4,192		628		34,397		1,581
December 31, 2009
Proved mineral interests	10,079		9,472		11,122		14,011		1,723		4,566		5,750		1,338		58,061		791
Unproved mineral interests	33		305		580		1,854		36		1,518		2,144		38		6,508		443
Support equipment and facilities	273		31		1,287		585		57		17		45		4		2,299		13
Incomplete wells and other	1,028		329		1,228		934		3,481		316		600		14		7,930		358
Gross Capitalized Costs	11,413		10,137		14,217		17,384		5,297		6,417		8,539		1,394		74,798		1,605
Accumulated depreciation, depletion and amortization	(7,557	)	(6,824	)	(7,044	)	(8,424	)	(620	)	(3,679	)	(4,673	)	(379	)	(39,200	)	(485	)
Net Capitalized Costs (a) (b) (c)	3,856		3,313		7,173		8,960		4,677		2,738		3,866		1,015		35,598		1,120

(1)	Eni's capitalized costs of the Kashagan field are determined based on Eni share of 16.81%.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)	The amounts include net capitalized financial charges totaling euro 537 million in 2008 and euro 570 million in 2009.
(b)	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 in euro 3,308 million in 2008 and euro 3,690 million in 2009 for the consolidated companies and of euro 48 million in 2008 and euro 76 million in 2009 for joint ventures affiliates.
(c)	Amounts of 2009 do not include the capitalized costs related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

277

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Cost incurred
Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following:

(euro million) Italy Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾

2007
Proved property acquisitions (b)			11	451			1,395		1,857	187
Unproved property acquisitions (b)				510			1,417		1,927	1,086
Exploration (b)	104	195	373	305	36	162	980	37	2,192	42
Development (a) (b)	320	557	1,047	1,425	744	247	734	165	5,239	156
Total costs incurred	424	752	1,431	2,691	780	409	4,526	202	11,215	1,471
2008
Proved property acquisitions (b)			626	413		256			1,295
Unproved property acquisitions (b)		33	384	655		647			1,719
Exploration (b)	135	227	403	600	16	345	440	48	2,214	48
Development (a) (b)	644	957	1,388	1,884	1,023	598	748	325	7,567	163
Total costs incurred	779	1,217	2,801	3,552	1,039	1,846	1,188	373	12,795	211
2009
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	41
Development (a)	742	727	1,401	2,121	1,086	423	858	462	7,820	206
Total costs incurred	782	841	2,070	2,474	1,106	676	1,274	514	9,737	247

(1)	Eni's incurred costs of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)	Includes the abandonment costs of the assets for euro 173 million in 2007, euro 628 million in 2008 and euro 301 million in 2009.
(b)	Of which business combination:

(euro million) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates

2007
Proved property acquisitions			451		1,395		1,846	187
Unproved property acquisitions			510		1,334		1,844	1,086
Exploration			59		474	��	533
Development			10		345		355	101
Total			1,030		3,548		4,578	1,374
2008
Proved property acquisitions			298	256			554
Unproved property acquisitions	33	384	560	647			1,624
Exploration		23	115	158			296
Development	52	132	4	233			421
Total	85	539	977	1,294			2,895

278

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Results of operations from oil and gas producing activities
Results of operations from oil and gas producing activities, represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA-related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.

279

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Results of operations from oil and gas producing activities by geographical area consist of the following:

(euro million) Italy Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾ Total consolidated subsidiaries, joint ventures and affiliates

Revenues
Sales to consolidated entities	3,171		3,273		3,000		4,439		296		44		229		91		14,543				14,543
Sales to third parties	163		755		4,793		693		833		961		1,112		187		9,497		176		9,673
Total revenues	3,334		4,028		7,793		5,132		1,129		1,005		1,341		278		24,040		176		24,216
Operations costs	(248	)	(584	)	(542	)	(499	)	(142	)	(39	)	(177	)	(50	)	(2,281	)	(27	)	(2,308	)
Production taxes	(188	)			(91	)	(473	)			(28	)					(780	)	(6	)	(786	)
Exploration expenses	(108	)	(196	)	(379	)	(297	)	(36	)	(168	)	(566	)	(27	)	(1,777	)	(42	)	(1,819	)
D.D. & A. and Provision for abandonment (a)	(499	)	(766	)	(768	)	(685	)	(76	)	(422	)	(511	)	(19	)	(3,746	)	(51	)	(3,797	)
Other income and (expenses)	(283	)	(83	)	(627	)	(285	)	(72	)	(134	)	(18	)	(65	)	(1,567	)	(18	)	(1,585	)
Pretax income from producing activities	2,008		2,399		5,386		2,893		803		214		69		117		13,889		32		13,921
Income taxes	(746	)	(1,447	)	(3,102	)	(1,820	)	(284	)	(93	)	(110	)	(10	)	(7,612	)	(49	)	(7,661	)
Results of operations from E&P activities (b)	1,262		952		2,284		1,073		519		121		(41	)	107		6,277		(17	)	6,260
2008
Revenues
Sales to consolidated entities	3,956		3,892		2,622		5,013		360		39		323		66		16,271				16,271
Sales to third parties	126		160		7,286		1,471		1,025		1,335		1,599		218		13,220		265		13,485
Total revenues	4,082		4,052		9,908		6,484		1,385		1,374		1,922		284		29,491		265		29,756
Operations costs	(260	)	(521	)	(528	)	(609	)	(157	)	(68	)	(233	)	(35	)	(2,411	)	(34	)	(2,445	)
Production taxes	(195	)			(32	)	(616	)			(35	)					(878	)	(53	)	(931	)
Exploration expenses	(135	)	(228	)	(406	)	(548	)	(16	)	(232	)	(435	)	(58	)	(2,058	)	(48	)	(2,106	)
D.D. & A. and Provision for abandonment (a)	(551	)	(829	)	(1,120	)	(1,115	)	(79	)	(823	)	(837	)	(35	)	(5,389	)	(84	)	(5,473	)
Other income and (expenses)	(420	)	(56	)	(934	)	(268	)	(270	)	(259	)	(6	)	(41	)	(2,254	)	(15	)	(2,269	)
Pretax income from producing activities	2,521		2,418		6,888		3,328		863		(43	)	411		115		16,501		31		16,532
Income taxes	(924	)	(1,623	)	(4,170	)	(2,262	)	(302	)	(122	)	(214	)	(70	)	(9,687	)	(49	)	(9,736	)
Total results of operations from E&P activities (b)	1,597		795		2,718		1,066		561		(165	)	197		45		6,814		(18	)	6,796
2009
Revenues
Sales to consolidated entities	2,274		2,583		1,738		4,386		245		41		808		29		12,104				12,104
Sales to third parties			540		5,037		586		739		1,208		639		181		8,930		232		9,162
Total revenues	2,274		3,123		6,775		4,972		984		1,249		1,447		210		21,034		232		21,266
Operations costs	(271	)	(517	)	(553	)	(749	)	(153	)	(78	)	(273	)	(41	)	(2,635	)	(34	)	(2,669	)
Production taxes	(148	)			(20	)	(445	)			(34	)					(647	)	(44	)	(691	)
Exploration expenses	(40	)	(114	)	(319	)	(451	)	(20	)	(204	)	(341	)	(62	)	(1,551	)	(41	)	(1,592	)
D.D. & A. and Provision for abandonment (a)	(463	)	(921	)	(956	)	(1,502	)	(78	)	(535	)	(1,108	)	(186	)	(5,749	)	(76	)	(5,825	)
Other income and (expenses)	(125	)	(134	)	(471	)	(467	)	(186	)	(17	)	170		(47	)	(1,277	)	(41	)	(1,318	)
Pretax income from producing activities	1,227		1,437		4,456		1,358		547		381		(105	)	(126	)	9,175		(4	)	9,171
Income taxes	(467	)	(833	)	(3,010	)	(1,042	)	(180	)	(67	)	(2	)	23		(5,578	)	(40	)	(5,618	)
Results of operations from E&P activities (b) (c)	760		604		1,446		316		367		314		(107	)	(103	)	3,597		(44	)	3,553

(1)	Eni's results of operations of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)	Includes asset impairments amounting to euro 91 million in 2007, euro 770 million in 2008 and euro 576 million in 2009.
(b)	The "Successful Effort Method" application would have led to an increase of result of operations of euro 438 million in 2007, euro 408 million in 2008 and euro 320 million in 2009 for the consolidated companies and of euro 26 million in 2007 and any variation in 2008 and euro 26 million in 2009 for joint ventures and affiliates.
(c)	Amounts of 2009 do not include result of operation related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

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Oil and natural gas reserves

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of 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 price¹⁹ 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.
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 evaluation²⁰ 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 report²¹.
In the preparation of their reports, independent evaluators rely, without independent verification, upon information 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; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.
In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.
In 2009 Ryder Scott Company and DeGolyer and MacNaughton²¹ provided an independent evaluation of almost 28% of Eni’s total proved reserves as of December 31, 2009²² confirming, as in previous years, the reasonableness of Eni’s internal evaluations.
In the three year period from 2007 to 2009, 86% of Eni’s total proved reserves were subject to independent evaluation.
As of December 31, 2009 among the most important Eni properties, the only one which was not subject to an independent review was Barbara (Italy).
Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery.
Proved oil and gas reserves associated with PSAs represented 46%, 54% and 57% of total proved reserves as of December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis.
Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 1%, 2% and 2% of total proved reserves on an oil-equivalent basis as of December 31, 2007, 2008 and 2009, respectively.
Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess to cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of

(19)	In prior periods, year-end liquids and natural gas prices were used in the estimate of proved reserves.
(20)	From 1991 to 2002 DeGolyer and MacNaughton, from 2003 also Ryder Scott.
(21)	The reports of independent engineers are available on Eni website www.eni.com, section Documentation/Annual Report 2009.
(22)	Including reserves of joint ventures and affiliates.

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reserves. Reserve volumes associated with oil and gas deriving from such obligation represent 1.8%, 0.1% and 0.3% of total proved reserves as of December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption, (iii) the quantities of natural gas produced to feed the Angola LNG plant and (iv) volumes of natural gas held in certain Eni’s 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 judgment. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be actually produced.
The following tables present 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, 2007, 2008 and 2009.

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Crude oil (including condensate and natural gas liquids)

(million barrels) Italy Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾ Total consolidated subsidiaries, joint ventures and affiliates

Reserves at December 31, 2006	215		386		982		786		893		62		98		35		3,457		24		3,481
of which: developed	136		329		713		546		262		53		54		33		2,126		18		2,144
undeveloped	79		57		269		240		631		9		44		2		1,331		6		1,337
Purchase of Minerals in Place							32						54				86		101		187
Revisions of Previous Estimates	28		14		(35	)	(26	)	(114	)	(6	)	(23	)	(2	)	(164	)	20		(144	)
Improved Recovery			1		9		12										22		1		23
Extensions and Discoveries			1		43		22						28		1		95		1		96
Production	(28	)	(57	)	(121	)	(101	)	(26	)	(12	)	(19	)	(5	)	(369	)	(5	)	(374	)
Reserves at December 31, 2007	215		345		878		725		753		44		138		29		3,127		142		3,269
of which: developed	133		299		649		511		219		35		81		26		1,953		26		1,979
undeveloped	82		46		229		214		534		9		57		3		1,174		116		1,290
Purchase of Minerals in Place							32				36						68				68
Revisions of Previous Estimates	(8	)	(30	)	56		80		239		42		11		1		391		4		395
Improved Recovery					7		25										32		1		33
Extensions and Discoveries	4		13		4		26				2		3				52				52
Production	(25	)	(51	)	(122	)	(105	)	(25	)	(18	)	(21	)	(4	)	(371	)	(5	)	(376	)
Sales of Minerals in Place									(56	)							(56	)			(56	)
Reserves at December 31, 2008	186		277		823		783		911		106		131		26		3,243		142		3,385
of which: developed	111		222		613		576		298		92		74		23		2,009		33		2,042
undeveloped	75		55		210		207		613		14		57		3		1,234		109		1,343
Purchase of Minerals in Place							2										2				2
Revisions of Previous Estimates	57		40		129		78		(36	)	(35	)	36		1		270				270
Improved Recovery			8		10		15										33				33
Extensions and Discoveries	10		74		38		5				44		12		8		191		1		192
Production	(20	)	(48	)	(105	)	(113	)	(26	)	(21	)	(26	)	(3	)	(362	)	(6	)	(368	)
Sales of Minerals in Place																			(51	)	(51	)
Reserves at December 31, 2009	233		351		895		770		849		94		153		32		3,377		86		3,463
of which: developed	141		218		659		544		291		45		80		23		2,001		34		2,035
undeveloped	92		133		236		226		558		49		73		9		1,376		52		1,428

(1)	Eni's proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).

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Natural gas

(billion cubic feet) Italy ^(a) Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾ Total consolidated subsidiaries, joint ventures and affiliates

Reserves at December 31, 2006	3,391		1,836		5,946		1,927		1,874		991		299		633		16,897		68		16,965
of which: developed	2,449		1,480		3,042		1,447		1,511		614		159		247		10,949		48		10,997
undeveloped	942		356		2,904		480		363		377		140		386		5,948		20		5,968
Purchase of Minerals in Place							5						395				400		2,963		3,363
Revisions of Previous Estimates	(53	)	66		250		74		(222	)	23		4		(20	)	122		5		127
Improved Recovery			3														3				3
Extensions and Discoveries	4		6		89		213		205		4		86				607				607
Production	(285	)	(236	)	(534	)	(97	)	(87	)	(138	)	(88	)	(15	)	(1,480	)	(14	)	(1,494	)
Reserves at December 31, 2007	3,057		1,675		5,751		2,122		1,770		880		696		598		16,549		3,022		19,571
of which: developed	2,304		1,364		3,065		1,469		1,580		530		442		213		10,967		428		11,395
undeveloped	753		311		2,686		653		190		350		254		385		5,582		2,594		8,176
Purchase of Minerals in Place			8				6				114						128				128
Revisions of Previous Estimates	56		(58	)	1,163		45		772		52		(13	)	24		2,041		6		2,047
Improved Recovery							4										4				4
Extensions and Discoveries	5		25		38		2				11		31				112				112
Production	(274	)	(229	)	(641	)	(95	)	(89	)	(146	)	(114	)	(16	)	(1,604	)	(13	)	(1,617	)
Sales of Minerals in Place									(16	)							(16	)			(16	)
Reserves at December 31, 2008	2,844		1,421		6,311		2,084		2,437		911		600		606		17,214		3,015		20,229
of which: developed	2,031		1,122		3,537		1,443		2,005		439		340		221		11,138		420		11,558
undeveloped	813		299		2,774		641		432		472		260		385		6,076		2,595		8,671
Purchase of Minerals in Place							1						136				137				137
Revisions of Previous Estimates	97		149		(309	)	142		(204	)	52		43		(17	)	(47	)	18		(29	)
Improved Recovery			25														25				25
Extensions and Discoveries	1		26		479						2		7		4		519		80		599
Production	(238	)	(239	)	(587	)	(100	)	(94	)	(151	)	(155	)	(18	)	(1,582	)	(14	)	(1,596	)
Sales of Minerals in Place			(2	)									(2	)			(4	)	(1,511	)	(1,515	)
Reserves at December 31, 2009	2,704		1,380		5,894		2,127		2,139		814		629		575		16,262		1,588		17,850
of which: developed	2,001		1,231		3,486		1,463		1,859		539		506		565		11,650		234		11,884
undeveloped	703		149		2,408		664		280		275		123		10		4,612		1,354		5,966

(1)	Eni's proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)	Including approximately, 754, 749, 746 and 769 billion of cubic feet of natural gas held in storage at December 31, 2006, 2007, 2008 and 2009, respectively.

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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 years ended December 31, 2007 and 2008 and the average prices during the year ended December 31, 2009 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 Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

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The standardized measure of discounted future net cash flows by geographical area consists of the following:

(euro million) Italy Rest of Europe North Africa West Africa Kazakhstan ⁽¹⁾ Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total joint ventures and affiliates ⁽²⁾ Total consolidated subsidiaries, joint ventures and affiliates

At December 31, 2007
Future cash inflows	47,243		30,390		73,456		48,283		42,710		4,855		11,180		3,544		261,661		7,135		268,796
Future production costs	(5,926	)	(6,759	)	(11,754	)	(9,875	)	(4,997	)	(476	)	(1,758	)	(459	)	(42,004	)	(1,249	)	(43,253	)
Future development and abandonment costs	(7,218	)	(2,653	)	(4,643	)	(3,013	)	(3,374	)	(306	)	(1,533	)	(428	)	(23,168	)	(1,721	)	(24,889	)
Future net inflow before income tax	34,099		20,978		57,059		35,395		34,339		4,073		7,889		2,657		196,489		4,165		200,654
Future income tax	(10,778	)	(14,388	)	(29,083	)	(23,083	)	(9,977	)	(1,109	)	(3,272	)	(1,003	)	(92,693	)	(2,009	)	(94,702	)
Future net cash flows	23,321		6,590		27,976		12,312		24,362		2,964		4,617		1,654		103,796		2,156		105,952
10% discount factor	(13,262	)	(1,757	)	(11,143	)	(3,953	)	(17,480	)	(718	)	(1,568	)	(913	)	(50,794	)	(1,265	)	(52,059	)
Standardized measure of discounted future net cash flows	10,059		4,833		16,833		8,359		6,882		2,246		3,049		741		53,002		891		53,893
At December 31, 2008
Future cash inflows	46,458		16,963		62,785		22,344		21,648		5,072		5,257		2,937		183,464		4,782		188,246
Future production costs	(5,019	)	(3,467	)	(10,673	)	(6,715	)	(6,273	)	(707	)	(1,657	)	(405	)	(34,916	)	(1,104	)	(36,020	)
Future development and abandonment costs	(6,805	)	(2,317	)	(6,153	)	(3,868	)	(4,842	)	(738	)	(1,022	)	(258	)	(26,003	)	(1,845	)	(27,848	)
Future net inflow before income tax	34,634		11,179		45,959		11,761		10,533		3,627		2,578		2,274		122,545		1,833		124,378
Future income tax	(11,329	)	(7,697	)	(27,800	)	(5,599	)	(2,745	)	(768	)	(232	)	(861	)	(57,031	)	(1,032	)	(58,063	)
Future net cash flows	23,305		3,482		18,159		6,162		7,788		2,859		2,346		1,413		65,514		801		66,315
10% discount factor	(13,884	)	(1,042	)	(8,639	)	(2,155	)	(6,230	)	(672	)	(672	)	(768	)	(34,062	)	(763	)	(34,825	)
Standardized measure of discounted future net cash flows	9,421		2,440		9,520		4,007		1,558		2,187		1,674		645		31,452		38		31,490
At December 31, 2009
Future cash inflows	26,243		22,057		59,413		33,676		30,273		5,680		7,088		2,973		187,403		3,718		191,121
Future production costs	(4,732	)	(6,215	)	(7,771	)	(9,737	)	(6,545	)	(1,427	)	(1,797	)	(529	)	(38,753	)	(1,251	)	(40,004	)
Future development and abandonment costs	(5,143	)	(5,375	)	(8,618	)	(5,134	)	(4,345	)	(1,409	)	(1,897	)	(214	)	(32,135	)	(1,168	)	(33,303	)
Future net inflow before income tax	16,368		10,467		43,024		18,805		19,383		2,844		3,394		2,230		116,515		1,299		117,814
Future income tax	(5,263	)	(6,621	)	(24,230	)	(9,894	)	(4,827	)	(636	)	(694	)	(563	)	(52,728	)	(432	)	(53,160	)
Future net cash flows	11,105		3,846		18,794		8,911		14,556		2,208		2,700		1,667		63,787		867		64,654
10% discount factor	(5,868	)	(1,455	)	(9,160	)	(3,102	)	(10,249	)	(520	)	(1,162	)	(771	)	(32,287	)	(610	)	(32,897	)
Standardized measure of discounted future net cash flows (a)	5,237		2,391		9,634		5,809		4,307		1,688		1,538		896		31,500		257		31,757

(1)	Eni's standardized measure of discounted future of net cash flows of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009 and 18.52% as at December 2007.
(2)	The amounts of joint ventures and affiliates as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(a)	Amounts of 2009 do not include standardized measure of discounted future net cash flows related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

286

ENI ANNUAL REPORT / NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Changes in standardized measure of discounted future net cash flows

Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2007, 2008 and 2009, are as follows:

(euro million) Total consolidated subsidiaries Total joint ventures and affiliates Total consolidated subsidiaries, joint ventures and affiliates

Value at December 31, 2006	43,227		354		43,581
Increase (Decrease):
. sales, net of production costs	(20,979	)	(143	)	(21,122	)
. net changes in sales and transfer prices, net of production costs	34,999		153		35,152
. extensions, discoveries and improved recovery, net of future production and development costs	3,982		46		4,028
. changes in estimated future development and abandonment costs	(4,000	)	(73	)	(4,073	)
. development costs incurred during the period that reduced future development costs	4,682		56		4,738
. revisions of quantity estimates	(2,995	)	527		(2,468	)
. accretion of discount	7,968		50		8,018
. net change in income taxes	(17,916	)	(1,027	)	(18,943	)
. purchase of reserves in-place	3,521		929		4,450
. changes in production rates (timing) and other	513		19		532
Net increase (decrease)	9,775		537		10,312
Value at December 31, 2007	53,002		891		53,893
Increase (Decrease):
. sales, net of production costs	(26,202	)	(178	)	(26,380	)
. net changes in sales and transfer prices, net of production costs	(39,699	)	(1,254	)	(40,953	)
. extensions, discoveries and improved recovery, net of future production and development costs	1,110		10		1,120
. changes in estimated future development and abandonment costs	(6,222	)	(129	)	(6,351	)
. development costs incurred during the period that reduced future development costs	6,584		145		6,729
. revisions of quantity estimates	5,835		(61	)	5,774
. accretion of discount	10,538		201		10,739
. net change in income taxes	21,359		657		22,016
. purchase of reserves in-place	476				476
. sale of reserves in-place	25				25
. changes in production rates (timing) and other	4,646		(244	)	4,402
Net increase (decrease)	(21,550	)	(853	)	(22,403	)
Value 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
Value at December 31, 2009	31,500		257		31,757

287

Certification pursuant to rule 154-bis paragraph 5 of the Legislative Decree No. 58/1998 (Testo Unico della Finanza)

1.	The undersigned Paolo Scaroni and Alessandro Bernini, in their quality as Chief Executive Officer and manager responsible for the preparation of financial reports of Eni, respectively, also pursuant to rule 154-bis, paragraphs 3 and 4 of Legislative Decree No. 58/1998, certify that internal controls over financial reporting in place for the reparation of the Annual Report as of December 31, 2009 and during the period covered by the report, were:
	• adequate to the company structure, and
	• effectively applied during the process of preparation of the report.
2.	Internal controls over financial reporting in place for the preparation of the 2009 consolidated accounts have been defined and the evaluation of their effectiveness has been assessed based on principles and methodologies adopted by Eni in accordance with the Internal Control-Integrated Framework Model issued by the Committee of Sponsoring Organizations of the Treadway Commission, which represents an internationally-accepted framework for the internal control system.
3.	The undersigned officers also certify that:
3.1	This 2009 consolidated Annual Report:
	a) was prepared in accordance with the evaluation and measurement criteria adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002;
	b) corresponds to the company’s evidence and accounting books and entries;
	c) fairly represents the financial condition, results of operations and cash flows of the parent company and the Group consolidated companies as of, and for, the period presented in this report.
3.2	The operating and financial review provides a reliable analysis of business trends and results, including trend analysis of the parent company and the Group companies, as well as a description of the main risks and uncertainties.

March 11, 2010

/s/ Paolo Scaroni
—————————
Paolo Scaroni
Chief Executive Officer /s/Alessandro Bernini
—————————
Alessandro Bernini
Chief Financial Officer

288

Report of Independent Auditors

289

290

	Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com
	eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2009: euro 4,005,358,876 fully paid Tax identification number 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1   Publications Financial Statement pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Sustainability Report (in Italian and English) Fact Book (in Italian and English) Eni in 2009 (in English) Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 Internet Home page: www.eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary Morgan Guaranty Trust Company of New York ADR Department 60 Wall Street (36th Floor) New York, New York 10260 Tel. 212-648-3164 ADRs/Transfer agent Morgan ADR Service Center 2 Heritage Drive North Quincy, MA 02171 Tel. 617-575-4328 Design: Opera Cover: In Area - Rome - Italy Layout and supervision: Korus - Rome - Italy Printing: Marchesi Grafiche Editoriali SpA - Rome - Italy Printed on environmental friendly paper: Fedrigoni Symbol Freelife Satin and Freelife Vellum

Eni: giant field Perla resources to increase by more than 30%

San Donato Milanese (Milan), April 12, 2010 - Eni has successfully drilled the Perla 2 well, located in the Cardón IV Block, in the shallow water of the Gulf of Venezuela. The results largely exceeded pre-drill expectations, thus increasing the initial resource estimations by 30%, with potential for further improvement.

This result confirms Perla as a world-class gas discovery, one of the most significant in recent years, and the largest ever in Venezuela.

Perla 2, drilled in 60 m of water depth, encountered 840 ft (260 m) of net pay in a carbonate sequence with excellent reservoir characteristics, confirmed by 700 ft (210 m) of bottom hole cores that have been recovered.

During the production test, the well flowed 50 mmscf/day of gas and 1,500 bopd of condensate. Normalized gas production per well is expected to increase to over 70 mmscf/day of gas and 2,000 bopd of condensate.

The Cardón IV Block is currently licensed and operated by a Joint Operating Company, owned 50% by Eni and 50% by Repsol, named Cardón IV S.A. The Venezuelan state company Petróleos de Venezuela S.A. (PDVSA) owns a 35% back-in right to be exercised in the development phase, and at that time Eni and Repsol will each hold a 32.5% interest in the project, which will then be jointly operated by the three companies.

Eni and Repsol have already begun, together with PDVSA, to evaluate options for a fast track development of Perla, through an early production phase targeted to start up in early-mid 2013 with 300 million scf per day.

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Eni is present in Venezuela through its participation in Petrosucre, the Operating Company which runs the Corocoro Field (PDVSA 74%, Eni 26%) with a daily equity production of approximately 10,000 barrels of oil per day, and in Petrolera Guiria (PDVSA 64.25%, Eni 19.5%, Ineparia 16.25%) which operates the discovery of Punta Sur. Both the Corocoro and Punta Sur fields are located in the offshore of the Gulf of Paria.

Furthermore, Eni has recently signed an agreement with PDVSA aimed at developing the Junin-5 heavy oil block, located in the Faja of Orinoco, which holds 35 billion barrels of certified oil in place. PDVSA will hold 60% and Eni 40% in the Junin-5 venture, which will be jointly operated.

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.065982398
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56
Switchboard: +39.0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

- 2 -

Eni and Gazprom meet on South Stream and upstream projects

San Donato Milanese (Milan), April 12, 2010 - Gazprom Chairman Alexey Miller and Eni CEO Paolo Scaroni met today in Moscow to discuss the two companies' common projects.

South Stream
Eni and Gazprom confirm their full commitment to the South Stream project and their intention to complete the feasibility study of the offshore section. The two companies also agreed to accelerate the activities of their joint venture South Stream AG.

Eni and Gazprom also confirmed their support to EdF entry into the project and committed to starting negotiations with EdF.

Upstream projects
Eni and Gazprom have agreed on the terms of Gazprom's entry into the Elephant project in Libya. The detailed agreement will be finalised in the coming days and will be submitted to Libyan authorities for approval.

First production at the Samburskoye field is confirmed for 2011. Plateau production of 150,000 boepd is expected within two years of start-up.

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.065982398
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56
Switchboard: +39.0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

ENI ANNOUNCES RESULTS FOR THE FIRST QUARTER OF 2010

Financial Highlights
• Adjusted operating profit: up 15.4% to euro 4.33 billion
• Adjusted net profit: up 3.6% to euro 1.82 billion
• Net profit: up 16.7% to euro 2.22 billion
• Cash flow: euro 4.55 billion

Operational Highlights
• Oil and natural gas production: up 2.1% to 1.816 million barrels per day
• Natural gas sales: down 5.7% to 30.51 billion cubic meters

Rome, April 23, 2010 - Eni, the international oil and gas company, today announces its group results for the first quarter of 2010¹ (unaudited).

Paolo Scaroni, Chief Executive Officer, commented:
“Eni delivered solid operating and financial results for the first quarter of 2010, in spite of ongoing market challenges. We continue investing to drive growth and efficiency as we maintain our focus on creating value for our shareholders.”

(1) This press release represents the quarterly report prepared in compliance with Italian listing standards as provided by Article 154-ter of the Italian code for securities and exchanges (Testo Unico della Finanza).

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Financial Highlights

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

SUMMARY GROUP RESULTS (euro million)

2,466	Operating profit	3,967	4,847	22.2
3,702	Adjusted operating profit (a)	3,754	4,331	15.4
391	Net profit (b)	1,904	2,222	16.7
0.11	- per share (euro) (c)	0.53	0.61	15.1
0.33	- per ADR ($) (c) (d)	1.38	1.69	22.5
1,394	Adjusted net profit (a) (b)	1,759	1,822	3.6
0.38	- per share (euro) (c)	0.49	0.50	2.0
1.12	- per ADR ($) (c) (d)	1.28	1.38	7.8

(a)	For a detailed explanation of adjusted operating profit and net profit see paragraph "Reconciliation of reported operating and net profit to results on an adjusted basis" page 20.
(b)	Profit attributable to Eni shareholders.
(c)	Fully diluted. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by the ECB for the periods presented.
(d)	One ADR (American Depositary Receipt) is equal to two Eni ordinary shares.

Adjusted operating profit
Adjusted operating profit was euro 4.33 billion, up 15.4% from the first quarter of 2009. This was due to an excellent operating performance reported by the Exploration & Production division driven by increased oil prices and production growth. The Petrochemical division also improved versus a year ago as operating losses were cut in half. Theses positive trends were partially offset by reduced results reported by both the Refining & Marketing and the Gas & Power divisions.

Adjusted Net Profit
Adjusted net profit was euro 1.82 billion, up 3.6% compared with a year ago, as a better operating performance was partly absorbed by the negative impact associated with an increased adjusted tax rate (from 49% to 53%).

Capital expenditures
Capital expenditures for the quarter amounted to euro 2.78 billion mainly related to continuing development of oil and gas reserves, the construction of rigs and offshore vessels in the Engineering & Construction segment and the upgrading of gas transport infrastructure.

Cash flow
The main cash inflows for the quarter were net cash generated by operating activities amounting to euro 4.55 billion and proceeds from divestments of euro 729 million. These inflows were used to fund the financing requirements associated with capital expenditures (euro 2.78 billion) and to pay down finance debt. As of March 31, 2010 net borrowings² amounted to euro 21.05 billion, representing a decrease of euro 2 billion from year end 2009, notwithstanding negative exchange rate translation differences (down approximately euro 370 million).

Financial Ratios
Return on Average Capital Employed (ROACE)³ calculated on an adjusted basis at March 31, 2010 was 9.1%. The ratio of net borrowings to shareholders’ equity including minority interest – leverage³ – decreased to 0.39 at March 31, 2010 from 0.46 as of December 31, 2009.

(2)	Information on net borrowings composition is furnished on page 27.
(3)	Non-GAAP financial measures disclosed throughout this press release are accompanied by explanatory notes and tables to help investors to gain a full understanding of said measures in line with guidance provided for by CESR Recommendation No. 2005-178b. See pages 27 and 28 for leverage and ROACE, respectively.

- 2 -

Operational Highlights and Trading Environment

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

KEY STATISTICS

1,886	Production of oil and natural gas	(kboe/d)	1,779	1,816	2.1
1,073	- Liquids	(kbbl/d)	1,013	1,011	(0.2	)
4,668	- Natural gas	(mmcf/d)	4,398	4,615	4.8
28.39	Worldwide gas sales	(bcm)	32.35	30.51	(5.7	)
1.82	- of which: E&P sales in Europe and the Gulf of Mexico		1.49	1.60	7.4
9.42	Electricity sales	(TWh)	7.78	9.00	15.7
3.00	Retail sales of refined products in Europe	(mmtonnes)	2.79	2.68	(3.9	)

Exploration & Production
Eni reported liquids and gas production of 1,816 kboe/d for the first quarter of 2010. Production grew by 2.1% as a result of continuing production ramp-up in Nigeria, Congo and the United States, and additions from fields which were started-up in 2009. These positive trends were partly offset by a combined negative impact associated with lower entitlements in Company’s PSAs due to higher oil prices, and lower OPEC restrictions. Also, production for the quarter was negatively affected by unplanned facility shutdowns and mature field declines, particularly in the North Sea.

Realized Oil and Gas Prices
Oil realizations in dollar terms increased by 68.5% driven by a recovery in market benchmark Brent prices (up 71.7% from the first quarter of 2009). Natural gas realizations declined due to the impact of the time lag in oil-linked pricing formulae and weak demand.

Gas & Power
Eni’s worldwide natural gas sales were 30.51 bcm, down by 5.7% compared with the first quarter of 2009. The performance was negatively affected by sharply lower volumes supplied to the Italian market (down by 2.34 bcm, or 17.7%) due to increased competitive pressures in the power generation business, as well as in sales to wholesalers and industrial customers. Sales outside of Italy increased by 2.6% as a result of organic growth achieved in Northern Europe, France and Belgium.

Refining & Marketing
Eni’s realized refining margins in dollar terms were sharply lower mirroring the environment for Brent margins (down $2.94 per barrel in the quarter, or 55.1%). This reduction reflected prolonged weakness in industry fundamentals as rapidly-escalating of oil-based feedstock costs were not fully transferred to final prices of products due to excess capacity, sluggish demand and high inventory levels.

Currency
Results of operations for the quarter were negatively affected by a steep appreciation of euro vs the US dollar, up by 6.3%. This particularly impacted reported results of foreign subsidiaries in the Exploration & Production division which use the US dollar as their functional currency.

Portfolio developments

Venezuela
The Perla 2 well, located in the Cardón IV Block, in the shallow waters of the Gulf of Venezuela, was successfully drilled. The results exceeded the initial resource estimation by 30% with potential for further improvements to be defined through the future wells. This result confirms Perla as a world-class gas discovery, one of the most significant in recent years, and the largest ever in Venezuela.

- 3 -

Angola
Two oil discoveries were made offshore in the 15/06 block (Eni 35%, operator) with the exploration wells Nzanza-1 e Cinguvu-1, which have been flowing at more than 1,600 and 6,400 barrels per day, respectively.

Russia
As part of the transaction to divest a 51% stake in the joint-venture Eni-Enel OOO SeverEnergia to Gazprom, based on the call option exercised by the Russian company on September 24, 2009, Eni collected a second installment of the transaction by March 31, 2010. This amounted to euro 526 million (as converted at the EUR/USD exchange rate of 1.35 as of the transaction date, corresponding to approximately $710 million, approximately 75% of the whole amount).

Main production start-ups

In line with the Company’s production plans, production was started at the Annamaria B field (Eni 90% operator), located in the offshore section between Italy and Croatia, which flowed at approximately 28 mmcf/day. A production plateau of 42 mmcf/day (7,500 barrels of oil equivalent) is targeted. Other start-ups were achieved in Algeria, China and Congo.

Outlook

In what remains an uncertain energy environment, Eni forecasts a modest improvement in global oil demand and a Brent price of 76 $/barrel in 2010. Gas demand in Europe and Italy is expected to recover gradually from the steep decline suffered in 2009, which mainly impacted the industrial and thermoelectric sectors at a time when new import capacity was coming on line. The Company faces a challenging refining environment, excluding any significant recovery in industry fundamentals, which will result in prolonged weakness in refinery margins.

- Production of liquids and natural gas is forecast to slightly increase compared to 2009 (production in 2009 was 1.769 million boe/d). This estimate is based on the Company’s scenario for a Brent price of 76 $/barrel for the full year, the same level of OPEC restrictions as in the first quarter of 2010 and asset disposals underway. Growth will be driven by continuing field start-ups, mainly in Italy, Algeria and Norway and marginally the Zubair project in Iraq, and production ramp-up at the Company’s recently started fields, mainly in Nigeria, Angola and the USA. These additions will be partly offset by mature field declines.

- Natural gas sales are forecasted to decrease slightly compared with 2009 (approximately 104 bcm were achieved in 2009). Increasing competitive pressures, mainly in Italy, are expected to be partly offset by an expected recovery in European gas demand. Other positive trends include a benefit associated with integrating Distrigas operations and the optimization of its supply portfolio, including re-negotiation of long-term supply contracts.

- Regulated businesses in Italy will benefit from the pre-set regulatory return on new capital expenditures and cost savings from integrating the whole chain of transport, storage and distribution activities.

- Refining throughputs on Eni’s account are planned to be in line with 2009 (actual throughputs in 2009 were 34.55 mmtonnes). Volumes processed at wholly-owned refineries are expected to increase, resulting in a higher capacity utilization rate, due to a reduction of volumes on third party refineries reflecting the Company’s decision to terminate certain processing agreements. Efficiency improvement actions will partly offset the unfavorable trading environment.

- Retail sales of refined products in Italy and the rest of Europe are expected to be unchanged from 2009 (12.02 mmtonnes in 2009) reflecting weak demand. New marketing initiatives are planned in order to strengthen Eni’s leadership on the Italian retail market and to develop its market share in European markets.

- The Engineering & Construction business is expected to see solid results due to a robust order backlog.

In 2010, management plans to make capital expenditures broadly in line with 2009 (euro 13.69 billion were invested in 2009). Capital expenditures will mainly be directed to the development of oil and natural gas reserves, exploration projects, the upgrading of construction vessels and rigs, and the upgrading of natural gas transport infrastructure. Management has planned a number of measures designed to ensure the achievement of a ratio of net borrowings to total equity (leverage) which will adequately support a strong credit rating.

- 4 -

This press release for the first quarter of 2010 (unaudited) provides data and information on business and financial performance in compliance with Article 154-ter of the Italian code for securities and exchanges ("Testo Unico della Finanza" - TUF). Results are presented for the first quarter of 2010 and for the first quarter and the fourth quarter of 2009. Information on liquidity and capital resources relates to end of the period as of March 31, 2010, and December 31, 2009. Tables contained in this press release are comparable with those presented in the management’s disclosure section of the Company’s annual report and interim report. Quarterly accounts set forth herein have been prepared in accordance with the evaluation and recognition criteria set by the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002. The evaluation and recognition criteria applied during the preparation of the report for the first quarter are unchanged from those adopted for the preparation of the 2009 Annual Report, with the exception of the international accounting standards come into force from January 1, 2010 described in the section of the 2009 Annual Report "Accounting standards and interpretations issued by IASB /IFRIC and endorsed by EU".
Adoption of those accounting standards did not have any impacts on the financial results of the first quarter 2010 with the sole exception of interpretation IFRIC 12 "service concession arrangements". IFRIC 12 provides guidance on the accounting by operators for public-to-private service concession arrangements. An arrangement within the scope of this interpretation involves for a specified period of time an operator constructing, upgrading, operating and maintaining the infrastructure used to provide the public service. In particular when the grantor controls or regulates what services the operator must provide with the infrastructure, at what price and any significant residual interest in the infrastructure at the end of the term of the arrangement, the operator shall recognize the concession as an intangible asset or as a financial asset on the basis of the agreements. Based on existing arrangements in Eni Group companies, adoption of IFRIC 12 has led to the Company classifying infrastructures used to provide the public service within intangible assets in the balance sheet as of March 31, 2010. Balance sheet data as of December 31, 2009 have been restated accordingly for an amount of euro 3,412 million (i.e. the net book value of infrastructures used to provide the public service which were presented within property, plant and equipment in prior years).
Considering the tariff set-up of public services rendered under concessions arrangements and absent any benchmarks, the Company was in no position to reliably quantify margins for construction and upgrading activities and consequently capital expenditure made in the period have been recognized as contract work in progress for an equal amount as costs incurred. Infrastructures used to provide the public service are amortized on the basis of the expected pattern of consumption of expected future economic benefits embodied in those assets and their residual value, as provided by the relevant regulatory framework.

Non-GAAP financial measures and other performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables to help investors to gain a full understanding of said measures in line with guidance provided by recommendation CESR/05-178b.

Eni’s Chief Financial Officer, Alessandro Bernini, in his position as manager responsible for the preparation of the Company’s financial reports, certifies pursuant to rule 154-bis paragraph 2 of Legislative Decree No. 58/1998, that data and information disclosed in this press release correspond to the Company’s evidence and accounting books and entries.

Cautionary statement
This press release, in particular the statements under the section "Outlook", contains certain forward-looking statements particularly those regarding capital expenditures, development and management of oil and gas resources, dividends, share repurchases, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sales growth, new markets, and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. Due to the seasonality in demand for natural gas and certain refined products and the changes in a number of external factors affecting Eni’s operations, such as prices and margins of hydrocarbons and refined products, Eni’s results from operations and changes in net borrowings for the first quarter of the year cannot be extrapolated on an annual basis.

- 5 -

* **

Contacts
E-mail: segreteriasocietaria.azionisti@eni.com

Investor Relations
E-mail: investor.relations@eni.com
Tel.: +39 0252051651 - Fax: +39 0252031929

Eni Press Office
E-mail: ufficiostampa@eni.com
Tel.: +39 0252031287 - +39 0659822040

* **

Eni
Società per Azioni, Rome, Piazzale Enrico Mattei, 1
Share capital: euro 4,005,358,876 fully paid
Tax identification number 00484960588
Tel.: +39-0659821 - Fax: +39-0659822141

* * *

This press release for the first quarter of 2010 (unaudited) is also available on the Eni web site eni.com.

- 6 -

Summary results for the first quarter of 2010

Fourth Quarter First Quarter

2009 (euro million) 2009 2010 % Ch.

22,077		Net sales from operations	23,741		24,804		4.5
2,466		Operating profit	3,967		4,847		22.2
(135	)	Exclusion of inventory holding (gains) losses	125		(409	)
1,371		Exclusion of special items	(338	)	(107	)
		of which:
250		- non recurring items
1,121		- other special items	(338	)	(107	)
3,702		Adjusted operating profit	3,754		4,331		15.4
391		Net profit attributable to Eni’s shareholders	1,904		2,222		16.7
(31	)	Exclusion of inventory holding (gains) losses	91		(280	)
1,034		Exclusion of special items	(236	)	(120	)
		of which:
250		- non recurring items
784		- other special items	(236	)	(120	)
1,394		Adjusted net profit attributable to Eni’s shareholders	1,759		1,822		3.6
287		Adjusted net profit of non-controlling interest	206		197		(4.4	)
1,681		Adjusted net profit	1,965		2,019		2.7
		Breakdown by division (a):
1,019		Exploration & Production	908		1,245		37.1
852		Gas & Power	988		955		(3.3	)
(118	)	Refining & Marketing	68		(30	)	..
(85	)	Petrochemicals	(95	)	(43	)	54.7
229		Engineering & Construction	223		197		(11.7	)
(83	)	Other activities	(25	)	(61	)	..
(95	)	Corporate and financial companies	(174	)	(202	)	(16.1	)
(38	)	Impact of unrealized intragroup profit elimination (b)	72		(42	)
		Net profit attributable to Eni’s shareholders
0.11		per share (euro)	0.53		0.61		15.1
0.33		per ADR ($)	1.38		1.69		22.5
		Adjusted net profit attributable to Eni’s shareholders
0.38		per share (euro)	0.49		0.50		2.0
1.12		per ADR ($)	1.28		1.38		7.8
3,622.4		Weighted average number of outstanding shares (c)	3,622.4		3,622.4
1,481		Net cash provided by operating activities	5,443		4,554		(16.3	)
3,894		Capital expenditures	3,147		2,779		(11.7	)

(a)	For a detailed explanation of adjusted net profit by division see page 20.
(b)	Unrealized intragroup profit concerns profit on the intragroup sale of products, goods, services and tangible and intangible goods reported in the acquiring company’s shareholders’ equity at period end.
(c)	Fully diluted (million shares).

Trading environment indicators

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

74.57	Average price of Brent dated crude oil (a)	44.40	76.24	71.7
1.478	Average EUR/USD exchange rate (b)	1.302	1.384	6.3
50.45	Average price in euro of Brent dated crude oil	34.10	55.09	61.6
1.24	Average European refining margin (c)	5.34	2.40	(55.1	)
1.80	Average European refining margin Brent/Ural (c)	6.28	3.20	(49.0	)
0.84	Average European refining margin in euro	4.10	1.74	(57.6	)
0.7	Euribor - three-month euro rate (%)	2.0	0.6	(70.0	)
0.3	Libor - three-month dollar rate (%)	1.2	0.3	(79.8	)

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

- 7 -

Group results
Net profit attributable to Eni’s shareholders for the first quarter of 2010 was euro 2,222 million, an increase of euro 318 million from the first quarter of 2009, up 16.7%. The result was driven by an increase in operating performance (up euro 880, or 22.2%) which was mainly reported by the Exploration & Production division on the back of higher oil prices and production growth. The improved operating results were partly offset by the negative effect associate with an increased Group’s tax rate from 48.3% to 49.9%.

Adjusted net profit attributable to Eni’s shareholders amounted to euro 1,822, an increase of euro 63 million from the first quarter of 2009, up 3.6%. Adjusted net profit is calculated by excluding an inventory holding profit of euro 280 million and net special gains of euro 120 million, resulting in an overall adjustment equivalent to a decrease of euro 400 million. The balance between special charges and gains is comprised of, on the positive side, gains recorded on the divestment of non-strategic assets in the Exploration & Production division. On the negative side, provisions for redundancy incentives and environmental charges were recorded.

Results by division
The increase in the Group adjusted net profit reflected higher results reported by the following divisions:

- Exploration & Production (up euro 337 million, or 37.1%). This increase reflected a better operating performance (up euro 945 million, or 43.5%) driven by higher oil realizations in dollar (up 68.5%), higher sales volumes (up 1.4%) and lower exploration expenses, which were partly offset by increased operating costs and amortization charges taken in connection with developing activities. Also results were negatively affected by the appreciation of the euro over the dollar (up 6.3%) and an increased adjusted tax rate which was up by 1.7 percentage points (from 58.6% to 60.3%).

- Petrochemicals (up euro 52 million). The division improved its performance as losses at both net and operating levels were reduced (from euro 95 million to euro 43 million, and from euro 111 million to euro 59 million, respectively) driven by a recovery in product demand and cost efficiencies.

These increases were partly offset by a decrease in the adjusted net profit reported in the following divisions:

- Refining & Marketing. The division achieved an adjusted net loss amounting to euro 30 million (down euro 98 million). This result reflected a move from profit to loss at operating level (from plus euro 55 million to minus euro 94 million) due to sharply lower refining margins affected by an unfavorable trading environment. Also marketing activities in Italy reported a decrease in results.

- Gas & Power (down euro 33 million, or 3.3%). The decrease was affected by a lower operating profit which was down by euro 96 million, or 7%, due to the negative performance of the Marketing business. This negative was partly offset by a positive impact resulting from a lower tax rate (down 2.2 percentage points).

- 8 -

Liquidity and capital resources
Summarized Group Balance Sheet⁴

(euro million)

Dec. 31, 2009 Mar. 31, 2010 Change

Fixed assets (a)
Property, plant and equipment	59,765		62,033		2,268
Inventory - compulsory stock	1,736		1,873		137
Intangible assets	11,469		11,446		(23	)
Equity-accounted investments and other investments	6,244		6,026		(218	)
Receivables and securities held for operating purposes	1,261		1,300		39
Net payables related to capital expenditures	(749	)	(612	)	137
	79,726		82,066		2,340
Net working capital
Inventories	5,495		5,517		22
Trade receivables	14,916		17,803		2,887
Trade payables	(10,078	)	(12,001	)	(1,923	)
Tax payables and provisions for net deferred tax liabilities	(1,988	)	(4,003	)	(2,015	)
Provisions	(10,319	)	(10,644	)	(325	)
Other current assets and liabilities (b)	(3,968	)	(3,297	)	671
	(5,942	)	(6,625	)	(683	)
Provisions for employee post-retirement benefits	(944	)	(964	)	(20	)
Net assets held for sale including related liabilities	266		897		631
CAPITAL EMPLOYED, NET	73,106		75,374		2,268
Shareholders’ equity
Eni shareholders’ equity	46,073		50,099		4,026
Non-controlling interest	3,978		4,223		245
	50,051		54,322		4,271
Net borrowings	23,055		21,052		(2,003	)
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	73,106		75,374		2,268

(a)	For the explanation of IFRIC 12 adoption, see the methodology note at page 5, under the second paragraph.
(b)	Include receivables and securities for financing operating activities for euro 181 million (euro 339 million at December 31, 2009) and securities covering technical reserves of Eni’s insurance activities for euro 444 million (euro 381 million at December 31, 2009).

The depreciation of the euro versus the US dollar, from December 31, 2009 (the EUR/USD exchange rate was 1.348 as of March 31, 2010, as compared to 1.441 as of December 31, 2009, down 7%) increased net capital employed, net equity and net borrowings by approximately euro 2,240 million, euro 1,870 million, and euro 370 million, respectively, as a result of exchange rate translation differences.

Fixed assets amounted to euro 82,066 million, representing an increase of euro 2,340 million from December 31, 2009 reflecting exchange rate translation differences and capital expenditures incurred in the period (euro 2,779 million), partly offset by depreciation, depletion, amortization and impairment charges (euro 2,184 million) recorded in the period.

Net working capital amounted to a negative euro 6,625 million, representing a decrease of euro 683 million. This decrease was mainly due to an increase in tax payable and provisions for net deferred tax liabilities accrued in the quarter, and the increased risk provisions due to exchange rate translation differences. These decreases were partly offset by a greater balance achieved between trade receivables and trade payables.

Net assets held for sale including related liabilities (euro 897 million) mainly related the following assets: the mineral properties in Italy which were contributed in kind to two subsidiaries Società Padana Energia SpA and Società Adriatica Idrocarburi SpA, the subsidiaries Gas Brasiliano Distribuidora SA and Distri RE SA, as well as the GreenStream gas pipeline, a stake of which is expected to be divested.

Shareholders’ equity including non-controlling interest increased by euro 4,271 million to euro 54,322 million, reflecting comprehensive income for the period (euro 4,276 million). This increase was as a result of net profit for the period (euro 2,419 million) and foreign currency exchange differences.

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

- 9 -

Summarized Group Cash Flow Statement⁵

Fourth Quarter (euro million) First Quarter

2009 2009 2010 Change

678		Net profit	2,110		2,419		309
		Adjustments to reconcile to cash generated from operating profit before changes in working capital:
3,282		- amortization and depreciation and other non monetary items	2,238		1,901		(337	)
58		- net gains on disposal of assets	(157	)	(169	)	(12	)
1,766		- dividends, interest and taxes	1,929		2,471		542
(1,691	)	Changes in working capital related to operations	964		(370	)	(1,334	)
(2,612	)	Dividends received, taxes paid, interest (paid) received during the period	(1,641	)	(1,698	)	(57	)
1,481		Net cash provided by operating activities	5,443		4,554		(889	)
(3,894	)	Capital expenditures	(3,147	)	(2,779	)	368
(46	)	Investments and purchase of consolidated subsidiaries and businesses	(2,039	)	(39	)	2,000
28		Disposals	182		729		547
214		Other cash flow related to capital expenditures, investments and disposals	1,745		(118	)	(1,863	)
(2,217	)	Free cash flow	2,184		2,347		163
13		Borrowings (repayment) of debt related to financing activities	102		(88	)	(190	)
2,167		Changes in short and long-term financial debt	(2,380	)	(1,484	)	896
(86	)	Dividends paid and changes in non-controlling interest and reserves	(2	)	13		15
(13	)	Effect of changes in consolidation and exchange differences	2		49		47
(136	)	NET CASH FLOW FOR THE PERIOD	(94	)	837		931

CHANGE IN NET BORROWINGS

Fourth Quarter (euro million) First Quarter

2009 2009 2010 Change

(2,217	)	Free cash flow	2,184		2,347		163
(212	)	Exchange differences on net borrowings and other changes	(334	)	(357	)	(23	)
(86	)	Dividends paid and changes in non-controlling interest and reserves	(2	)	13		15
(2,515	)	CHANGE IN NET BORROWINGS	1,848		2,003		155

Net cash provided by operating activities (euro 4,554 million) coupled with cash from divestments for euro 729 million, were mainly used to fund cash outflows relating to capital expenditures totaling euro 2,779 million and to pay down finance debt (euro 2,003 million). The divestments related to non strategic assets in the Exploration & Production division, as well as proceeds from the sale to Gazprom of a 51% interest in the joint-venture OOO SeverEnergia (euro 526 million).

Financial and operating information by division for the first quarter of 2010 is provided in the following pages.

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

- 10 -

Exploration & Production

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

RESULTS (euro million)

6,648		Net sales from operations		6,145		7,385		20.2
2,411		Operating profit		2,374		3,297		38.9
393		Exclusion of special items:		(201	)	(179	)
403		- asset impairments
8		- gains on disposal of assets		(163	)	(160	)
20		- provision for redundancy incentives		2		2
(38	)	- re-measurement gains/losses on commodity derivatives		(40	)	(21	)
2,804		Adjusted operating profit		2,173		3,118		43.5
(57	)	Net financial income (expense) (a)		33		(49	)
24		Net income from investments (a)		(12	)	67
(1,752	)	Income taxes (a)		(1,286	)	(1,891	)
63.2		Tax rate (%)		58.6		60.3
1,019		Adjusted net profit		908		1,245		37.1
		Results also include:
2,436		- amortizations and depreciations		1,686		1,680		(0.4	)
		of which:
350		exploration expenditure:		478		312		(34.7	)
269		- amortization of exploratory drilling expenditure and other		376		231		(38.6	)
81		- amortization of geological and geophysical exploration expenses		102		81		(20.6	)
2,490		Capital expenditures		2,148		1,964		(8.6	)
		of which:
284		- exploratory expenditure (b)		380		256		(32.6	)
		Production (c) (d)
1,073		Liquids (e)	(kbbl/d)	1,013		1,011		(0.2	)
4,668		Natural gas	(mmcf/d)	4,398		4,615		4.8
1,886		Total hydrocarbons	(kboe/d)	1,779		1,816		2.1
		Average realizations
68.42		Liquids (e)	($/bbl)	42.09		70.93		68.5
183.52		Natural gas	($/mmcf)	249.38		202.36		(18.9	)
52.24		Total hydrocarbons	($/boe)	41.46		54.28		30.9
		Average oil market prices
74.57		Brent dated	($/bbl)	44.40		76.24		71.7
50.45		Brent dated	(euro/bbl)	34.10		55.09		61.6
76.06		West Texas Intermediate	($/bbl)	42.97		78.67		83.1
153.27		Gas Henry Hub	($/kcm)	161.39		181.90		12.7

(a)	Excluding special items.
(b)	Includes exploration bonuses.
(c)	Supplementary operating data is provided on page 35.
(d)	Includes Eni’s share of production of equity-accounted entities.
(e)	Includes condensates.

Results

The Exploration & Production division reported adjusted operating profit amounting to euro 3,118 million for the first quarter of 2010, representing an increase of euro 945 million from the first quarter of 2009, or 43.5%. The positive performance was driven by higher oil realizations in dollars (up 68.5%) and production sales volumes growth (up 2.1 million boe). Lower expenses were also incurred in connection with exploration activities. These positives were partly offset by: (i) rising operating costs and amortization charges taken in connection with development activities as new fields were brought into production in 2009; (ii) foreign currency exchange rate translation differences as the euro appreciated over the dollar (down approximately euro 60 million); (iii) lower natural gas realizations in dollars (down 18.9%).

- 11 -

Special charges excluded from adjusted operating profit amounted to euro 179 million and mainly concerned gains from the divestment of certain non strategic assets as well as re-measurement gains recorded on fair value evaluation of certain non-hedging commodity derivatives.
First quarter adjusted net profit increased by euro 337 million to euro 1,245 million from the first quarter of 2009 due to an improvement in operating performance and higher results from associates. This increase was partly offset by a higher tax rate from 58.6% to 60.3%, (up 1.7 percentage points) mainly due to a higher share of profit before tax earned in foreign countries with higher taxation.

Operating review

Eni reported liquids and gas production of 1,816 kboe/d for the first quarter of 2010. Production grew by 2.1% as a result of continuing production ramp-up in Nigeria, Congo and the United States, and additions from fields which were started-up in 2009. These positive trends were partly offset by a combined negative impact associated with lower entitlements in Company’s PSAs due to higher oil prices, and lower OPEC restrictions. Also, production for the quarter was negatively affected by unplanned facility shutdowns and mature field declines, particularly in the North Sea. The share of oil and gas production outside Italy was 90% (90% in the first quarter of 2009).

Liquids production (1,011 kbbl/d) was barely unchanged (down 0.2%). Main increases were recorded in Nigeria, due to the ramp-up of the Oyo project (Eni’s interest 40%) and lower impact of disruptions resulting from security issues, and Congo, due to the ramp-up of the Awa Paloukou project (Eni’s interest 90%). The main reductions were recorded for mature fields decline in the North Sea and for the unplanned facility downtime in Algeria as well as price effects in the Company’s PSAs and similar contractual schemes net of lower OPEC restrictions mainly in Angola and Nigeria.

Natural gas production (4,615 mmcf/d) increased by 217 mmcf/d from the first quarter of 2009 (up 4.8%). The organic growth in Nigeria and the USA as well as higher entitlements in Libya were partially offset by declines in Egypt and North Sea.

Liquids and gas realizations for the first quarter in dollar terms (54.28 $/bbl) increased by 30.9% on average driven by higher oil prices for market benchmarks (the Brent crude price increased by 71.7%). Natural gas realizations were down by 18.9% driven by the time-lag between movements in oil prices and their effect on gas prices provided in pricing formulae and by weak demand.
Eni’s average liquids realizations decreased by 1.13 $/bbl due to the settlement of certain commodity derivatives relating to the sale of 7.1 mmbbl in the quarter. This was part of a derivative transaction the Company entered into to hedge exposure to the variability in future cash flows expected from the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmbbl in the 2008-2011 period, decreasing to approximately 30.4 mmbbl as of end of March 2010.

Fourth Quarter First Quarter

2009 2009 2010

LIQUIDS

95.4		Volumes sold	(mmbbl)	92.9	85.8
10.5		Sales volumes hedged by derivatives (cash flow hedge)		10.5	7.1
69.88		Total price per barrel, excluding derivatives	($/bbl)	40.63	72.06
(1.46	)	Realized gains (losses) on derivatives		1.46	(1.13	)
68.42		Total average price per barrel		42.09	70.93

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Gas & Power

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

RESULTS (euro million)

7,468		Net sales from operations		11,849		8,708		(26.5	)
1,004		Operating profit		1,253		1,316		5.0
(9	)	Exclusion of inventory holding (gains) losses		276		(81	)
132		Exclusion of special items:		(166	)	32
1		- environmental charges		2		5
27		- asset impairments				10
(1	)	- gains on disposal of assets
115		- risk provisions
13		- provision for redundancy incentives		3		6
(23	)	- re-measurement gains/losses on commodity derivatives		(171	)	11
1,127		Adjusted operating profit		1,363		1,267		(7.0	)
549		Marketing		774		614		(20.7	)
487		Regulated businesses in Italy (a)		469		533		13.6
91		International transport		120		120
4		Net finance income (expense) (b)		(6	)	(2	)
94		Net income from investments (b)		100		100
(373	)	Income taxes (b)		(469	)	(410	)
30.4		Tax rate (%)		32.2		30.0
852		Adjusted net profit		988		955		(3.3	)
591		Capital expenditures		390		310		(20.5	)
		Natural gas sales	(bcm)
24.31		Sales of consolidated subsidiaries		28.36		26.45		(6.7	)
10.01		Italy (includes own consumption)		13.21		10.87		(17.7	)
14.14		Rest of Europe		15.03		15.45		2.8
0.16		Outside Europe		0.12		0.13		8.3
2.26		Eni’s share of sales of natural gas of affiliates		2.50		2.46		(1.6	)
26.57		Total sales and own consumption (G&P)		30.86		28.91		(6.3	)
1.82		E&P in Europe and in the Gulf of Mexico		1.49		1.60		7.4
28.39		Worldwide gas sales		32.35		30.51		(5.7	)
21.56		Gas volumes transported in Italy	(bcm)	20.29		23.98		18.2
9.82		Eni		10.42		10.21		(2.0	)
11.74		On behalf of third parties		9.87		13.77		39.5
9.42		Electricity sales	(TWh)	7.78		9.00		15.7

(a)

From January 1, 2010, amortization and depreciation in the transportation business segment were determined taking into account an increase in the useful life of pipelines (from 40 to 50 years), which was revised recently by the Electricity and Gas Authority for tariff purposes. Taking into account the ways of recognizing tariff components linked to new amortization and depreciation, the company decided to adjust the useful life of these assets in line with the conventional tariff duration.

(b)

Excluding special items.

Results

In the first quarter of 2010 the Gas & Power division reported adjusted operating profit of euro 1,267 million, a decrease of euro 96 million from the first quarter of 2009, down 7%, due to a lower performance delivered by the Marketing business. Results from that business did not take into account certain gains recorded in previous quarters on the settlement of non-hedging commodity and exchange rate derivatives amounting to euro 21 million for the first quarter 2010 which could be associated with the sale of gas and electricity occurring in the quarter. With respect to those derivatives, hedge-accounting is not permitted by IFRS as they do not meet all formal criteria to be designated as hedges. If the Company had followed hedge-accounting, those gains would have impacted realized prices in the quarter. However, in assessing the underlying performance of the Marketing business, management calculates (as an alternative measure of performance) the EBITDA pro-forma adjusted, by carrying over the impact of the settlement of those derivatives to the reporting periods where the associated revenues have been recognized. Management

- 13 -

believes that disclosing this internally used measure is helpful in assisting investors to understand these business trends (see page 16). The EBITDA pro-forma adjusted delivered by the Marketing business in the first quarter 2010 showed a sharp decline compared to the first quarter 2009 due to rising competitive pressures in Italy, determining both lower sales volumes (down 17.7%) and reduced margins, as well as an unfavorable scenario, partly offset by the impact of the renegotiation of a number of long-term supply contracts and supply optimization measures.

Special items excluded from operating profit amounted to net charges of euro 32 million. These mainly related to the impact on fair value evaluation of certain non-hedging commodity derivatives in the Marketing business (euro 11 million), provisions for both redundancy incentives and environmental charges, and minor impairments.

Adjusted net profit for the first quarter 2010 was euro 955 million, declining by euro 33 million from 2009 (down 3.3%) due to a weaker operating performance which was partly offset by a lower adjusted tax rate (from 32.2% to 30%).

Operating review

Marketing
This business reported adjusted operating profit of euro 614 million for the first quarter of 2010, representing a decrease of euro 160 million from the first quarter of 2009 (down 20.7%). In considering the impact associated with the above mentioned non-hedging commodity derivatives, the following factors had a negative effect on Marketing results:

(i)	A sharp reduction in volumes sold in Italy (down 2.34 million cubic meters, or 17.7%) and declining margins as competitive pressures mounted.
(ii)	Gas margins were negatively affected by unfavorable trends in energy parameters provided in contractual pricing formulae.

These negatives were partly offset by the impact of the renegotiation of a number of long-term supply contracts and supply optimization measures.

NATURAL GAS SALES BY MARKET

(bcm)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

10.01	ITALY	13.21	10.87	(17.7	)
1.47	Wholesalers	2.81	1.93	(31.3	)
0.41	Gas release	0.41	0.40	(2.4	)
1.35	Italian exchange for gas and spot markets	0.10	1.04	..
1.62	Industries	2.12	1.58	(25.5	)
0.39	Medium-sized enterprises and services	0.48	0.52	8.3
1.29	Power generation	2.65	0.75	(71.7	)
1.98	Residential	3.13	3.11	(0.6	)
1.50	Own consumption	1.51	1.54	2.0
18.38	INTERNATIONAL SALES	19.14	19.64	2.6
15.97	Rest of Europe	17.18	17.61	2.5
2.64	Importers in Italy	3.41	3.22	(5.6	)
13.33	European markets	13.77	14.39	4.5
1.64	Iberian Peninsula	1.55	1.63	5.2
1.59	Germany-Austria	1.73	1.82	5.2
4.75	Belgium	5.10	5.22	2.4
0.82	Hungary	1.29	1.09	(15.5	)
1.31	Northern Europe	0.97	1.41	45.4
1.30	Turkey	1.30	0.98	(24.6	)
1.53	France	1.34	1.77	32.1
0.39	Other	0.49	0.47	(4.1	)
0.59	Extra European markets	0.47	0.43	(8.5	)
1.82	E&P in Europe and in the Gulf of Mexico	1.49	1.60	7.4
28.39	WORLDWIDE GAS SALES	32.35	30.51	(5.7	)

- 14 -

Sales of natural gas for the first quarter 2010 were 30.51 bcm, a decrease of 1.84 bcm from the first quarter of 2009, down 5.7%. This was mainly as a result of rising competitive pressures in Italy, partly offset by steady trends in sales on the European markets. Sales included own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and the Gulf of Mexico.
Sales volumes on the Italian market declined by 2.34 bcm, or 17.7%, to 10.87 bcm due to strong competitive pressures also resulting from the greater availability of gas on the marketplace following the start-up of a new regasification plant offshore of the Adriatic Coast in the fourth quarter of 2009 and the upgrade of import pipelines coming on-stream. Eni suffered lower sales to the power generation business (down 1.90 bcm), wholesalers (down 0.88 bcm) and, to a lesser extent, to industrial customers (down 0.54 bcm), sales volumes to the residential sector were barely unchanged.

International sales were up 0.50 bcm, or 2.6%, to 19.64 bcm, benefiting from organic growth achieved on target markets in the Rest of Europe (up 0.62 bcm, or 4.5%) particularly in Northern Europe (up 0.44 bcm), France (up 0.43 bcm) where ongoing marketing initiatives helped boost sales, and Belgium (up 0.12 bcm). Sales declined in Turkey (down 0.32 bcm) and Hungary (down 0.20 bcm).

First quarter 2010 electricity sales increased to 9 TWh (up 15.7%) compared with the first quarter of 2009. Eni’s sales were driven by higher sales traded on the Italian power exchange. Sales on the open market declined marginally, in particular in the wholesalers segment, while sales to large and retail clients increased following effective marketing campaigns with sales benefiting from the greater availability of power from Eni’s production plants.

Regulated businesses in Italy
These businesses reported an adjusted operating profit of euro 533 million for the first quarter of 2010, up euro 64 million, or 13.6% from the same period of 2009, due to a new tariff mechanism that recognizes the fuel gas and higher volumes transported (up euro 58 million) reflecting a recovery in gas demand in Italy. The Distribution business reported unchanged results versus the first quarter of 2009 (euro 120 million). The Storage business reported adjusted operating profit of euro 90 million in the first quarter of 2009 (euro 84 million in the first quarter of 2010).

Volumes of gas transported in Italy in the first quarter of 2010 were 23.98 bcm increasing by 3.69 bcm, or 18.2%, from the first quarter of 2009 reflecting seasonal sales and higher gas offtakes from domestic storage deposits.

In the first quarter of 2010, 4.83 bcm of gas were supplied (up 1.22 bcm from the first quarter of 2009) while 0.26 bcm were inputted to Company’s storage deposits, an increase of 0.23 bcm compared to the same period of 2009.

- 15 -

Other performance indicators

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

1,159		Pro-forma adjusted EBITDA	1,720	1,432	(16.7	)
623		Marketing	1,184	856	(27.7	)
(143	)	of which: +/(-) adjustment on commodity derivatives	175	21
363		Regulated businesses in Italy	343	379	10.5
173		International transport	193	197	2.1

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 discussed below.
This performance indicator includes the adjusted EBITDA of Eni’s wholly owned subsidiaries and Eni’s share of adjusted EBITDA generated by certain associates which are accounted for under the equity method for IFRS purposes. Snam Rete Gas’ EBITDA is included according to Eni’s share of equity (55.57% as of December 31, 2009, which takes into account the amount of own shares held in treasury by the subsidiary itself) although this Company is fully consolidated when preparing consolidated financial statements in accordance with IFRS, due to its listed company status. Italgas SpA and Stoccaggi Gas Italia SpA results are also included according to the same share of equity as Snam Rete Gas, due to the closing of the restructuring deal which involved Eni’s regulated business in the Italian gas sector. The parent company Eni SpA divested the entire share capital of the two subsidiaries to Snam Rete Gas. 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 proforma adjusted relating to the reporting periods during which those supplies at fixed prices are recognized. Management believes that the EBITDA pro-forma adjusted is an important alternative measure to assess the performance of Eni’s Gas & Power division, taking into account evidence that this division is comparable to European utilities in the gas and power generation sector. This measure is provided in order to assist investors and financial analysts in assessing the Eni Gas & Power divisional performance 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.

- 16 -

Refining & Marketing

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

RESULTS (euro million)

9,066		Net sales from operations		6,386		9,346		46.4
(423	)	Operating profit (a)		240		105		(56.3	)
(152	)	Exclusion of inventory holding (gains) losses		(209	)	(232	)
379		Exclusion of special items:		24		33
31		- environmental charges		7		17
325		- asset impairments		6		22
(1	)	- gains on disposal of assets		(1	)	(10	)
2		- risk provisions
11		- provision for redundancy incentives		5		2
11		- re-measurement gains/losses on commodity derivatives		7		2
(196	)	Adjusted operating profit		55		(94	)	..
14		Net income from investments (b)		35		45
64		Income taxes (b)		(22	)	19
35.2		Tax rate (%)		24.4		..
(118	)	Adjusted net profit		68		(30	)	..
254		Capital expenditures		85		118		38.8
		Global indicator refining margin
1.24		Brent	($/bbl)	5.34		2.40		(55.1	)
0.84		Brent	(euro/bbl)	4.10		1.74		(57.6	)
1.80		Brent/Ural	($/bbl)	6.28		3.20		(49.0	)
		Refining throughputs and sales	(mmtonnes)
5.97		Refining throughputs of wholly-owned refineries		5.72		5.86		2.4
7.30		Refining throughputs on own account Italy		7.05		6.88		(2.4	)
1.31		Refining throughputs on own account Rest of Europe		1.28		1.26		(1.6	)
8.61		Refining throughputs on own account		8.33		8.14		(2.3	)
2.26		Retail sales Italy		2.10		2.01		(4.3	)
0.74		Retail sales Rest of Europe		0.69		0.67		(2.9	)
3.00		Total retail sales in Europe		2.79		2.68		(3.9	)
2.47		Wholesale Italy		2.41		2.04		(15.4	)
0.96		Wholesale Rest of Europe		0.91		0.86		(5.5	)
3.43		Total wholesale in Europe		3.32		2.90		(12.7	)
0.10		Wholesale other		0.09		0.09
5.59		Other sales		4.77		5.20		9.0
12.12		SALES		10.97		10.87		(0.9	)
		Refined product sales by region
6.90		Italy		6.18		6.17		(0.2	)
1.70		Rest of Europe		1.60		1.53		(4.4	)
3.52		Rest of World		3.19		3.17		(0.6	)

(a)

From January 1, 2010, management has reviewed the residual useful lives of refineries and related facilities due to a change in the expected pattern of consumption of the expected future economic benefit embodied in those assets. In doing so, the Company has aligned with practices prevailing among integrated oil companies, particularly the European companies. Management’s conclusions have been supported by an independent technical review. The impact on quarterly results was immaterial.

(b)

Excluding special items.

Results

In the first quarter of 2010 Refining & Marketing reported an adjusted operating loss amounting to euro 94 million, reversing a prior year profit of euro 55 million. The marked decrease (down euro 149 million from the first quarter of 2009) was driven by lower refining margins due to the decrease in the relative prices of products to oil feedstock costs due to weak industry fundamentals associated with excess capacity, sluggish demand and high inventory levels partly offset by improved light-heavy crude differentials. Quarterly results were also affected by lower operating performance delivered by the Marketing activities, due to weak demand in retail and wholesale markets, in Italy and outside Italy, as well as a reduction of the market share in Italy.

- 17 -

Special charges excluded from adjusted operating loss amounted to euro 33 million and mainly related to impairment of capital expenditures on assets impaired in previous reporting periods, environmental provisions, and provisions for redundancy incentives.

In the first quarter of 2010, adjusted net loss was euro 30 million (down euro 98 million from the first quarter of 2009) mainly due to a lower operating performance partly offset by higher earnings reported by equity-accounted entities.

Operating review

Eni’s refining throughputs for the first quarter of 2010 were 8.14 mmtonnes, down 2.3% from the first quarter of 2009. Lower volumes were processed in Italy (down 2.4%) reflecting termination of a processing contract on a third-party refinery. Volumes processed outside Italy decreased by 1.6% particularly at Eni’s plants in the Czech Republic due to lower capacity utilization in response to weak market demand.
The capacity utilization rate of Italian refineries was lower compared with the first quarter of 2009 as Eni’s main refineries at Taranto, Sannazzaro and Gela lowered processed volumes.

Retail sales in Italy (2.01 mmtonnes) decreased by approximately 90 ktonnes, down 4.3%, driven by lower demand of both gasoline and gasoil. Eni’s retail market share for the first quarter was 30.5%, down 1 percentage point from the first quarter 2009 (31.5%).
Wholesale sales in Italy (2.04 mmtonnes) decreased by 370 ktonnes, down 15.4%, due to lower demand reflecting challenging economic conditions.

Retail sales in the rest of Europe (670 ktonnes) decreased by approximately 20 ktonnes, or 2.9%, mainly reflecting a decline in fuel demand, in particular in Germany, Hungary and Czech Republic.
Wholesale sales in the rest of Europe (860 ktonnes) decreased by approximately 50 ktonnes, mainly in the Czech Republic, Switzerland and Slovenia.

- 18 -

Summarized Group profit and loss account

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

22,077		Net sales from operations	23,741		24,804		4.5
284		Other income and revenues	360		285		(20.8	)
(16,728	)	Operating expenses	(17,973	)	(18,096	)	(0.7	)
(250	)	of which non recurring items
94		Other operating income (expense)	17		38		..
(3,261	)	Depreciation, depletion, amortization and impairments	(2,178	)	(2,184	)	(0.3	)
2,466		Operating profit	3,967		4,847		22.2
(157	)	Finance income (expense)	(30	)	(245	)	..
17		Net income from investments	144		225		56.3
2,326		Profit before income taxes	4,081		4,827		(18.3	)
(1,648	)	Income taxes	(1,971	)	(2,408	)	(22.2	)
n.s.		Tax rate (%)	48.3		49.9
678		Net profit	2,110		2,419		14.6
391		- Net profit attributable to Eni’s shareholders	1,904		2,222		16.7
287		- Net profit attributable to non-controlling interests	206		197		(4.4	)
391		Net profit attributable to Eni’s shareholders	1,904		2,222		16.7
(31	)	Exclusion of inventory holding (gains) losses	91		(280	)
1,034		Exclusion of special items	(236	)	(120	)
		of which:
250		- non recurring items
784		- other special items	(236	)	(120	)
1,394		Adjusted net profit attributable to Eni’s shareholders (a)	1,759		1,822		3.6

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

- 19 -

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 of 34% is applied to finance charges and income. Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or U.S. GAAP.
Management includes them in order to facilitate a comparison of base business performance across periods and allow financial analysts to evaluate Eni’s 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 management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives, including the ineffective portion of cash flow hedges.

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.

- 20 -

First quarter 2010	E&P	G&P	R&M	Petrochemicals	Engineering & Construction	Other activities	Corporate and financial companies	Impact of unrealized intragroup profit elimination	Group
(euro million)

Reported operating profit	3,297		1,316		105		36		291		(60	)	(70	)	(68	)	4,847
Exclusion of inventory holding (gains) losses			(81	)	(232	)	(96	)									(409	)
Exclusion of special items:
environmental charges			5		17												22
asset impairments			10		22												32
gains on disposal of assets	(160	)			(10	)											(170	)
provision for redundancy incentives	2		6		2		1				1		5				17
re-measurement gains/losses on commodity derivatives	(21	)	11		2				(2	)							(10	)
other											2						2
Special items of operating profit	(179	)	32		33		1		(2	)	3		5				(107	)
Adjusted operating profit	3,118		1,267		(94	)	(59	)	289		(57	)	(65	)	(68	)	4,331
Net finance (expense) income (a)	(49	)	(2	)									(194	)			(245	)
Net income from investments (a)	67		100		45				2		(4	)					210
Income taxes (a)	(1,891	)	(410	)	19		16		(94	)			57		26		(2,277	)
Tax rate (%)	60.3		30.0		..				32.3								53.0
Adjusted net profit	1,245		955		(30	)	(43	)	197		(61	)	(202	)	(42	)	2,019
of which:
- adjusted net profit of non-controlling interest																	197
- Eni’s shareholders adjusted net profit																	1,822
Eni reported net profit																	2,222
Exclusion of inventory holding (gains) losses																	(280	)
Exclusion of special items																	(120	)
Eni’s adjusted net profit																	1,822

(a) Excluding special items.

- 21 -

First quarter 2009	E&P	G&P	R&M	Petrochemicals	Engineering & Construction	Other activities	Corporate and financial companies	Impact of unrealized intragroup profit elimination	Group
(euro million)

Reported operating profit	2,374		1,253		240		(167	)	270		(55	)	(63	)	115		3,967
Exclusion of inventory holding (gains) losses			276		(209	)	58										125
Exclusion of special items:
environmental charges			2		7												9
asset impairments					6						1						7
gains on disposal of assets	(163	)			(1	)					(1	)					(165	)
provision for redundancy incentives	2		3		5		1						5				16
re-measurement gains/losses on commodity derivatives	(40	)	(171	)	7		(3	)	2								(205	)
Special items of operating profit	(201	)	(166	)	24		(2	)	2				5				(338	)
Adjusted operating profit	2,173		1,363		55		(111	)	272		(55	)	(58	)	115		3,754
Net finance (expense) income (a)	33		(6	)							30		(87	)			(30	)
Net income from investments (a)	(12	)	100		35				8								131
Income taxes (a)	(1,286	)	(469	)	(22	)	16		(57	)			(29	)	(43	)	(1,890	)
Tax rate (%)	58.6		32.2		24.4				20.4								49.0
Adjusted net profit	908		988		68		(95	)	223		(25	)	(174	)	72		1,965
of which:
- adjusted net profit of non-controlling interest																	206
- Eni’s shareholders adjusted net profit																	1,759
Eni reported net profit																	1,904
Exclusion of inventory holding (gains) losses																	91
Exclusion of special items																	(236	)
Eni’s adjusted net profit																	1,759

(a) Excluding special items.

- 22 -

Fourth quarter 2009	E&P	G&P	R&M	Petrochemicals	Engineering & Construction	Other activities	Corporate and financial companies	Impact of unrealized intragroup profit elimination	Group
(euro million)

Reported operating profit	2,411		1,004		(423	)	(161	)	27		(177	)	(153	)	(62	)	2,466
Exclusion of inventory holding (gains) losses			(9	)	(152	)	26										(135	)
Exclusion of special items:
of which:
Non-recurring (income) charges									250								250
Other special (income) charges:	393		132		379		31		7		111		68				1,121
environmental charges			1		31						108		54				194
asset impairments	403		27		325		24		2		(1	)					780
gains on disposal of assets	8		(1	)	(1	)			7								13
risk provisions			115		2												117
provision for redundancy incentives	20		13		11		7				4		18				73
re-measurement gains/losses on commodity derivatives	(38	)	(23	)	11				(2	)							(52	)
other													(4	)			(4	)
Special items of operating profit	393		132		379		31		257		111		68				1,371
Adjusted operating profit	2,804		1,127		(196	)	(104	)	284		(66	)	(85	)	(62	)	3,702
Net finance (expense) income (a)	(57	)	4								(16	)	(88	)			(157	)
Net income from investments (a)	24		94		14				20		(1	)					151
Income taxes (a)	(1,752	)	(373	)	64		19		(75	)			78		24		(2,015	)
Tax rate (%)	63.2		30.4		..				24.7								54.5
Adjusted net profit	1,019		852		(118	)	(85	)	229		(83	)	(95	)	(38	)	1,681
of which:
- adjusted net profit of non-controlling interest																	287
- Eni’s shareholders adjusted net profit																	1,394
Eni reported net profit																	391
Exclusion of inventory holding (gains) losses																	(31	)
Exclusion of special items:																	1,034
- non-recurring (income) charges																	250
- other special (income) charges																	784
Eni’s adjusted net profit																	1,394

(a) Excluding special items.

- 23 -

Breakdown of special items

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

250		Non-recurring charges (income)
250		of which: estimated charge of the possible resolution of the TSKJ matter
1,121		Other special charges (income):	(338	)	(107	)
780		asset impairments	7		32
194		environmental charges	9		22
13		gains on disposal of property, plant and equipment	(165	)	(170	)
117		risk provisions
73		provisions for redundancy incentives	16		17
(52	)	re-measurement gains/losses on commodity derivatives	(205	)	(10	)
(4	)	other			2
1,371		Special items of operating profit	(338	)	(107	)
148		Net income from investments	(10	)
(485	)	Income taxes	112		(13	)
		of which:
72		deferred tax assets E&P
(192	)	other special items
(365	)	taxes on special items of operating profit	112		(13	)
1,034		Total special items of net profit	(236	)	(120	)

Adjusted operating profit

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

2,804		Exploration & Production	2,173		3,118		43.5
1,127		Gas & Power	1,363		1,267		(7.0	)
(196	)	Refining & Marketing	55		(94	)	..
(104	)	Petrochemicals	(111	)	(59	)	46.8
284		Engineering & Construction	272		289		6.3
(66	)	Other activities	(55	)	(57	)	(3.6	)
(85	)	Corporate and financial companies	(58	)	(65	)	(12.1	)
(62	)	Impact of unrealized intragroup profit elimination	115		(68	)
3,702			3,754		4,331		15.4

- 24 -

Net sales from operations

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

6,648		Exploration & Production	6,145		7,385		20.2
7,468		Gas & Power	11,849		8,708		(26.5	)
9,066		Refining & Marketing	6,386		9,346		46.4
1,136		Petrochemicals	878		1,476		68.1
2,400		Engineering & Construction	2,415		2,512		4.0
21		Other activities	26		25		(3.8	)
359		Corporate and financial companies	309		302		(2.3	)
(50	)	Impact of unrealized intragroup profit elimination	(14	)	64
(4,971	)	Consolidation adjustment	(4,253	)	(5,014	)
22,077			23,741		24,804		4.5

Operating expenses

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

15,636	Purchases, services and other	16,983	17,051	0.4
	of which:
250	- non-recurring items
411	- other special items	9	37
1,092	Payroll and related costs	990	1,045	5.6
	of which:
73	- provision for redundancy incentives	16	17
16,728		17,973	18,096	0.7

Gains and losses on non-hedging commodity derivate instruments

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

37		Exploration & Production	40		21
(1	)	- settled transactions	(36	)	19
38		- re-measurement gains/losses	(207	)	30
78		Gas & Power	171		(11	)
55		- settled transactions	3		(5	)
23		- re-measurement gains/losses	10		(3	)
(21	)	Refining & Marketing	(7	)	(2	)
(10	)	- settled transactions	9		1
(11	)	- re-measurement gains/losses	6		1
1		Petrochemicals	3
1		- settled transactions	(3	)	2
		- re-measurement gains/losses	(1	)
(1	)	Engineering & Construction	(2	)	2
(3	)	- settled transactions	17		38
2		- re-measurement gains/losses	(188	)	28
94		Total	205		10
42		- settled transactions
52		- re-measurement gains/losses

- 25 -

Depreciation, depletion, amortization and impairments

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

2,064		Exploration & Production	1,686		1,680		(0.4	)
261		Gas & Power	240		244		1.7
109		Refining & Marketing	99		80		(19.2	)
19		Petrochemicals	24		19		(20.8	)
111		Engineering & Construction	107		114		6.5
		Other activities			1
22		Corporate and financial companies	19		18		(5.3	)
(5	)	Impact of unrealized intragroup profit elimination	(4	)	(4	)
2,581		Total depreciation, depletion and amortization	2,171		2,152		(0.9	)
680		Impairments	7		32
3,261			2,178		2,184		0.3

Net income from investments

(euro million)

Exploration
& Production Gas & Power Refining
& Marketing Engineering
& Construction Other activities Group

Share of gains (losses) from equity-accounted investments	56		98	32	2	(4	)	184
Dividends	12		2	28				42
Other income (expense), net	(1	)						(1	)
	67		100	60	2	(4	)	225

Income taxes

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

		Profit before income taxes
(146	)	Italy	1,595	1,151	(444	)
2,472		Outside Italy	2,486	3,676	1,190
2,326			4,081	4,827	746
		Income taxes
(3	)	Italy	666	450	(216	)
1,651		Outside Italy	1,305	1,958	653
1,648			1,971	2,408	437
		Tax rate (%)
n.s.		Italy	41.8	39.1	(2.7	)
66.8		Outside Italy	52.5	53.3	0.8
n.s.			48.3	49.9	1.6

- 26 -

Leverage and net borrowings

Leverage is a measure used by management to assess the Company’s level of indebtedness. It is calculated as 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 minority 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.

(euro million)

Dec. 31, 2009 March 31, 2010 Change

Total debt	24,800		23,723		(1,077	)
Short-term debt	6,736		7,708		972
Long-term debt	18,064		16,015		(2,049	)
Cash and cash equivalents	(1,608	)	(2,445	)	(837	)
Securities held for non-operating purposes	(64	)	(57	)	7
Financing receivables for non-operating purposes	(73	)	(169	)	(96	)
Net borrowings	23,055		21,052		(2,003	)
Shareholders’ equity including non-controlling interest	50,051		54,322		4,271
Leverage	0.46		0.39		(0.07	)

Bonds maturing in the 18-months period starting on March 31, 2010

(euro million)
Issuing entity	Amount at March 31, 2010 (a)
Eni SpA	525
Eni Coordination Center SA	482
	1,007

(a) Amounts in euro at March 31, 2010 include interest accrued and discount on issue.

- 27 -

Return On Average Capital Employed (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 minority interest, 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% effective from January 1, 2009. The capital invested as of 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 division specific tax rate).

(euro million)

Calculated on a 12-month period ending on
March 31, 2010 Exploration & Production Gas &Power Refining & Marketing Group

Adjusted net profit	4,215	2,883	(295	)	6,211
Exclusion of after-tax finance expenses/interest income	-	-	-		316
Adjusted net profit unlevered	4,215	2,883	(295	)	6,527
Adjusted capital employed, net:
- at the beginning of period	33,667	22,300	7,120		68,534
- at the end of period	34,572	25,107	7,306		74,812
Adjusted average capital employed, net	34,120	23,704	7,213		71,673
Adjusted ROACE (%)	12.4	12.2	(4.1	)	9.1

(euro million)

Calculated on a 12-month period ending on
March 31, 2009 Exploration & Production Gas &Power Refining & Marketing Group

Adjusted net profit	3,878	2,916	(197	)	6,157
Exclusion of after-tax finance expenses/interest income	-	-	-		283
Adjusted net profit unlevered	3,878	2,916	(197	)	6,440
Adjusted capital employed, net:
- at the beginning of period	30,362	22,547	7,379		66,886
- at the end of period	32,455	25,024	7,560		72,915
Adjusted average capital employed, net	31,409	23,786	7,470		69,901
Adjusted ROACE (%)	12.3	12.3	(2.6	)	9.2

- 28 -

GROUP BALANCE SHEET

(euro million)

Dec. 31, 2009 Mar. 31, 2010

ASSETS
Current assets
Cash and cash equivalents	1,608		2,445
Other financial assets held for trading or available for sale	348		346
Trade and other receivables	20,348		23,660
Inventories	5,495		5,517
Current tax assets	753		371
Other current tax assets	1,270		937
Other current assets	1,307		1,362
Total current assets	31,129		34,638
Non-current assets
Property, plant and equipment	59,765		62,033
Inventory - compulsory stock	1,736		1,873
Intangible assets	11,469		11,446
Equity-accounted investments	5,828		5,592
Other investments	416		434
Other financial assets	1,148		1,077
Deferred tax assets	3,558		3,603
Other non-current receivables	1,938		2,004
Total non-current assets	85,858		88,062
Assets held for sale	542		1,253
TOTAL ASSETS	117,529		123,953
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	3,545		4,535
Current portion of long-term debt	3,191		3,173
Trade and other payables	19,174		20,383
Income taxes payable	1,291		1,619
Other taxes payable	1,431		2,162
Other current liabilities	1,856		1,925
Total current liabilities	30,488		33,797
Non-current liabilities
Long-term debt	18,064		16,015
Provisions for contingencies	10,319		10,644
Provisions for employee benefits	944		964
Deferred tax liabilities	4,907		5,106
Other non-current liabilities	2,480		2,749
Total non-current liabilities	36,714		35,478
Liabilities directly associated with assets held for sale	276		356
TOTAL LIABILITIES	67,478		69,631
SHAREHOLDERS’ EQUITY
Non-controlling interest	3,978		4,223
Eni shareholders’ equity
Share capital	4,005		4,005
Reserves	46,269		50,432
Treasury shares	(6,757	)	(6,757	)
Interim dividend	(1,811	)
Net profit	4,367		2,419
Total Eni shareholders’ equity	46,073		50,099
TOTAL SHAREHOLDERS’ EQUITY	50,051		54,322
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	117,529		123,953

- 29 -

GROUP PROFIT AND LOSS ACCOUNT

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

REVENUES
Net sales from operations	23,741		24,804
Other income and revenues	360		285
Total revenues	24,101		25,089
OPERATING EXPENSES
Purchases, services and other	16,983		17,051
Payroll and related costs	990		1,045
OTHER OPERATING (CHARGE) INCOME	17		38
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS	2,178		2,184
OPERATING PROFIT	3,967		4,847
FINANCE INCOME (EXPENSE)
Finance income	2,087		1,363
Finance expense	(2,095	)	(1,422	)
Derivative financial instruments	(22	)	(186	)
INCOME (EXPENSE) FROM INVESTMENTS
Share of profit (loss) of equity-accounted investments	113		184
Other gain (loss) from investments	31		41
	144		225
PROFIT BEFORE INCOME TAXES	4,081		4,827
Income taxes	(1,971	)	(2,408	)
Net profit	2,110		2,419
Net profit attributable to Eni	1,904		2,222
Net profit attributable to non-controlling interest	206		197
	2,110		2,419
Earnings per share attributable to Eni (euro per share)
Basic	0.53		0.61
Diluted	0.53		0.61

COMPREHENSIVE INCOME

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

Net profit	2,110		2,419
Other items of comprehensive income
Foreign currency translation differences	1,120		1,870
Change in the fair value of cash flow hedging derivatives	36		(23	)
Taxation	(17	)	10
Other comprehensive income	1,139		1,857
Total comprehensive income	3,249		4,276
Attributable to:
- Eni shareholders’ equity	3,044		4,036
- Non-controlling interest	205		240
	3,249		4,276

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GROUP CASH FLOW STATEMENT

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

Net profit	2,110		2,419
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation, depletion and amortization	2,171		2,152
Impairments of tangible and intangible assets, net	7		32
Share of profit (loss) of equity-accounted investments	113		(184	)
Gain on disposal of assets, net	(157	)	(169	)
Dividend income	(17	)	(43	)
Interest income	(240	)	(39	)
Interest expense	215		145
Income taxes	1,971		2,408
Other changes	(43	)	(95	)
Changes in working capital:
- inventories	1,341		(120	)
- trade receivables	245		(1,930	)
- trade payables	(427	)	1,436
- provisions for contingencies	6		56
- other assets and liabilities	(201	)	188
Cash flow from changes in working capital	964		(370	)
Net change in the provisions for employee benefits	(10	)	(4	)
Dividends received	17		35
Interest received	75		47
Interest paid	(121	)	(143	)
Income taxes paid, net of tax receivables received	(1,612	)	(1,637	)
Net cash provided from operating activities	5,443		4,554
Investing activities:
- tangible assets	(2,742	)	(2,447	)
- intangible assets	(405	)	(332	)
- investments	(48	)	(39	)
- securities	(1	)	(4	)
- financing receivables	(676	)	(366	)
- change in payables and receivables in relation to investments and capitalized depreciation	1,794		(104	)
Cash flow from investments	(2,078	)	(3,292	)
Disposals:
- tangible assets	27		203
- intangible assets	145
- investments	10		526
- securities	87		6
- financing receivables	611		306
- change in payables and receivables in relation to disposals	32		(44	)
Cash flow from disposals	912		997
Net cash used in investing activities (*)	(1,166	)	(2,295	)

- 31 -

GROUP CASH FLOW STATEMENT (continued)

(euro million)

First Quarter

2009 2010

Proceeds from long-term debt	1,867		22
Repayments of long-term debt	(2,718	)	(2,198	)
Increase (decrease) in short-term debt	(1,529	)	692
	(2,380	)	(1,484	)
Net capital contributions by non-controlling interest	(2	)
Net acquisition of treasury shares different from Eni SpA			13
Acquisition of additional interests in consolidated subsidiaries	(1,991	)
Net cash used in financing activities	(4,373	)	(1,471	)
Effect of exchange rate changes on cash and cash equivalents and other changes	2		49
Net cash flow for the period	(94	)	837
Cash and cash equivalents - beginning of the period	1,939		1,608
Cash and cash equivalents - end of the period	1,845		2,445

(*) Net cash used in investing activities included investments in certain financial assets to absorb temporary surpluses of cash or as a part of our ordinary management of financing activities. Due to their nature and circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. Cash flows of such investments were as follows:

(euro million) First Quarter

2009 2010

Financing investments:
- securities	(1	)
- financing receivables	(183	)	(106	)
	(184	)	(106	)
Disposal of financing investments:
- securities	72		6
- financing receivables	214		12
	286		18
Net cash flows from financing activities	102		(88	)

- 32 -

CAPITAL EXPENDITURES

(euro million)

Fourth Quarter First Quarter

2009 2009 2010 % Ch.

2,490	Exploration & Production	2,148	1,964		(8.6	)
591	Gas & Power	390	310		(20.5	)
254	Refining & Marketing	85	118		38.8
64	Petrochemicals	9	26		..
409	Engineering & Construction	495	412		(16.8	)
25	Other activities	6	9		50.0
22	Corporate and financial companies	10	17		70.0
39	Impact of unrealized intragroup profit elimination	4	(77	)
3,894		3,147	2,779		(11.7	)

In the first quarter of 2010, capital expenditures amounting to euro 2,779 million (euro 3,147 million in the first quarter of 2009) related mainly to:

- development activities (euro 1,693 million) deployed mainly in Congo, Kazakhstan, Algeria, Egypt, the United States, Italy and Norway and exploratory activities (euro 256 million) of which 97% was spent outside Italy, primarily in the United States, Angola, Indonesia, Ghana and Pakistan;

- development and upgrading of Eni’s natural gas transport network in Italy (euro 164 million) and distribution network (euro 58 million), as well as development and increase of storage capacity (euro 46 million);

- projects aimed at improving the conversion capacity and flexibility of refineries (euro 95 million), as well as building and upgrading service stations in Italy and outside Italy (euro 17 million);

- upgrading of the fleet used in the Engineering & Construction division (euro 412 million).

- 33 -

Capital expenditures by division

EXPLORATION & PRODUCTION

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

207	Acquisitions of proved and unproved property	9
113	North Africa	6
94	Rest of Asia
	America	3
284	Exploration	380	256
6	Italy	21	8
14	Rest of Europe	24	15
37	North Africa	112	21
123	West Africa	75	76
4	Kazakhstan	5	2
29	Rest of Asia	60	53
68	America	54	80
3	Australia and Oceania	29	1
1,968	Development	1,744	1,693
203	Italy	174	142
188	Rest of Europe	137	161
315	North Africa	378	421
760	West Africa	387	504
241	Kazakhstan	232	220
83	Rest of Asia	150	63
118	America	188	167
60	Australia and Oceania	98	15
31	Other expenditures	15	15
2,490		2,148	1,964

GAS & POWER

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

545	Italy	371	283
46	Outside Italy	19	27
591		390	310
73	Marketing	24	42
42	- Marketing	10	27
4	Italy
38	Outside Italy	10	27
31	- Power generation	14	15
510	Regulated businesses in Italy	357	268
358	- Transport	237	164
70	- Distribution	65	58
82	- Storage	55	46
8	International transport	9
591		390	310

REFINING & MARKETING

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

231	Italy	77	112
23	Outside Italy	8	6
254		85	118
174	Refining, Supply and Logistic	48	95
174	Italy	48	95
75	Marketing	26	17
52	Italy	18	11
23	Outside Italy	8	6
5	Other activities	11	6
254		85	118

- 34 -

Exploration & Production

PRODUCTION OF OIL AND NATURAL GAS BY REGION

Fourth Quarter First Quarter

2009 2009 2010

1,886	Production of oil and natural gas (a) (b)	(kboe/d)	1,779	1,816
173	Italy		174	178
255	Rest of Europe		256	240
565	North Africa		595	579
421	West Africa		330	401
117	Kazakhstan		119	120
130	Rest of Asia		150	119
209	America		135	156
16	Australia and Oceania		20	23
166.8	Production sold (a)	(mmboe)	154.2	156.3

PRODUCTION OF LIQUIDS BY REGION

Fourth Quarter First Quarter

2009 2009 2010

1,073	Production of liquids (a)	(kbbl/d)	1,013	1,011
61	Italy		55	58
138	Rest of Europe		139	132
281	North Africa		304	287
349	West Africa		294	341
72	Kazakhstan		70	72
50	Rest of Asia		73	36
116	America		66	77
6	Australia and Oceania		12	8

PRODUCTION OF NATURAL GAS BY REGION

Fourth Quarter First Quarter

2009 2009 2010

4,668	Production of natural gas (a) (b)	(mmcf/d)	4,398	4,615
645	Italy		685	687
673	Rest of Europe		672	618
1,629	North Africa		1,671	1,679
411	West Africa		210	339
261	Kazakhstan		276	272
458	Rest of Asia		446	479
534	America		395	453
57	Australia and Oceania		43	88

(a)	Includes Eni’s share of production of equity-accounted entities.
(b)	Includes volumes of gas consumed in operations (316 and 289 mmcf/d in the first quarter 2010 and 2009, respectively and 318 mmcf/d in the fourth quarter 2009).

- 35 -

Petrochemicals

Fourth Quarter First Quarter

2009 2009 2010

	Sales of petrochemical products	(euro million)
503	Basic petrochemicals		341	673
584	Polymers		485	758
49	Other revenues		52	45
1,136			878	1,476
	Production	(ktonnes)
1,080	Basic petrochemicals		1,019	1,241
575	Polymers		520	607
1,655			1,539	1,848

Engineering & Construction

(euro million)

Fourth Quarter First Quarter

2009 2009 2010

	Offshore construction
1,681	Offshore construction	561	1,105
891	Onshore construction	1,621	1,247
355	Offshore drilling	316	140
41	Onshore drilling	20	186
2,968		2,518	2,678

(euro million)

Dec. 31, 2009 March 31, 2010

Order backlog 18,730 18,769

- 36 -

Eni: Board of Directors approves bond issue

San Donato Milanese (Milan), April 23, 2010 - Eni's Board of Directors this morning approved the issue of one or more bonds for a maximum amount of euro 3 billion, in one or more tranches, by April 23, 2011.

The bonds will enable Eni to achieve a better balance between its short-term and medium/long-term debt, and will be listed on regulated markets.

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.065982398
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56
Switchboard: +39.0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

ANNUAL REPORT ON FORM 20-F 2009

Rome, April 26, 2010 - Today Eni’s Annual Report on Form 20-F for the year ended December 31, 2009, has been filed with the U.S. Securities and Exchange Commission (SEC).

The Annual Report on Form 20-F 2009 is available on the Publications section of Eni’s website, www.eni.com.

Shareholders can receive a hard copy of Eni’s Annual Report on Form 20-F 2009, free of charge, by filling in the request form found in the Publications section or by emailing a request to segreteriasocietaria.azionisti@eni.com or to investor.relations@eni.com.

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.065982398
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56
Switchboard: +39.0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

Eni: Shareholders' meeting approves 2009 financial statements

• dividend of euro 1
• net income at euro 5.06 billion
• appointment of Reconta Ernst & Young as Independent Auditors of Eni financial statements for the period 2010-2018
• amendments to articles 1, 4, 12, 14, 15 and 16 of the By-laws

Rome, April 29, 2010 - The Ordinary and Extraordinary Shareholders’ Meeting held today resolved to:

• approve Eni Financial Statements at December 31, 2009, which disclose a net income of euro 5,060,639,549.44;

• allocate euro 3,249,436,231.44 of Eni’s 2009 net income of euro 5,060,639,549.44, remaining after the payment of an interim dividend of euro 0.50 per share resolved by the Board of Directors on September 10, 2009 and paid as of September 24, 2009, as follows:

- to pay a dividend of 0.50 euro for each share outstanding on the ex-dividend date, Eni treasury shares on that date are excluded. Therefore, including the payment of the 2009 interim dividend of 0.50 euro per share, the 2009 dividend per share proposed amounts to 1 euro;

- to contribute the remaining net income after allotment of the dividend to the Distributable Reserve;

• pay said dividend as of May 27, 2010, the ex-dividend date being May 24, 2010;

• appoint the auditing firm Reconta Ernst & Young as Independent Auditors of Eni financial statements for the period 2010-2018;

- 1 -

• approve the amendments to articles 1, 4, 12, 14, 15 and 16 of the By-laws proposed by the Board of Directors. These include the recent changes to shareholders rights introduced in Italy by the decree on the Shareholders rights directive.

Payment of year 2009 final dividend

Eni Shareholders’ Meeting resolved to pay final dividends as of May 27, 2010, coupon No. 14, being the ex-dividend date May 24, 2010. Therefore, as of this date, Eni shares will be traded without the right to the payment of 2009 final dividend.

In order to exercise the rights incorporated in the shares owned, Shareholders whose shares are not yet dematerialised shall deliver said shares to a financial intermediary for their deposit with Monte Titoli (the Italian Securities Register Centre) and their subsequent dematerialisation.

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 JPMorgan Chase Bank, N.A.

Company Contacts:

Press Office: Tel. +39.0252031875 - +39.065982398
Freephone for shareholders (from Italy): 800940924
Freephone for shareholders (from abroad): +39.800 11 22 34 56
Switchboard: +39.0659821

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

- 2 -

Table of Contents
Contents

 

Table of Contents
Contents

Table of Contents
Contents

Table of Contents
Contents

Eni’s Fact Book is a supplement to Eni’s 2009 Annual Report and is designed to provide supplemental financial and operating information.
It contains certain forward-looking statements in particular under the section "Outlook" regarding capital expenditure, development and management of oil and gas resources, dividends, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sale growth, new markets, and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. April 29, 2010

Periodical updates will be available on the web site: www.factbook.eni.com

Contents	4	Eni in 2009
	5	Eni’s strategy
	11	Exploration & Production
	47	Gas & Power
	66	Refining & Marketing
	79	Engineering & Construction
	87	Research and Innovation
		Tables
	92	• Financial data
	105	• Employees
	106	• Supplemental oil and gas information
	117	• Quarterly information

Eni Fact BookEni

Eni in 2009

Eni is a major integrated energy company, committed to growth in the activities of finding, producing, transporting, transforming and marketing oil and gas. In 2009 Eni’s adjusted net profit was euro 5.21 billion, a decrease of 49% compared to 2008, driven by the sharp decline in oil prices recorded in the first nine months of the year and lower refining margins, those negative trends were partially offset by improved results in the Gas & Power and Engineering & Construction segments. Adjusted return on average capital employed (ROACE) was 9.2%. Main cash inflows for the year were net cash generated by operating activities of euro 11.14 billion, proceeds from disposals of euro 3.6 billion and the share of third parties in a share capital increase part of the restructuring plan of Eni’s regulated gas businesses in Italy (euro 1.54 billion). Cash inflows funded part of the financing requirements associated with organic growth and exploration projects amounting to euro 13.69 billion, the completion of the Distrigas acquisition for euro 2.04 billion, and the payment of Eni dividends for euro 4.17 billion. Net debt to equity ratio at year end was 0.46. The Board of Directors resolved to propose at the Annual General Shareholders Meeting a dividend of euro 1.00 per share for 2009. In 2009 the Exploration & Production segment achieved adjusted net profit of euro 3.9 billion, down 50.9% from 2008, driven by an unfavorable trading environment for oil prices in the first nine months (Brent prices were down 37%), lower sales volumes and a higher tax rate. Oil and gas production was 1,769 kboe/day, down 1.6% from 2008. When excluding OPEC restrictions amounting to approximately 28 kbbl/d, production remained substantially

unchanged from a year ago with an average reference price of Brent at 59.9 $/bbl. Eni’s all-sources reserve replacement ratio was 96%, resulting in a reserve life index of 10.2 years at December 31, 2009. Over the course of the year we increased our resource base by more than 1 billion boe to 30 billion boe thanks to successful exploration activities in Venezuela, with the giant Perla discovery, Angola, Ghana and the Gulf of Mexico. The Gas & Power segment reported adjusted net profit of euro 2.92 billion, an increase of 10% from 2008, in spite of challenging market conditions, with gas consumption down by 7.4% in Europe and 10% in Italy. This result was largely due to a stable performance in the regulated businesses, excellent results achieved by Distrigas and integration synergies and the impact of the renegotiation of long-term supply contracts. Those trends were partially offset by sharply lower sales volumes and margins, in particular on the Italian market. However, global sales volumes were stable at 104 bcm, as a result of the expansion in European markets that absorbed declining sales in Italy (down 24%). The Refining & Marketing segment reported adjusted net loss of euro 197 million, a decline of euro 718 million as compared to a net profit of euro 521 million in 2008, due to an extremely weak refining scenario. Refining throughputs were reduced by one million tonnes. These impacts were partly offset by a good performance in marketing as a result of our effective marketing initiatives. The Engineering & Construction segment reported adjusted net profit of euro 892 million (14% higher than in 2008) thanks to a better operating performance driven by a strong order backlog, the profitability of orders acquired in the upward phase of the oil cycle and increased efficiency.

- 4 -

Eni Fact BookEni

Eni’s strategy

In spite of uncertain perspectives for the global economy and muted expectations for the energy scenario on both the short and medium term, our strategic direction has remained unchanged. Eni will continue pursuing growth and creating sustainable long-term shareholders’ value. Our strategy will leverage on Eni’s unique integrated business model, its high-quality asset portfolio and investment opportunities. Eni’s strategy is based on the following pillars:
- to preserve a solid capital structure;
- to select the best capital and investment opportunities;
- to pursue capital and operating efficiency;
- to manage risks;
- to leverage research and innovation;
- to apply the highest ethical principles of business conduct;
- to promote the sustainability of the business model. Over the next four years, Eni plans to execute a capital expenditure program amounting to euro 52.8 billion to support organic growth in its businesses. Approximately euro 37 billion (or 71%) of planned capital expenditures will be invested to explore for and grow high-quality oil and gas resources. Planned projects have been assessed against our long-term scenario for Brent prices at 65 $/barrel. Eni expect to fund its capital expenditure plans with the expected cash flows from operations. Additional resources (free cash flow) will be used to support our dividend policy and progressively reduce the ratio of net borrowings to total equity ("leverage") to below 0.40.
In the next four year period, management intends to pursue a progressive dividend policy, paying a dividend of euro 1 per share for 2010, in line with the 2009 the dividend, and thereafter growing it in line with OECD inflation. This dividend policy is based on management’s planning assumptions for oil prices at 65 $/barrel flat in the next four years.
Business strategies and targets In the Exploration & Production division Eni boasts strong competitive positions in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and West Africa and Venezuela. The Company can count on a robust pipeline of giant fields which grant competitive costs and access to conventional resources, increasing operatorship as well as long-standing partnerships with key host producing countries.
Our existing asset base provides a strong platform for growth, and we intend to increase production with improving returns. Management targets a production growth rate higher than 2.5% on average over the next four-year period, resulting in a production level in excess of 2 mmboe/d in 2013 based on the Company’s long-term Brent price assumptions of 65 $/barrel.

- 5 -

Eni Fact BookEni

Management plans to achieve 75% of that production target by continuing production ramp-up at our existing fields by applying the Company’s advanced recovery technologies and a further 25% by starting production at 41 new fields, particularly the Zubair project in Iraq, Kashagan in the Caspian area, Algeria with the fields acquired from First Calgary, the Goliat field offshore Norway and the Block 15 development area in Angola. Overall, new start-ups are expected to add approximately 560 kboe/d by 2013.
Most of our projects are in the final investment decision stage or have already been sanctioned. preserve the profitability of the business by strengthening its leadership in the European market.
By 2013 we expect to grow our gas sales at an average annual rate higher than 3%, or an overall increase of 14 bcm from 2009 (104 bcm) targeting a global sales volume of 118 bcm. Our growth plans will be directed to the European markets, mainly France, Benelux and Germany, where the Company plans to achieve sales volumes of approximately 59 bcm by 2013, from sales of 47 bcm in 2009. Our efforts will be supported by synergies deriving from the integration of Distrigas activities.

Management intends to consolidate its industry-leading position on costs leveraging on economies of scale associated with giant projects development, a focused presence in core legacy areas providing low lifting costs and increasing operatorship that ensures a better control on project schedules and costs. Management will continue focusing on reserve replacement in order to sustain the long-term growth prospects of the business. Over the last five years we have grown our resource base by some 10 billion barrels, to 30 billion barrels or 46 years of production, thanks to successful exploration and continuing development activities. In the Gas & Power division Eni is leader in the European gas market leveraging is fully-integrated presence along the gas value chain: supply, transport, distribution, storage and marketing of natural gas, as well as power generation and sales of electricity.
Flexibility granted by our long-term and diverse supply sources portfolio, a large customer base, market knowledge, long-term relationships with key producing countries and integration with upstream activities are our competitive advantages.
In the context of a changed demand outlook and stronger competitive pressures both on the European and Italian markets, Eni’s strategy in its Gas & Power segment is to In Italy, management intends to maintain the Company’s market share and preserve the profitability of the business. To achieve those targets, the Company will pursue effective marketing initiatives and increasing levels of efficiency mainly by reducing the cost of service and cost associated with business supporting activities. Stable returns are expected from regulated businesses in Italy, which will benefit from the pre-set, regulatory returns on new capital expenditures and cost savings from integrating the whole chain of transport, storage and distribution activities. In the Refining & Marketing division Eni is leader in the retail marketing of refined products in Italy with a market share of 31.5 as of the end of 2009.
Operations are conducted also in Central-Eastern Europe. Eni operations are effectively fully integrated through refining, supply, trading, logistics and distribution, so as to maximize cost efficiencies and business effectiveness.
The medium-term outlook for the refining industry is challenging as weak industry fundamentals are expected to persist for some time as to regard to excess capacity, high inventory levels, increasing feedstock costs and weak demand. Against this backdrop, Eni plans to selectively upgrade its refining system by increasing complexity and flexibility of its best refineries, leveraging on its know-

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Eni Fact BookEni

how and the proprietary EST technology. Recovery in profitability will be achieved through cost efficiencies and energy measures.
In marketing operations, Eni plans to achieve higher returns by improving quality and range of offered services, including non-oil activities, leveraging on marketing initiatives to retain customers’ loyalty and re-branding to the "eni" brand our service stations. By 2013, Eni expects to increase market share in Italy by 2.5 percentage points to 34% (31.5% in 2009).
Eni’s strategy in the rest of Europe is focused on selectively growing its presence by leveraging on synergies ensured by the proximity of these markets to Eni’s production and logistic facilities. In the Engineering & Construction segment, Eni operates through its subsidiary Saipem, boasting a worldwide leading position in engineering, construction and drilling activities, leveraging on innovative technologies and distinctive know-how mainly in the realization of complex projects. Saipem is completing the expansion and revamping program of its world class of construction and drilling vessels which, combined with a strong competitive position in frontier areas which are traditionally less exposed to the cyclical nature of this market, underpin expectations for a further strengthening of Eni’s competitive position in the Engineering & Construction segment which maintains steady orders backlog and profitability.
Over the four year plan, efficiency remains one of the pillars of our strategy. The cost reduction program launched in 2006, in a favorable trading environment, has delivered euro 1.3 billion of savings to date. In 2009 alone we delivered cost savings of around euro 400 million.
In the next four year period, the Company is targeting euro 1.1 billion of additional efficiency gains through technology improvements, commercial and supply optimization as well as continuous process streamlining. Research and innovation will play a central role in Eni’s growth strategy. In recent years Eni engaged in the generation, identification and protection of innovative results obtained in R&D both in the technologies related to its core business and in the field of renewable energy sources.
For the next four years Eni defined a relevant capital expenditure plan in Research and Innovation amounting to approximately euro 1.4 billion, focusing in particular on (i) developing techniques aiming at improving the assessment of the production potential of fields and the performance of exploration and production activities; (ii)increasing the hydrocarbon recovery factor; (iii) monetizing natural gas reserves and upgrading transport infrastructure and (iv) converting low grade products (e.g. ultra-heavy crude, bitumen, fuel oil) to higher grade distillates.

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Eni Fact BookEni

Main data

Key financial data Italian GAAP IFRS

(euro million) 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Net sales from operations (a)		47,938		49,272		47,922		51,487		57,498		73,692		86,071		87,204		108,082		83,227
Operating profit (b) (c)		10,772		10,313		8,502		9,517		12,399		16,664		19,336		18,739		18,517		12,055
Exploration & Production (d)		6,603		5,984		5,175		5,746		7,890		12,324		15,368		13,433		16,239		9,120
Gas & Power (d)		3,178		3,672		3,244		3,627		3,723		3,580		4,022		4,465		4,030		3,687
Refining & Marketing		986		985		321		583		1,080		1,852		324		686		(988	)	(102	)
Petrochemicals		4		(415	)	(126	)	(176	)	320		202		172		100		(845	)	(675	)
Engineering & Construction		144		255		298		311		203		307		505		837		1,045		881
Other activities						(214	)	(293	)	(395	)	(934	)	(622	)	(444	)	(346	)	(382	)
Corporate and financial companies		(143	)	(168	)	(196	)	(281	)	(363	)	(526	)	(300	)	(312	)	(743	)	(474	)
Impact of unrealized intragroup      profit elimination										(59	)	(141	)	(133	)	(26	)	125
Adjusted operating profit (c)				10,482		8,959		9,958		12,582		17,396		20,483		19,004		21,608		13,122
Net profit		5,771		7,751		4,593		5,585		7,059		8,788		9,217		10,011		8,825		4,367
Adjusted net profit (c)				5,757		4,923		5,096		6,645		9,251		10,401		9,569		10,164		5,207
Net cash provided by operating activities		10,583		8,084		10,578		10,827		12,500		14,936		17,001		15,517		21,801		11,136
Capital expenditures and investments		9,815		11,270		9,414		13,057		7,815		7,560		7,928		20,502		18,867		16,018
Capital expenditures		5,431		6,606		8,048		8,802		7,499		7,414		7,833		10,593		14,562		13,695
Investments		4,384		4,664		1,366		4,255		316		146		95		9,909		4,305		2,323
Shareholders’ equity including minority interest		24,073		29,189		28,351		28,318		35,540		39,217		41,199		42,867		48,510		50,051
Net borrowing		7,742		10,104		11,141		13,543		10,443		10,475		6,767		16,327		18,376		23,055
Net capital employed (b)		31,815		39,293		39,492		41,861		45,983		49,692		47,966		59,194		66,886		73,106
Exploration & Production (d)		12,646		18,252		17,318		17,340		16,770		19,109		17,783		23,826		30,363		32,455
Gas & Power (d)		10,721		12,777		12,488		15,617		19,554		20,075		19,713		21,333		22,546		24,754
Refining & Marketing		4,563		4,476		5,093		5,089		5,081		5,993		5,631		7,675		7,379		8,105
Petrochemicals		2,581		1,075		2,130		1,821		2,076		2,018		1,953		2,228		1,915		1,774
Engineering & Construction		1,395		1,635		2,335		2,119		2,403		2,844		3,399		4,313		5,023		6,566
Corporate, financial companies      and other activities		(91	)	1,078		128		(125	)	277		2		(95	)	294		24		(192	)
Impact of unrealized intragroup      profit elimination										(178	)	(349	)	(418	)	(475	)	(364	)	(356	)
Return On Average Capital Employed (ROACE)	(%)
Reported		21.5		23.9		13.7		15.6		16.6		19.5		20.2		20.5		15.7		8.0
Adjusted										15.9		20.5		22.6		19.4		17.6		9.2
Leverage		0.32		0.35		0.39		0.48		0.29		0.27		0.16		0.38		0.38		0.46

(a)	From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programmes be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results under IFRS have been restated accordingly.
(b)	From January 1, 2006 Eni’s subsidiaries operating in diversified sectors (such as real estate services, insurance and financing intermediation, R&D and training services) are reported in the aggregate "Corporate and financing companies" with the exception of Tecnomare which is reported in the Exploration & Production division (previously all these diversified activities were reported in the aggregate "Other activities"). The "Other activities" aggregate includes only Syndial SpA, a subsidiary which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain business which Eni exited in past years. In order to allow for comparison, 2005 data have been reclassified accordingly. Previous years data have not been reclassified.
(c)	From year 2009, the Company accounts gains and losses on non-hedging commodity derivative instruments, including both fair value remeasurement and settled transactions, as items of operating profit. Adjusted operating profit and net profit only include gains and losses associated with settled transactions, gross and net of the associated tax impact respectively. Prior period results under IFRS have been restated accordingly.
(d)	From January 1, 2009, results of the gas storage business, accounted for the Exploration & Production segment until December 31, 2008, are reported within the Gas & Power segment, in the regulated businesses results, following restructuring of Eni regulated gas businesses in Italy. IFRS data have been restated accordingly.

Key market indicators 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Average price of Brent dated crude oil (a)		28.39	24.46	24.98	28.84	38.22	54.38	65.14	72.52	96.99	61.51
Average EUR/USD exchange rate (b)		0.924	0.896	0.946	1.131	1.244	1.244	1.256	1.371	1.471	1.393
Average price in euro of Brent dated crude oil		30.73	27.30	26.41	25.50	30.72	43.71	51.86	52.90	65.93	44.16
Average European refining margin (c)		3.99	1.97	0.80	2.65	4.35	5.78	3.79	4.52	6.49	3.13
Average European refining margin Brent/Ural (c)		4.80	2.60	1.40	3.40	7.03	8.33	6.50	6.45	8.85	3.56
Euribor - three-month euro rate	(%)	4.4	4.3	3.3	2.3	2.1	2.2	3.1	4.3	4.6	1.2

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

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Eni Fact BookEni

Selected operating data 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Exploration & Production
Proved reserves of hydrocarbons at period end	(mmboe)	6,008	6,929	7,030	7,272	7,218	6,837	6,436	6,370	6,600	6,571
Reserve life index	(years)	14.0	13.7	13.2	12.7	12.1	10.8	10.0	10.0	10.0	10.2
Hydrocarbon production	(kboe/d)	1,187	1,369	1,472	1,562	1,624	1,737	1,770	1,736	1,797	1,769
Gas & Power
Sales of consolidated companies (including own consumption)	(bcm)	64.63	65.72	66.14	71.39	76.49	82.62	85.76	84.83	89.32	89.60
Sales of Eni’s affiliates (Eni’s share)	(bcm)	0.87	1.38	2.40	6.94	5.84	7.08	7.65	8.74	8.91	7.95
Total sales and own consumption (G&P)	(bcm)	65.50	67.10	68.54	78.33	82.33	89.70	93.41	93.57	98.23	97.55
E&P gas sales (a)	(bcm)					4.70	4.51	4.69	5.39	6.00	6.17
Worldwide gas sales	(bcm)	65.50	67.10	68.54	78.33	87.03	94.21	98.10	98.96	104.23	103.72
Natural gas transported on behalf of third parties in Italy	(bcm)	9.45	11.41	19.11	24.63	28.26	30.22	30.90	30.89	33.84	37.27
Electricity sold	(TWh)	4.77	6.55	6.74	8.65	16.95	27.56	31.03	33.19	29.93	33.96
Refining & Marketing
Throughputs on own account	(mmtonnes)	41.27	39.99	37.73	35.43	37.69	38.79	38.04	37.15	35.84	34.55
Balanced capacity of wholly-owned refineries at period end	(kbbl/d)	664	664	504	504	504	524	534	544	544	554
Sales of refined products (b)	(mmtonnes)	53.46	53.24	52.24	50.43	53.54	51.63	51.13	50.15	49.16	45.59
Retail sales in Europe (b)	(mmtonnes)	13.92	14.11	13.71	14.01	14.40	12.42	12.48	12.65	12.03	12.02
Service stations at year end (b)	(units)	12,085	11,707	10,762	10,647	9,140	6,282	6,294	6,440	5,956	5,986
Average throughput per service station	(kliters/y)	1,555	1,621	1,674	1,771	1,970	2,479	2,470	2,486	2,502	2,477
Engineering & Construction
Orders acquired	(euro million)	4,726	3,716	7,852	5,876	5,784	8,395	11,172	11,845	13,860	9,917
Order backlog at year end	(euro million)	6,638	6,937	10,065	9,405	8,521	10,122	13,191	15,390	19,105	18,370
Employees at year end	(units)	69,969	72,405	80,655	76,521	70,348	72,258	73,572	75,862	78,880	78,417

(a)	Includes E&P gas sales in Europe (4.70 bcm, 4.51 bcm, 4.07 bcm, 3.59 bcm, 3.36 bcm and 2.57 bcm, in 2004, 2005, 2006, 2007, 2008 and 2009, respectively) and in the Gulf of Mexico (0.62 bcm, 1.8 bcm, 2.64 bcm and 3.60 bcm in 2006, 2007, 2008 and 2009, respectively).
(b)	2008-2009 data not include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Share data Italian GAAP IFRS

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Net profit (a)	(euro)	1.44	1.98	1.20	1.48	1.87	2.34	2.49	2.73	2.43		1.21
Dividend	(euro)	0.424	0.75	0.75	0.75	0.90	1.10	1.25	1.30	1.30		1.00
Dividend pertaining to the year (b)	(euro million)	1,664	2,876	2,833	2,828	3,384	4,086	4,594	4,750	4,714		3,622
Cash flow	(euro)	2.65	2.07	2.76	2.87	3.31	3.97	4.59	4.23	5.99		3.07
Dividend yield (c)	(%)	3.2	5.6	5.2	5.1	4.9	4.7	5.0	5.3	7.6		5.8
Net profit per ADR (d)	($)	2.71	3.52	2.52	3.72	4.66	5.81	6.26	7.49	7.15		3.36
Dividend per ADR (d)	($)	0.72	1.48	1.71	1.83	2.17	2.74	3.14	3.56	3.82		2.79
Cash flow per ADR (d)	($)	4.98	3.68	5.79	7.22	8.96	9.40	11.53	11.60	17.63		8.56
Dividend yield per ADR (c)	(%)	3.0	6.2	5.8	5.0	5.0	4.7	5.0	5.3	7.6		5.8
Pay-out	(%)	29	37	62	51	48	46	50	47	53		83
Number of shares at period-end representing share capital	(million shares)	4,001.1	4,001.3	4,001.8	4,002.9	4,004.4	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)	3,995.1	3,911.9	3,826.9	3,778.4	3,771.7	3,763.4	3,701.3	3,669.2	3,638.9		3,622.4
TSR	(%)	29.2	6.0	13.1	4.3	28.5	35.3	14.8	3.2	(29.1	)	13.7

(a)	Calculated on the average number of Eni shares outstanding during the year.
(b)	Amounts due on the payment of the balance of 2009 dividends are estimated.
(c)	Ratio between dividend of the year and average share price in December.
(d)	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)	Calculated by excluding own shares in portfolio.

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Eni Fact BookEni

Share information 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Share price - Milan Stock Exchange
High	(euro)	14.50	15.60	17.15	15.75	18.75	24.96	25.73	28.33	26.93	18.35
Low	(euro)	9.54	11.56	12.94	11.88	14.72	17.93	21.82	22.76	13.80	12.30
Average	(euro)	11.78	14.10	15.29	13.64	16.94	21.60	23.83	25.10	21.43	16.59
End of period	(euro)	13.64	14.05	15.15	14.96	18.42	23.43	25.48	25.05	16.74	17.80
ADR price (a) - New York Stock Exchange
High	($)	64.88	69.70	82.11	94.98	126.45	151.35	67.69	78.29	84.14	54.45
Low	($)	46.56	52.50	60.90	66.15	92.35	118.50	54.65	60.22	37.22	31.07
Average	($)	54.18	63.22	72.20	77.44	105.60	134.02	59.97	68.80	63.38	46.36
End of period	($)	64.31	61.96	78.49	94.98	125.84	139.46	67.28	72.43	47.82	50.61
Average daily exchanged shares	(million shares)	17.3	17.4	19.4	22.0	20.0	28.5	26.2	30.5	28.70	27.88
Value	(euro million)	203.9	245.0	295.4	298.5	338.7	620.7	619.1	773.1	610.40	461.66
Number of shares outstanding at period end (b)	(million shares)	3,956.7	3,846.9	3,795.1	3,772.3	3,770.0	3,727.3	3,680.4	3,656.8	3,622.4	3,622.4
Market capitalization (c)
EUR	(billion)	54.0	54.0	57.5	56.4	69.4	87.3	93.8	91.6	60.6	64.5
USD	(billion)	50.7	48.1	60.4	71.1	94.9	104.0	117.8	264.9	173.2	183.3

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

Data on Eni share placements 1995 1996 1997 1998 2001

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

(a) Refers to share capital at December 31, 2009.

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Eni Fact BookExploration & Production

Key performance indicators ^(a) 2005 2006 2007 2008 2009

Net sales from operations (b)	(euro million)	22,120	26,738	26,920	33,042	23,801
Operating profit		12,324	15,368	13,433	16,239	9,120
Adjusted operating profit		12,649	15,521	13,770	17,222	9,484
Adjusted net profit		6,032	7,135	6,328	7,900	3,878
Capital expenditures		4,932	5,163	6,480	9,281	9,486
of which: exploratory expenditures (c)		656	1,348	1,659	1,918	1,228
Adjusted capital employed, net at year end		19,109	17,783	23,826	30,362	32,455
Adjusted ROACE	(%)	33.6	38.7	30.4	29.2	12.3
Average realizations
- Liquids	($/bbl)	49.09	60.09	67.70	84.05	56.95
- Natural gas	($/mmcf)	4.49	5.29	5.42	8.01	5.62
- Total hydrocarbons	($/boe)	41.06	48.87	53.17	68.13	46.90
Production (d)
- Liquids	(kbbl/d)	1,111	1,079	1,020	1,026	1,007
- Natural gas	(mmcf/d)	3,595	3,964	4,114	4,424	4,374
- Total hydrocarbons	(kboe/d)	1,737	1,770	1,736	1,797	1,769
Estimated net proved reserves (d) (e) (f)
- Liquids	(mmbbl)	3,773	3,481	3,219	3,335	3,463
- Natural gas	(bcf)	17,591	16,965	18,090	18,748	17,850
- Total hydrocarbons	(mmboe)	6,837	6,436	6,370	6,600	6,571
Reserve life index	(years)	10.8	10.0	10.0	10.0	10.2
Reserve replacement ration including equity-accounted entities (f)	(%)	40	38	90	135	96
Employees at year end	(units)	7,739	8,040	9,023	10,891	10,870

(a)	From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit following restructuring of Eni’s regulated gas businesses in Italy. Prior period results have been restated accordingly.
(b)	Before elimination of intragroup sales.
(c)	Includes exploration bonuses.
(d)	Includes Eni’s share of equity-accounted entities.
(e)	The new US SEC rule has changed the pricing mechanism for oil & gas reserves estimation in 2009. It specifies that, in calculating economic producibility, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prior period results use the one-day-price measured on the last day of the company’s fiscal year.
(f)	Includes a 29.4% stake of the reserves of the three equity-accounted Russian companies participated by joint-venture OOO SeverEnergia, owned by Eni (60%) and its Italian partner Enel (40%) which on September 23, 2009 completed the divestment of the 51% stake in the venture to Gazprom in line with the call option arrangement.

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Eni Fact BookExploration & Production

2009 Highlights Portfolio
I Signed a technical service contract, under a 20-year term with an option for further 5 years, with Iraqi National Oil Companies to develop the Zubair oil field (Eni’s interest 32.8%). The partners of the project expect to gradually increase production to a target plateau level of 1.2 mmbbl/d over the next six years.
- Signed an agreement with the Venezuelan National Oil Company PDVSA for the joint development of the Junin 5 giant field with 35 billion barrels of certified heavy oil in place, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 kbbl/d and a long-term production plateau of 240 kbbl/d is targeted.
- Acquired from Quicksilver Resources Inc a 27.5% interest in the Alliance area, in Northern Texas with gas shale reserves. Quicksilver has retained the 72.5% of the property and operatorship. The cash consideration for the transaction amounted to $280 million. Production from the acquired assets amounted to 4 kboe/d net to Eni for the full year 2009, ramping up to approximately 10 kboe/d by 2011.
- Awarded a 37.8% stake in the Indonesian Sanga Sanga license for the production of coal bed methane. Recent preliminary studies in the block showed a resource potential of about 3,920 billion cubic feet of gas to be verified through an appraisal program that will commence in 2010.
- As part of the optimization process of Eni’s upstream portfolio, management approved a plan for rationalizing Eni’s mineral activities in Italy by establishing three new companies to which certain of the Company’s assets have been contributed. The selected assets have different geographical locations: a first group of assets that are located in Northern Italy (Pianura Padana and Emilia Romagna) have been contributed to Società Padana Energia SpA; a second group with assets located in Central Italy (Marche, Abruzzo, Molise) to Società Adriatica Idrocarburi SpA; lastly certain assets in Southern Italy (Crotone area) have been contributed to Società Ionica Gas SpA. Negotiations are firmly underway for the sale of the two companies, Società Padana Energia SpA and Società Adriatica Idrocarburi SpA.
- Awarded new exploration leases in Angola, China, Ghana, the Gulf of Mexico, India, Norway and Yemen.
Divestment of Russian assets
I On April 7, 2009 Gazprom exercised its call option to purchase a 20% interest in OAO Gazprom Neft held by Eni, based on the existing agreements between the two partners, amounting to euro 3,070 million. At the same time, Eni and Gazprom signed new cooperation agreements targeting certain development projects to be conducted jointly in Russia and other countries of interest.
- On September 23, 2009, Eni and its Italian partner Enel in the 60-40% owned joint-venture OOO SeverEnergia completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. The total cash consideration amounted to $940 million net to Eni. The three partners are committed to producing first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 kboe/d within two years from the start of production.
Partnership agreements
I In 2009, leveraging its established co-operation model with oil host countries, Eni finalized a number of strategic partnerships pursuing new ventures. The framework of these ventures provides for integration between the traditional oil business and sustainable development initiatives designed to support the host countries population in achieving high social and economic standards.
- In February 2009 three agreements were finalized as part of the Memorandum of Understanding signed in August 2008 with Angola’s national oil company Sonangol, providing for: (i) a feasibility study to assess the economics of the utilization of associated gas in feeding a grass-root onshore power plant; (ii) a joint study to evaluate and collect data on certain Angolan onshore basins in view of identifying upstream opportunities; (iii) the design of a number of educational and training projects targeting Angolan professionals in the development of energy resources.
- In March 2009 signed a Protocol for Cooperation with the government of Pakistan to develop a number of important upstream, midstream and downstream projects in the Country. Eni will provide its expertise as well as new technologies developed in the field of exploring for and developing hydrocarbon fields.
- In May 2009 signed a cooperation agreement with Egypt’s Ministry for Oil to increase and widen cooperation in development activities. The agreement provides for: (i) an extension of the concession of the giant Belayim field (Eni’s interest 100%) in the Gulf of Suez till 2030, with Eni’s commitment to spending $1.5 billion over the next five years to execute development expenditures, upgrading actions and operating costs; (ii) a joint study to evaluate a number of industrial initiatives to monetize the natural gas reserves at high depth; (iii) training and knowledge management.
- In August 2009 signed a strategic partnership with the Oil Ministry of the Democratic Republic of Congo to start cooperation in developing the host country’s conventional and unconventional oil reserves, upgrading industrial facilities and training projects.
- In November 2009 signed a co-operation agreement as part of the Memorandum of Understanding signed in July 2009 with the Kazakh National Oil Company KazMunaiGas. The agreement provides for: (i) joint exploration activities in the Isatay and Shangala areas located in the Caspian Sea; (ii) studies of initiatives to optimize gas usage in Kazakhstan; (iii) the evaluation of a number of industrial initiatives including the upgrading of the Pavlodar refinery,

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in which KMG holds a majority interest.
- In December 2009 signed a memorandum of understanding with Turkmenistan aimed at promoting and reinforcing the partnership in the development of the oil industry of the Country. Eni will co-operate with state bodies and the Agency for Hydrocarbons to carry out studies to ascertain the oil and gas potential of the country. Eni will contribute its expertise in technology and the sustainability field.
Financial results
I Adjusted net profit for the full year was euro 3,878 million, a decrease of euro 4,022 million from 2008 (down 50.9%) driven by lower oil realizations as a result of the negative price environment recorded in the first nine months of the year, lower gas realizations and lower sales volumes. These negatives were partly offset by the depreciation of the euro against the dollar.
- Return on average capital employed calculated on an adjusted basis was 12.3% in 2009 (29.2% in 2008).
- Full-year liquids and gas realizations in dollar terms declined by 31.2% on average reflecting market conditions (Brent dated was down 36.6%).
ProductionI Oil and natural gas production for the full year 2009 amounted to 1,769 kboe/d, representing a decrease of 28 kboe/d from 2008 (down 1.6%). Excluding OPEC cuts (down 28 kboe/d) production was barely unchanged. The continuing production ramp-ups and field start-ups and positive price impacts in the Company’s PSAs and similar contractual schemes (up 35 kbbl/d) were offset lower production uplifts associated with weak European gas demand, the impact of unplanned facility downtime, continuing security issues in Nigeria as well as mature fields decline. - Leveraging on organic growth in Africa and Central Asia, Eni expects to deliver more than 2.5% compound average growth rate over the next four-year period, targeting a production level in excess of 2 mmboe/day by 2013 under Brent scenario at $65 per barrel.
Estimated net proved reservesI Estimated net proved reserves at December 31, 2009 were 6.57 bboe (down 0.4% from 2008) based on a 12-month average Brent price of $59.9 per barrel. All sources reserve replacement ratio was 96%, with an average reserve life index of 10.2 years (10 years at December 31, 2008). Excluding the price effect resulting from higher liquids prices from a year ago (the Brent crude price was $36.5 per barrel in 2008) the replacement ratio would be 109%.
Exploration and development expenditures
I In 2009, capital expenditures amounted to euro 9,486 million to enhance assets in well established areas of Africa, the Gulf of Mexico and Central Asia. Exploration activities (euro 1,228 million) achieved a number of successes such as the large Perla gas discovery in the Venezuelan offshore and the oil discovery in the Cabaça Norte Angolan offshore basin. Further discoveries were made in Ghana, the North Sea, the Gulf of Mexico and the Indonesian offshore.
- A total of 69 new exploratory wells were drilled (37.6 of which represented Eni’s share), in addition to 10 exploratory wells in progress at year end (4.2 net to Eni). The overall commercial success rate was 41.9% (43.6% net to Eni).
- Development expenditures were euro 7,478 million (up 16.3% from 2008) to fuel the growth of major projects in Kazakhstan, the United States, Egypt, Congo, Italy and Angola.

Strategies

Eni’s Exploration & Production business boasts strong competitive positions in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and West Africa and Venezuela. A high quality portfolio of assets with high exposure to the most competitive giant projects, a strengthened resource base and long-standing relationships with key host countries will enable Eni to deliver industry-leading growth. Our excellent track record of successfully bringing on stream projects on time and budget and integrating acquired assets as well as operational excellence underpins our ambitious production and reserve replacement targets to 2013 and beyond. Consistent with this goal, strategic guidelines for

Exploration & Production division have remained basically unchanged in the years, as follows: - Maintain strong profitable production growth. - Ensure medium to long-term sustainability focusing on reserve replacement. - Develop new projects to fuel future growth. - Consolidate the industry-leading position on costs. In order to carry out these strategies, over the next four years Eni intends to invest approximately euro 37 billion to fund organic growth and exploration initiatives; euro 0.5 billion of which will be spent to build transportation infrastructures through equity-accounted entities.

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Maintain strong profitable production growth Eni’s strategy is intended to deliver strong profitable production growth via organic developments. We intend to grow high-quality oil and gas resources and invest in our robust pipeline of capital projects. Our large exposure to giant projects will enable to Company to reap the benefits associated with scale. We intended to continue increasing recovery from those giant fields by applying our optimization techniques so as to contrast natural declines and provide a stable production platform. Those fields provide, 50% of our production and most of them are still in their early phases of development, with large residual potential.
Our efforts will be supported by our ongoing commitment in establishing strategic partnerships, leveraging on the so-called "Eni co-operation model" that integrates the traditional business of hydrocarbon exploration and production and sustainable activities in host countries' territory.
Development of new reserves and management of mature fields require a significant amount of capital expenditures. In 2009, Eni invested euro 7.5 billion on developing new projects and maximizing the performance of producing fields through work-over actions and drilling of infilling wells.
In the 2010-2013 period, the Company plans to invest approximately euro 32 billion to fuel organic growth. A relevant share of these expenditures relates to operated projects that will add 1.5 mmboe/d of gross production by 2013 reaching 4 mmboe/d. This will allow to maximize synergies in operations and improve the efficiency of our performance. Production: 2009 and outlookLiquids and gas production for the full year 2009 was 1,769 kboe/d, representing a decline of 28 kboe/d from 2008, or 1.6%. Excluding OPEC cuts (down 28 kboe/d) production was barely unchanged.
The continuing production ramp-ups/start-ups in Angola, Congo, Egypt, Kazakhstan, Venezuela and the Gulf of Mexico as well as the positive price impact reported in the Company’s PSAs and similar contractual schemes (up 35 kbbl/d) were offset by lower production uplifts associated with weak European gas demand, the impact of unplanned facility downtime, continuing security issues in Nigeria as well as mature fields decline. The share of oil and natural gas produced outside Italy was 90% (89% in 2008).
In 2009 a total of 27 new fields were started-up, which are expected to provide 190 kboe/d to our production at plateau. Main start-ups were: (i) Cerro Falcone (Eni’s interest 60.77%) in Italy, with current production of approximately 6 kboe/d, within the completion of the first phase of the development of Val d’Agri the concession; (ii) Yttergryta (Eni’s interest 9.8%) and Tyrihans (Eni’s interest 6.23%) in Norway, with production of approximately 71 mmcf/d and approximately 3 kbbl/d net to Eni, respectively; (iii) North Bardawil (Eni operator with a 60% interest) and Thekah (Eni operator with a 50% interest) offshore in the Nilo Delta, in Egypt; (iv) Mafumeira in Block 0 in Cabinda-Area A (Eni’s interest 9.8%) and Landana-Tombua in the Development Area of former Block 14, in Angola. A production peak is expected in 2010 at 33 kbbl/d and 2011 with 136 kbbl/d, respectively; (v) Oyo in Blocks OML 120/121 (Eni’s interest 40%) offshore Nigeria, with initial production of 25 kbbl/d; (vi) the PY-1 gas field, an asset held by Hindustan Oil Exploration Company Ltd (Eni’s interest 47.18%), purchased within the Burren transaction; (vii) Thunderhawk (Eni’s interest 25%), Longhorn (Eni’s interest 75%) and Leo (Eni’s interest 75%) offshore in the Gulf of Mexico.
In the medium-term, Eni targets to deliver high production growth with the object of a production level in excess of 2 mmboe/d by 2013, corresponding to an average annual growth rate of 2.5% in the 2010-2013 period under Eni’s Brent price scenario at $65 per barrel. Looking forward, Eni projects an approximately 2% annual growth rate until 2016. To achieve those targets, we intend:
- to leverage our robust pipeline of project start-ups, particularly in Kazakhstan, Russia, Iraq, Algeria, Congo, Norway, the Gulf of Mexico and Angola, most of which is Eni operated or holds a significant interest. In the next four years, we expect to start 41 new fields that will add approximately 560 kboe/d to our production in 2013. Most of the projects has been already sanctioned or is progressing towards fid. The whole new production will be profitable also at a Brent price of 40 $/bbl;
- to competitively increase production profiles at giant fields particularly the Western Libyan Gas project in Libya, Karachaganak in Kazakhstan, Val d’Agri in Italy, M’Boundi in Congo and Ekofisk in Norway. We expected that our giant fields will add approximately 400 kboe/d to our production in 2013;
- to develop opportunities in LNG to monetize our wide gas reserve base in particular in West Africa, and non conventional resources with a view of supporting long-term growth.
Ensure medium to long-term business
sustainability by focusing on reserve
replacement Eni intends to pay special attention to reserve replacement in order to ensure the medium to long-term sustainability of the business. We will pursue this goal by:
- optimizing our portfolio of development properties by focusing on core areas, seeking new strategic opportunities and divesting non-core assets;

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- searching for new exploration opportunities targeting a sound balance between high risk/high reward initiatives and established/mature projects.
In 2009 Eni added over 1 billion barrels to its resource base essentially due to successful exploration. The main discoveries of the year were the giant Perla gas discovery offshore Venezuela, the oil discovery Cabaça Norte offshore Angola and other large discoveries in Ghana, the North Sea, the Gulf of Mexico and offshore Indonesia. Eni estimates the contribution to production of its recent discoveries at 170 kboe/d by 2013. Over the past five years, discovered reserves, access to giant fields and final investment decisions all contributed to increase our resource base by 10 billion boe, essentially conventional resources with low production costs. New resources are located both in areas of well-established presence, such as West and North Africa and the North Sea and in new frontier areas such as the deep offshore of the Gulf of Mexico and South America. At 30 billion barrels assuming the Company’s long-term price scenario ($65 per barrel in real term), Eni’s resource base will ensure 46 years of production at current rates.
In the medium-term, Eni expects to achieve a high reserve replacement ratio at the Company’s long-term price scenario leveraging on the monetization of Eni’s core assets in the Caspian Sea, West and North Africa, the Gulf of Mexico and new high potential areas such as Venezuela and Iraq.
Exploration activities will be the pillar in enlarging Eni’s resource base in order to fuel new production and in securing access to new opportunities. In 2009, Eni exploration expenditures amounted to euro 1,228 million to execute a selected campaign with the completion of 69 new exploratory wells were drilled (37.6 of which represented Eni’s share) and an overall commercial success rate of 41.9% (43.6% net to Eni). In 2009 we acquired new acreage for a total extension of approximately 40,000 square kilometers in well established areas in Angola, China, the Gulf of Mexico, India and Norway and in new high potential areas such as Ghana and Yemen.
In the next four years, management plans to invest a cumulative euro 4 billion in exploratory projects focused on:
- monetize our assets in core areas where 70% of capex is directed;
- to conduct activities in recently acquired areas with high risk/high reward opportunities;
- optimize our asset portfolio;
- to selectively assess opportunities to enhance the competitiveness of Eni’s full-cycle production costs.
In particular, investments in well established areas of presence enable Eni to capture synergies leveraging on availability of production facilities and existing competencies. Eni also intends to selectively pursue high risk/high reward opportunities arising from expansion in high risk/high reward areas with high mineral potential.
As of December 31, 2009 Eni’s mineral right portfolio consisted of 1,246 exclusive or shared rights for exploration and development in 40 countries on five continents for a total net acreage of 347,862 square kilometers net to Eni, of which 41,794 kilometers regarded development properties.
Leveraging on the strengthening in core areas of Africa, Central Asia and Russia where Eni already boasted leadership, we increased our portfolio diversity and exposure to less risky areas.

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	Year	w. i.	Peak 100%		Year	w. i.	Peak 100%		Year	w. i.	Peak 100%
Algeria				Egypt				Norway
Rom Integrated	2010		29 kboe/d	Ha’py 9	2010	50%	26 kboe/d	Morvin	2010	30%	51 kboe/d
IAN/EOR	2012	22.38%	5 kboe/d	Melehia Deep	2010	56%	9 kboe/d	Gamma	2012	17%	20 kboe/d
Menzel Ledjmet East	2011	75%	55 kboe/d	Tuna	2010	50%	28 kboe/d	Goliat	2013	65%	100 kboe/d
Central Area Field Complex	2011	75%	67 kboe/d	Seth	2012	50%	27 kboe/d	Marulk	2012	20%	35 kboe/d
El Merk	2012	12.25%	146 kboe/d	Iraq				Russia
Angola				Zubair	2010	32.8%	1,200 kboe/d	Samburskoye	2011	29.4%	145 kboe/d
A-LNG	2012	13.6%	176 kboe/d	Indonesia				Tunisia
Block 15/06	2012	35%	84 kboe/d	Coal Bed Methane (CBM)	2013	37.8%	105 kboe/d	Baraka	2010	49%	5 kboe/d
Kakocha	2013	20%	33 kboe/d	Italy				United Kingdom
Lianzi	2012	10%	43 kboe/d	Aquila, Phase 2	2011	100%	9 kboe/d	Burghley	2010	21.9%	11 kboe/d
Mavacola/ Clochas	2011	20%	120 kboe/d	Annamaria	2010	90%	5 kboe/d	Jasmine	2012	33%	86 kboe/d
Australia				Cerro Falcone	2010	60.77%	42 kboe/d	Kinnoul	2012	16.67%	31 kboe/d
Kitan	2011	40%	40 kboe/d	Offshore Ibleo	2013	60%	26 kboe/d	United States
Congo				Libya				Appaloosa	2010	100%	3 kboe/d
Libondo	2011	35%	8 kboe/d	Bouri - natural gas	2011	50%	36 kboe/d	Nikaitchuq	2011	100%	26 kboe/d
Litchendjili	2013	100%	20 kboe/d	NC 118	2013	50%	9 kboe/d	Venezuela
M'Boundi Gas to IPP	2010	100%	22 kboe/d	Kazakhstan				Junin 5	2013	40%	235 kboe/d
Tar Sands Project	2012	50%	39 kboe/d	Kashagan, Phase 1	2012	16.81%	450 kboe/d	Perla	2013	32.5%	140 kboe/d

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Activity areas nItaly
Eni has been operating in Italy since 1926. In 2009 Eni’s oil and gas production amounted to 169 kboe/d. Eni’s 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 27,178 square kilometers (22,038 net to Eni). Eni’s exploration and development activities are regulated by concession contracts.
As part of the optimization process of Eni’s upstream portfolio, management approved a plan for rationalizing Eni’s mineral activities in Italy by establishing three new companies to which certain of the Company’s assets have been contributed. The selected assets have different geographical locations: a first group of assets that are located in Northern Italy (Pianura Padana and Emilia Romagna) have been contributed to Società Padana Energia SpA; a second group with assets located in Central Italy (Marche, Abruzzo, Molise) to Società Adriatica Idrocarburi SpA; lastly certain assets in Southern Italy (Crotone area) have been contributed to Società Ionica Gas SpA. Negotiations are firmly underway for the sale of the two companies, Società Padana Energia SpA and Società Adriatica Idrocarburi SpA.
Production is expected to remain stable in the medium-term despite mature field declines, due to the continued ramp-up of production in Val d’Agri, ongoing new field projects and continuing production optimization activities designed to counteract mature field decline. Adriatic Sea
Production Fields in the Adriatic Sea accounted for 46% of Eni’s domestic production in 2009. Main operated fields are Barbara (98 mmcf/d net to Eni), Angela-Angelina (48 mmcf/d), Porto Garibaldi (39 mmcf/d), Cervia (46 mmcf/d) and Tea-Arnica-Lavanda (37 mmcf/d). Production is operated by means of 87 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.
In March 2010 production started at the offshore Annamaria b platform (Eni operator with a 90% interest). Production is carried by sealine to the Fano terminal where it is input in the national network. Full production is expected at 42 mmcf/d.
Development Activities for the year concerned sidetrack and workover actions for recovering residual potential of main fields in particular Antares, Cervia, Emma, Giovanna, Barbara, Luna and Annalisa.
Planned activities concern: (i) sidetrack and infilling actions on Barbara and Calpurnia fields; (ii) development of the Bonaccia Est field with drilling of 2 wells.
Exploration Exploration activity concerned the assessment of the residual mineral potential of this area. Central-Southern Apennines
Production Eni is operator of the Val d’Agri concession (Eni’s interest 60.77%) in the Basilicata region, 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 of the 47 foreseen by the sanctioned development plan and is supported at the Viggiano oil center with a treatment capacity of 104 kbbl/d. Oil produced is carried to Eni’s 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 2009 the Val d’Agri concession produced 78 kboe/d (42 net to Eni) corresponding to 25% of Eni’s production in Italy.
Development In 2009 the first development phase in Val d’Agri has been completed by linking the first 3 wells of the Cerro Falcone area to the Val d’Agri oil center with a production of approximately 6 kboe/d. The drilling program continued with sidetracking actions and the upgrade of a production facilities.
The main development activities in natural gas concern the Capparuccia field with the drilling of a second production well and the construction of a treatment station linked to the Italian natural gas transportation network. Start-up is expected in 2011.
Exploration Exploration activity concerned the survey of mineral potential in the area.

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SicilyProduction Eni is operator of 15 production concessions onshore and offshore Sicily. Its main fields are Gela, Ragusa, Giaurone, Fiumetto and Prezioso, which in 2009 accounted for 10% of Eni’s production in Italy. Development In 2009 activities concerned workover and infilling actions on the Gela field for the recovery of the residual mineral potential; upgrading of facilities at the Ragusa plants. Other onshore activities concerned the completion of the development of the Tresauro oil field where early production was started in 2009 by means of LPT of the existing well. The recovery of the residual reserves of the Tresauro field will be obtained by drilling 2 wells that are expected to be linked to the Ragusa treatment station, with start-up expected in the second half of 2011.
Offshore activities concerned the development of the three recent discoveries (Panda, Argo and Cassiopea). The project provides for the drilling of wells, 3 of them new wells and the recovery of 2 existing ones and the installation of a production platform provided with treatment facilities for a further delivery of production to the mainland. The mineral potential of the area is estimated at approximately 98 mmboe. Start-up is expected in 2013.
Exploration Exploration activity concerned the assessment of the mineral potential of this area. Po ValleyProduction Fields in the area accounted for 5% of Eni’s production in Italy in 2009.
Development Activities in the year regarded mainly optimization, workover and sidetracking activity at the Trecate field. Development continued at the Longanesi field with the drilling of three production wells and the linkage to the San Potito plant, that is expected to be revamped. Start-up is expected in 2012. nRest of Europe Croatia
Eni has been present in Croatia since 1996. In 2009 Eni’s production of natural gas averaged 96 mmcf/d. Activities are deployed in the Adriatic Sea facing 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 Ivana, Ika & Ida, Marica and Katarina operated by Eni through a joint-venture with the Croatian oil company INA. Production is carried by sealine and sold on the Italian and Croatian market.
In 2009 the Annamaria field was started-up operated in joint-venture with INA with a current production of approximately 13 mmcf/d net to Eni. Development was completed on the Irina and Vesna fields with an overall production start-up at approximately 3 mmcf/d net to Eni. Development Further drilling activities are nearing completion in the Katarina field. Start-up is expected in the third quarter of 2010 at approximately 7 mmcf/d.
Exploration Exploration activities yielded positive results in the Ika SW 2 appraisal well that confirmed the mineral potential of the area. Norway
Eni has been operating in Norway since 1964. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea over a development and undevelopment acreage of 11,184 square

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kilometers (3,412 square kilometers net to Eni). In 2009 Eni’s production in Norway amounted to 126 kboe/d.
In May 2009, following an international bid procedure, Eni was awarded the operatorship of the PL 533 (Eni’s interest 40%) and PL 529 (Eni’s interest 40%) exploration licenses in addition to a 30% stake in PL 532 in the Barents Sea.
Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a few years with possible extensions.
In the medium-term, planned development projects will offset by mature field declines. Norwegian Sea
Production Eni holds interests in 6 production areas. The main producing fields are Aasgard (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.12%), Mikkel (Eni’s interest 14.9%) and Norne (Eni’s interest 6.9%) which in 2009 accounted for 65% of Eni’s production in Norway. The gas produced in the area is collected at the Aasgard 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.
Four year production start-up was achieved in: (i) Yttergryta field (Eni’s interest 9.8%), with production of approximately 71 mmcf/d; (ii) Tyrihans field (Eni’s interest 6.23%), developed through synergies with the Kristin production facilities. Production start-up at approximately 3 kbbl/d net to Eni was scheduled to coincide with the production decline of Kristin which made spare capacity available to process production from Tyrihans.
Development Activities in the year were aimed at maintaining production levels by means of sidetracking and infilling activities at the main producing fields.
Development activities progressed in recent oil and gas discoveries near the Aasgard field. In particular the development plan of the Morvin discovery (Eni’s interest 30%) provides linkage to existing production facilities that will be upgraded. Production start-up is expected in 2010 with peak production at 12 kboe/d net to Eni in 2014.
Exploration Eni holds interests in 35 Prospecting Licenses ranging from 5 to 70%, 6 of these are operated. Exploration activities yielded positive results with the Dompap gas discovery (Eni’s interest 11.5%). Appraisal activities are underway. Norwegian section of the North Sea
Production The main producing field is Ekofisk (Eni’s interest 12.39%) in PL 018 which in 2009 produced 56 kboe/d net to Eni and accounted for 44% of Eni’s production in Norway. Production from Ekofisk and satellites is carried by pipeline to the Teesside terminal in the United Kingdom for oil and to the Emdem terminal in Germany for gas.
Development Ongoing projects aim at maintaining and optimizing production at 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 5 prospecting licenses ranging from 12 to 45%, one of them as operator. Barents Sea
Currently Eni is only performing exploration and pre-development activities in this area. Eni is operator of Prospecting License 201 (Eni’s interest 67%), 489 (Eni’s interest 40%), 229-229B-229C (Eni’s interest 65%) and holds a 30% interest in Prospecting License 393 and Seismic Area C (Eni’s interest 31%). Operations in this area are focused on the appraisal of the mineral potential of the large Goliath discovery made in 2000 at a water depth of 370 meters in PL 229 aimed at its commercial development. The project is progressing according to schedule. Commencement is expected in 2013 with a production plateau at 100 kbbl/d and recoverable reserves of 175 mmboe. In 2009, the final investment decision of the Goliat project was sanctioned. Development provides for the use of a cylindrical FPSO unit linked to an underwater production system. Gas produced will be injected in the field. United KingdomEni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, in the Irish Sea and in some areas east and west of the Shetland Islands over a developed and undeveloped acreage of 5,165 square kilometers (1,469 square kilometers net to Eni). In 2009 Eni’s net production of oil and gas averaged 104 kboe/d.
Exploration and production activities in the United Kingdom are regulated by concession contracts.

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In the medium-term, production is expected to decrease due to mature field declines. British section of the North Sea
Production Eni holds interests in 12 production areas. The main fields are Elgin/Franklin (Eni’s interest 21.87%), the J-Block (Eni’s interest 33%), Andrew (Eni’s interest 16.21%), Farragon (Eni’s interest 30%), the Flotta Catchment Area (Eni’s interest 20%), MacCulloch (Eni’s interest 40%) and West Franklin (Eni’s interest 21.87%) which in 2009 accounted for 61% of Eni’s production in the United Kingdom.
Activities in 2009 concerned infilling actions at the Elgin/Franklin, MacCulloch and Jade (Eni’s interest 7%) fields targeting to maintain production levels.
Development Pre-development activities continued at: (i) the Burghley discovery (Eni’s interest 21.92%) with expected start-up in 2010; (ii) the Kinnoul oil and gas discovery (Eni’s interest 16.67%) to be developed in synergy with the Andrew facilities and expected start-up in 2012; (iii) the Jasmine gas discovery (Eni’s interest 33%) with expected start-up in 2012; (iv) Mariner (Eni’s interest 8.89%), with expected start-up in 2015.
Exploration Eni holds interests in 42 exploration blocks ranging from 2 to 45%, in 3 of these Eni is operator. Exploration activity is intense aimed at appraising residual mineral potential. At the gas and condensate Culzean discovery (Eni’s interest 16.95%) near the Elgin/Franklin producing field, activities are underway to assessing its possible development opportunities. Irish Sea
Production Eni holds a 53.9% interest in 6 production fields in the Liverpool Bay area (Douglas, Hamilton and Lennox and their extensions) which in 2009 accounted for 21% of Eni’s production in the UK. Oil and gas volumes are collected at the Douglas hub. Facilities upgrading is underway. Shetland Islands
Production Main fields are Ninian (Eni’s interest 12.94%) and Magnus (Eni’s interest 5%) which in 2009 accounted for 4% of Eni’s production in the United Kingdom. In 2009 maintenance and optimization actions were performed in particular on Magnus.
Development Pre-development activities are underway on the Laggan (Eni’s interest 20%), Tormore (Eni’s interest 22.5%) and Mariner (Eni’s interest 8.89%) discoveries to appraise their development plans. Start-up is expected in 2013.
Exploration Eni holds interests in 9 exploration blocks ranging from 20 to 38%, where an intense seismic acquisition campaign is underway near the mentioned discoveries. nNorth Africa Algeria
Eni has been present in Algeria since 1981. In 2009, Eni’s oil and gas production averaged 83 kboe/d. Operating activities are located in the Bir Rebaa area in the South-Eastern desert and include the following exploration and production blocks: (a) Blocks 403a/d (Eni’s interest 100%); (b) Blocks 401a/402a (Eni’s interest 55%); (c) Blocks 403 (Eni’s interest 50%) and

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404a (Eni’s interest 12.25%); (d) under development Blocks 212 (Eni’s interest 22.38%), 208 (Eni’s interest 12.25%) and 405b (Eni’s interest 75%; following the First Calgary transaction).
Developed and undeveloped acreage of Eni’s interests in Algeria was 19,610 square kilometers (17,244 square kilometers net to Eni).
In 2009 relevant authorities confirmed the acquisition of the operatorship of the Kerzaz exploration block (Block 319a, 321a and 316b) covering a gross acreage of 16,000 square kilometers. Exploration activity was started in 2009.
Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.
In the medium-term, production is expected to increase due to the development and integration of the First Calgary acquired assets with an expected production in excess of 125 kboe/d in 2013. Blocks 403a/d
Production Production in the area is supplied mainly by the HBN and Rom and satellite fields and accounted for approximately 28% of Eni’s production in Algeria in 2009. 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 The main project underway is the Rom Integrated project, designed to develop the Rom and satellites reserves (Zea, Zek and Rec) following the mineral potential revaluation. Current production is collected at the Rom Central Production Facility and delivered to the treatment plant in Bir Rebaa North. Drilling and workover activities were started in 2009. An export pipeline and a new multiphase pumping system are underway in compliance with applicable Country law to reduce gas flaring. The development project provides construction of a new oil treatment plant with a capacity of 32 kbbl/d with production start-up expected in 2012. Blocks 401a/402a
Production Production from this area is supplied mainly by the Rod and satellite fields and accounted for approximately 22% of Eni’s production in Algeria in 2009. 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 fields and accounted for approximately 16% of Eni’s production in Algeria in 2009. Exploration activities for appraising the mineral potential of the area are planned. Block 405b
Development Activities in the area concerned the joint development MLE and CAFC, assets acquired from Canadian company First Calgary in 2008. During 2009 the MLE final investment decision was sanctioned. This project provides the construction of a NGL plant with a capacity of 350 mmcf/d. Production start-up is expected in November 2011. The CAFC final investment decision will be sanctioned in 2010. The CAFC project will provide the construction of an oil treatment plant with a capacity of 35 kbbl/d and installation of water/gas injection systems. The development of the two fields will ensure a production plateau of approximately 33 kboe/d net to Eni by 2012. Drilling activities are underway.
In 2009 the EPC contract for the construction of a gas treatment plant, gathering and exporting facilities has been awarded. As of December 31, 2009, 11% of the project was completed. 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 scheme provides the construction of a NGL treatment plant with a capacity of 600 mmcf/d and 2 oil trains with a capacity of 65 kbbl/d for the production of 11 kboe/d net to Eni. During the year all EPC contracts for the development of facilities were awarded and drilling activity started. As of December 31, 2009, 24% of the project was completed and start-up is expected in 2012. Egypt
Eni has been present in Egypt since 1954 and is the first international oil operator with a gross production amounting to 595 kboe/d (230 net to Eni) in 2009, over a developed and undeveloped acreage of 23,097 square kilometers (8,328 square kilometers net to Eni).
Eni’s main producing liquid fields are located in the Belayim concession (Eni’s interest 100%) in the Western Desert mainly in the Melehia (Eni’s interest 56%) and Ras Qattara(Eni’s interest 75%) concessions producing oil and condensates. Gas production mainly comes from the operated or

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participated concession of North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (50% interest), Ras el Barr (50% interest, non-operated) and el Temsah (50% interest) offshore the Nile Delta.
In 2009 production from these concessions accounted for over 80% of Eni’s production in Egypt.
In May 2009 Eni signed a cooperation agreement with Egypt’s Ministry for Oil to increase and widen cooperation in development activities. The agreement provides for: (i) an extension of the concession of the giant Belayim field in the Gulf of Suez till 2030, with Eni’s commitment to spending $1.5 billion over the next five years in development expenditures, upgrading actions and operating costs; (ii) a joint study to evaluate a number of industrial initiatives to monetize the natural gas reserves at high depth; (iii) training and knowledge management.
Exploration and production activities in Egypt are regulated by PSAs.
In the next four years Egypt confirms to be one of Eni’s largest oil and gas producing countries. Gulf of Suez
Production Liquid production mainly comes from the Belayim field, Eni’s first large oil discovery in Egypt, which produced 54 kbbl/d net to Eni in 2009. Other producing assets are located in the Ashrafi concession which in 2009 produced 4 kbbl/d.
Development Basic engineering activities continued for upgrading the water injection system of the Belayim field in order to optimize the recovery of its mineral potential.
Exploration During the year acquisition and processing of seismic 3D data were conducted aimed at assessing the mineral potential of the area. Nile Delta
North Port Said
Production Eni’s production for the year amounted to over 32 kboe/d (approximately 177 mmcf/d of gas and 4 kbbl/d of condensates net to Eni). Part of the production of this concession is supplied to the NGL (natural gas liquids) plant owned by United Gas Derivatives Co (Eni’s interest 33%) with a treatment capacity of 1.1 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 plant’s capacity to 1.3 bcf/d.
Development Ongoing development activities aim at supporting the current gas production level. Upgrading progressed at the El Gamil compression facility to support the Nord Port Said, el Temsah and Ras el Barr production concessions. Baltim
Production In this concession Eni’s production for the year amounted to over 21 kboe/d net to Eni (approximately 106 mmcf/d of gas and 2 kbbl/dof condensates). During the year, development activities continued at the Abu Madi plant in order to increase compression capacity supporting production from Baltim.

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Ras el Barr
Production This concession contains three fields: Ha’py, Akhen and Taurt. Eni’s production in 2009 amounted to 177 mmcf/d net to Eni. El Temsah
Production This concession includes the Temsah and Denise fields. Eni’s production in 2009 amounted to over 45 kboe/d (approximately 212 mmcf/d of gas and approximately 8 kbbl/d of condensates) net to Eni.
Near this concession, in 2009 production started at the North Bardawil (Eni operator with a 60% interest) and Thekah (Eni operator with a 50% interest) fields through linkage to the El Gamil facilities, with an overall production plateau at approximately 190 mmcf/d.
Development Development activities concerned mainly: (i) the development of the Tuna field through the drilling of 3 wells and the installation of a production platform; (ii) the second phase at the Denise field through the drilling of 3 additional underwater wells to be linked to the Tuna facilities and to the TNW2/Denise A platform; (iii) the upgrade of the El Gamil plant. Exploration in the Nile Delta
The area shows a relevant mineral potential, mainly of gas, and is undergoing an extensive 3D seismic acquisition campaign for assessing the residual mineral potential of area A where 3 wells are in progress. Western Desert
Production Other production activities are located in the Western Desert, in particular in the Melehia (Eni’s interest 56%), Ras Qattara (Eni’s interest 75%), West Abu Gharadis (Eni’s interest 80%) and West Razzak (Eni’s interest 80%) development permits containing mainly oil. Concessions in the Western Desert accounted for approximately 6% of Eni’s production in Egypt in 2009. The LNG business in Egypt
Through its affiliate Unión Fenosa Gas, Eni has an indirect interest in the Damietta natural gas liquefaction plant with a producing capacity of 5.1 mmtonnes/y of LNG corresponding to approximately 268 bcf/y of feed gas. Eni is currently supplying 35 bcf/y for a twenty-year period. Natural gas supplies derived from the Taurt and Denise fields with 17 kboe/d net to Eni of feed gas. Libya
Eni started operations in Libya in 1959 and is currently the leading international operator. In 2009 Eni’s oil and gas production averaged 522 kboe/d (244 net to Eni), the portion of liquids being 44%. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan Desert area, over a developed and undeveloped acreage of approximately 36,374 square kilometers (18,165 square kilometers net to Eni).
Exploration and development activities are concentrated in the following areas; onshore: (i) area A including the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 field (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); (iv) Area F with Block 118 (Eni’s interest 50%); offshore: (i) Area C with the Bouri oil field (Eni’s interest 50%); (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).
In the exploration phase, Eni is operator of four onshore blocks in the Muzurk basin (161/1, 161/2&4, 176/3) and in the Kufra area (186/1, 2, 3 & 4) and in A, B and D contract areas.
Eni’s activities in Libya are regulated by six Exploration and Production Sharing contracts (EPSA) lasting until 2042 for oil production and until 2047 for gas production.
Eni’s production in Libya is expected to post an increase in the next four years due to the expected ramp-up of new gas developments, the schedule of which will depend upon future trends in the gas market, with the support of the upgrade of the GreenStream pipeline, despite mature field declines. In the medium-term Libya is expected to remain the largest producing country by volume in Eni’s portfolio. Area A
Production Located in the Eastern Libyan Desert, it includes six oil fields, started-up in 1984, which are linked to existing facilities at the nearby Bu Attifel field (Area B). In 2009 production from these fields amounted to approximately 14 kbbl/d (approximately 1 kbbl/d net to Eni).
Exploration An extensive exploration activity has been planned in the medium-term to monetize the residual mineral potential of the area.

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Area B
Production Located in the Eastern Libyan Desert, it includes the Bu Attifel oil field discovered in 1967 and started-up in 1972, as well as the smaller NC 125 field. Eni’s production in 2009 amounted to approximately 88 kbbl/d (approximately 14 net to Eni). Infilling wells are currently being drilled in order to recover the residual mineral potential that will also be supported by the construction of new facilities to favor production from lower pressure fields and through the upgrading of the associated gas compression plant.
Exploration In the medium-term an extensive exploration activity has been planned to monetize the residual mineral potential. Area C
Production This area is located in the Mediterranean offshore facing Tripoli. The Bouri oil field, discovered in 1976 and started-up in 1998, produced approximately 45 kbbl/d (approximately 14 net to Eni) in 2009. The field is exploited through two platforms linked to an FSO unit with a storage capacity of approximately 1.5 mmbbl.
Development A plan to monetize flaring gas and associated condensates is underway. Gas and condensates will be delivered by means of underwater pipelines to the Sabratha platform for an initial treatment and from here to the Mellitah plant for the final treatment. Studies are underway for developing residual reserves by means of drilling in the western area of the reservoir along with the replacement of the operating FSO unit and workover of some fields for optimizing oil recovery. Area D
Production The area includes the offshore NC 41 block and the onshore NC 169 block jointly developed in the Western Libyan Gas Project. Production comes from: (i) the Wafa onshore field that was started-up in September 2004. In 2009 this field produced approximately 117 kboe/d of liquids and natural gas (approximately 88 net to Eni); (ii) the Bahr Essalam offshore field that was started-up in August 2005. In 2009 this field produced approximately 148 kboe/d of liquids and natural gas (approximately 112 net to Eni). Onshore production is treated at the Wafa facility and delivered by pipeline to the Mellitah plant for the export of gas and fractioning and marketing of oil and condensates. Offshore production is operated through the Sabratha platform located on the Bahr Essalam field where gas and liquids undergo a pre-treatment phase and are delivered via sealine to the Mellitah plant. Most of the natural gas produced is exported to Europe through the GreenStream pipeline. In 2009 volumes delivered through this pipeline were 309 bcf. In addition, 43 bcf were sold on the Libyan market for power generation and to feed the GreenStream compressor station.
Development Upgrading actions of existing plants and facilities in order to increase gas sales by 49 bcf/y was completed. Additional gas volumes are also expected from a portfolio of undeveloped fields.
Activities aiming at maintaining the production profile of Wafa and Bahr Essalam are underway and include the construction of a compression unit and the drilling of additional wells at Wafa and the drilling of 13 new underwater wells a Bahr Essalam linked to the Sabratha platform. Area E
Production Located in the South-Western Libyan desert about 800 kilometers from Tripoli, production of this area is provided mainly by the El Feel (Elephant) field. In 2009 the field produced approximately 110 kbbl/d (approximately 14 net to Eni). Production is treated at the field’s facilities and then delivered by pipeline to the Mellitah plant for storage and marketing.
Development In 2009 construction of facilities was completed for starting water injection. The project to be completed in 2010 aims at maintaining the production plateau in the area. Area F
Development In the Western Libyan Desert, the A-NC 118 field is under development after the declaration of commercial discovery at the end of 2006. Production will be delivered via the pipeline linking Wafa to Mellitah. The plan provides also for a phase following that of natural depletion with water alternate gas injection to maintain recoverable volumes and production capacity. Production start-up under phase A is expected in 2013.

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Tunisia
Eni has been present in Tunisia since 1960. In 2009 Eni’s production amounted to 16 kboe/d. Eni’s activities are located mainly 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.
Eni’s production in Tunisia is expected to post an increase in the medium-term due to the development of recent discoveries.
Production Production mainly comes from the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks.
The development plan of Maamoura concession (Eni operator with a 49% interest) is almost completed with early production started-up in late 2009. The Baraka (Eni operator with a 49% interest) development project is in final stage with peaking production at 11 kboe/d which is expected in 2010.
Development The ongoing development projects mainly regarded the optimization of production at the Adam, Djebel Grouz (Eni’s interest 50%), Oued Zar and El Borma concessions.
Exploration Exploration activities yielded positive results with four discovery wells of five drilled. In 2009 gas production was started in one well, while two more wells are expected to start-up in 2010. nWest Africa Angola
Eni has been present in Angola since 1980. In 2009 Eni’s production averaged 130 kboe/d. Eni’s activities are concentrated in the conventional and deep offshore over a developed and undeveloped acreage of 20,849 square kilometers (3,393 square kilometers net to Eni).
The main blocks participated by Eni are: (i) Block 0 offshore Cabinda (Eni’s interest 9.8%); (ii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; (iii) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo basin. Eni also holds interests in other minor concessions, in particular in some areas of Block 3 (with interests varying from 12 to 15%) and in the Lianzi Development Area (former 14K/A IMI Unit Area; Eni’s interest 10%).
In the exploration and development phase, Eni is operator of Block 15/06 (with a 35% interest) and holds a 12% interest in Block 3/05-A, in Cabinda North (onshore) with a 10% interest and in the Open Areas of the Gas Project (see below) with a 20% interest.
In 2009 Eni signed agreements with Sonangol implementing the Memorandum of Understanding signed in August 2008 that provide for: (i) a feasibility study for the use of associated gas for firing a new power plant; (ii) a joint study on areas in Angolan onshore basins and the evaluation of upstream activities; (iii) definition of educational and training projects for Angolan professionals in the field of energy; (iv) collaboration in the field of bio-fuels.
Exploration and production activities in Angola are regulated by concessions and PSAs.
In the next four years, production from ongoing development projects is expected to offset mature field decline. Eni targets a production of approximately 180 kbbl/d in the medium-term. Block 0
Production Block 0 is divided into areas A and B. In 2009 production from this block amounted to 352 kbbl/d (34 kbbl/d net to Eni). Oil production from area A, deriving mainly from the Takula and Malongo fields amounted to 20 kbbl/d net to Eni. Production of area B derives mainly from the Bomboco, Kokongo, Lomba, N’Dola, Nemba and Sanha fields, and amounted to 14 kbbl/d net to Eni.
In 2009 production started-up at the Mafumeira field (Eni’s interest 9.8%) in the A area. Drilling and completion are underway of the remaining 6 wells included in the development program. Peak production at 33 kboe/d is expected in 2010.
Development Within the activities for reducing gas flaring, projects progressed at the Nemba field in the A area. Gas currently flared will be reinjected in the field (later it will be sent to the A-LNG liquefaction plant) or used to optimize production (gas lift and secondary recovery). Activities to

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be completed concern the construction of facilities for gas reinjection and a new platform with facilities used for de-bottlenecking. Start-up is expected in 2013 reducing flared gas by approximately 85%.
In 2009 the development activity of Takula field was completed. Gas flared is re-injected in the field; condensates will be shipped to the Malongo treatment plant, nearing completion, to be converted into LPG.
Flaring down of the Malongo area are still underway with completion expected in 2011. LPG will be carried to the Sanha FPSO by means of a recently completed pipeline.
Concept Selection studies are underway on the recent South Malongo, Lifua and Vanza-Longui discoveries.
Infilling activities are underway on the whole block in order to contrast natural decline.
Exploration Exploration activities yielded positive results with an oil and gas discovery in the Vanza area. Appraisal activities continue. Block 3
Production Block 3 is divided into three production offshore areas. In 2009 production from this block amounted to approximately 73 kbbl/d (approximately 6 kbbl/d net to Eni).
Exploration Exploration activities yielded positive results with the Punja-4 gas and liquids appraisal well, that confirmed the mineral potential of the area. Block 14
Production In 2009 Development Areas in the former Block 14 produced 160 kbbl/d (20 kbbl/d net to Eni), accounting for 9% of Eni’s production in Angola. It is one of the most fruitful areas in the West African offshore, recording 9 commercial discoveries to date. Its main fields are Kuito, started-up in 1999, flowing at 3 kbbl/d net to Eni in 2009 and Benguela-Belize/Lobito-Tomboco, started-up in 2006, flowing at 15 kbbl/d net to Eni in 2009.
Development of Benguela-Belize/Lobito-Tomboco is still ongoing with the completion of drilling activities and is aimed at a production peak of 105 kbbl/d in 2010. 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.
In 2009 production started-up at the Landana-Tombua fields discovered in 1997 and 2001 respectively by means of a Compliant Piled Tower provided with treatment facilities aimed at recovering 320 mmbbl by drilling 46 wells (8 are already producing). Peak production at 136 kbbl/d is expected in 2011. Oil produced will be treated at Malongo plant, while associated gas 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 Gabela, Lucapa and Negage discoveries.
Exploration Exploration activity was successful with the Malange 2 appraisal well showing the presence of oil while appraisal activities continue on the Lucapa discovery. Block 15
Production Development Areas in the former Block 15 produced on average 621 kbbl/d (67 kbbl/d net to Eni) in 2009. 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 2009, these fields operated by FPSO unit yielded peak production of 377 kbbl/d (27 kbbl/d net to Eni).
Other fields in Block 15 are Xikombo, Mondo and Saxi/Batuque fields which produced 212 kbbl/d (35 kbbl/d net to Eni) in 2009.
In the medium-term production plateau will be supported by phased development of satellite discoveries.

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Development Activities started for the Kizomba satellites project - phase 1. The first phase plans to produce reservoir of the Clochas and Mavacola oil discoveries with a mineral potential estimated at 254 mmbbl. The project provides for the drilling of 18 producing wells linked to the FPSO vessels existing in the area. Associated gas will be initially re-injected in the reservoirs in the Kizomba area, and thereafter delivered to the A-LNG liquefaction plant. Start-up is expected in 2012. Peak production at 100 kboe/d (21 kboe/d net to Eni) is expected in 2013. The second phase provides for production from nearby discoveries (Mondo South, Kakocha, Bavuca, Tchihumba).
Drilling is underway in the Mondo and Saxi/Batuque fields to complete their development plans.
Optimization of production in the Hungo/Chocalho (Kizomba A) and Kissanje/Dikanza (Kizomba B) fields is underway to maintain their production plateau.
Exploration Exploration activity yielded positive results with the Mondo-4 appraisal well showing the presence of oil increasing the potential of the area. Block 15/06
Exploration Exploration activities yielded positive results with (i) the Cabaça Norte discovery which showed the presence of oil and yielded 6.5 kbbl/d in test production. After this discovery exploration was extended to nearby areas in order to accelerate the development of the eastern part of the block; (ii) the Nzanza discovery containing oil which yielded 1.5 kbbl/d in test production in the western part of the block; (iii) the Cinguvu discovery containing oil which yielded 6.4 kbbl/d in test production. The Nzanza and Cinguvu discoveries will contribute to the redefinition of the development plan of the western part of the block where in 2008 the Sangos and N’goma discoveries were made.
In 2009 commitment activities were completed for the seismic processing of data acquired in 2008. 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 in Soyo, 300 kilometers North of Luanda. It will be designed with a processing capacity of approximately 1.1 bcf/d of natural gas and produce 5.2 mmtonnes/y of LNG and 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. The plant will be fed initially with associated gas from Blocks 0, 14, 17, 18 and in a later phase from Blocks 31 and 32 and with production from the offshore Quiluma and Atum/Polvo gas fields. The project also has a relevant environmental content. Start-up is expected in the first quarter of 2012. The LNG is expected to be delivered to the United States market at the re-gasification plant in Pascagoula, currently under construction, (Eni’s capacity 45%, amounting to approximately 205 bcf/y) in Louisiana. Start-up is expected in late 2011. In addition, Eni finalized another agreement with the national Angolan company and other partners to be part of a second gas consortium which will explore further potential gas discoveries (Gas Project) to support the feasibility of a second LNG train. Eni is technical advisor with a 20% interest.
This Gas Project covers blocks 1, 2, 3, 15 and 15/06, the Lower Congo Basin and the Angolan offshore.
Exploration, development and production of non associated gas and condensates are initially foreseen only in Block 2 (Open Areas). In 2009 seismic data have been acquired. The first appraisal well of the project is scheduled in the second half of 2010. Congo
Eni has been present in Congo since 1968. In 2009 production averaged 102 kboe/d net to Eni. Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore covering a developed and undeveloped acreage of 15,598 square kilometers (8,188 square kilometers net to Eni).
Eni’s principal oil producing interests operated in Congo are the Zatchi (Eni’s interest 65%), Loango (Eni’s interest 50%), Ikalou (Eni’s interest 100%), Djambala, Foukanda e Mwafi (Eni’s interest 65%), Kitina (Eni’s interest 35.75%), Awa Paloukou (Eni’s interest 90%), M’Boundi (Eni’s interest 83%) and Kouakouala (Eni’s interest 75%) fields.

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Other relevant producing areas are a 35% interest in the Pointe Noire Grand Fond (Eni’s interest 35%) and Pex (Eni’s interest 35%) permits.
Eni also holds interests in the exploration phase in the deep offshore block Mer Très Profonde Sud (Eni’s interest 30%), and onshore Noumbi (Eni’s interest 37%) while it is operator with a 65% interest of the offshore Marine XII and onshore Le Kouilou permit (Eni’s interest 85%).
Exploration and production activities in the Congo are regulated by Production Sharing Agreements.
In 2009 Eni and the Republic of Congo signed a certain strategic agreements for cooperation and monetization of conventional and non conventional hydrocarbon resources. The agreement implements Eni’s model of cooperation with partner countries for integrating traditional business with sustainable development and promoting high socio-economic standards.
Production in Congo is expected to increase in the medium-term targeting a level in excess of 150 kbbl/d in 2013 due to the integration and development of recently acquired assets as well as projects underway.
Production Production is provided mainly by the M’Boundi (30 kboe/d), Zatchi (11 kboe/d) and Loango (8 kboe/d), Foukanda, Djambala and Mwafi (overall approximately 8 kboe/d) and Kitina (1.5 kboe/d) fields and by non operated fields located in production Pex and Pointe Noire Grand Fond (overall 22 kboe/d) permits.
In 2009, the development plan of Awa-Paloukou field was completed. Production start-up was 12 kbbl/d.
Development Activities on the M’Boundi operated field moved forward with the application of advanced recovery techniques and a design to monetize associated gas. In 2009, Eni signed a long-term agreement to supply associated gas from the M’Boundi field to feed three facilities in the Pointe Noire area: (i) the Koilou potassium plant, owned by Canadian Company MAG Industries and under construction; (ii) the CED (Centrale Electrique du Djeno) existing power plant; and (iii) the newly built CEC (Centrale Electrique du Congo - Eni’s interest 20%). The facilities will also receive gas in the future from the offshore discoveries of the Marine XII permit.
The development activities to build the CEC power plant moved forward in 2009 as scheduled in the Cooperation Agreement signed by Eni and the Republic of Congo in 2007, and the start-up of the first turbo-generator occurred by the end of March 2010.
Within the cooperation agreement signed in 2008, 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 apply its proprietary Eni Slurry Technology (EST) for the monetization of heavy oils extracted from these sands. 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 M’Boundi oilfield.
Exploration Exploration activities yielded positive results in: (i) the Marine XII permit (Eni operator with a 65% interest) with two discoveries wells which confirmed the mineral potential of the area. The related PSA was signed; (ii) the Le Kouilou permit (Eni’s interest 85%) with the Zingali field, confirmed by subsequently long production test. Eni applied for a development and production permit in the area. Ghana
On September 28, 2009, Eni acquired operatorship of the offshore exploration permits Cape Three Point South and Cape Three Point (Eni’s interest 47.2%). Exploration activities yielded positive results in the latter with the Sankofa discovery containing oil and natural gas. Nigeria
Eni has been present in Nigeria since 1962. In 2009, Eni’s oil and gas production averaged 128 kboe/d over a developed and undeveloped acreage of 44,048 square kilometers (8,574 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 4 onshore Oil Mining Leases (OMLS) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%), OMLs 120-121 (Eni’s interest 40%) and holds a 12.5% interest in OML 118 as well as in OML 119 and 116 service contracts. Through SPDC JV, the largest oil joint-venture in the Country, Eni also holds a 5% interest in 30 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 (Eni’s interest 60%) and OML 134 (former OPL 211 - Eni’s interest 85%) as well as onshore OPL 282 (Eni’s interest 90%) and OPL 135 (Eni’s interest 48%). Eni also holds a 12.5% interest in OML 135 (former OPL 219).
Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as in two blocks by service contracts, where Eni acts as contractor for state owned companies.
Production is expected to increase in the medium-term mainly due to the development of gas reserves. Eni’s production is expected to achieve a level of approximately 190 kboe/d, confirming Nigeria among Eni’s largest producing countries. Blocks OMLs 60, 61, 62 and 63
Production Onshore licenses OMLs 60, 61, 62 and 63 accounted for 41% of Eni’s production in Nigeria in 2009. Liquid and gas production is supported by the NGL plant at Obiafu-Obrikom with a treatment capacity of approximately 706 mmcf/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).

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Another portion of gas production is employed in firing the combined cycle power plant at Kwale-Okpai with a 480 MW generation capacity. In 2009 supplies to this power station were an overall amount of 57 mmcf/d, corresponding to approximately 10 kboe/d (2 kboe/d net to Eni). This project is part of the Nigerian government and Eni’s plans for the reduction of carbon dioxide emissions and qualifies as CDM (Clean Development Mechanism) as provided for by the Kyoto Protocol.
Development In the framework of the activities aimed at guaranteeing production to feed the Bonny LNG plant, the basic engineering work for increasing capacity at the Obiafu/Obrikom plant was completed as well as the installation of a new treatment plant and transport facilities for carrying 155 mmcf/d of feed gas for 20 years. To the same end the development plan of the Tuomo gas field has been progressing along with its linkage to the Ogbainbiri treatment plant. Block OML 125
Production The Abo field production amounted to approximately 20 kbbl/d of oil net to Eni in 2009. Ongoing development activities allowed to reach a peak production of 33 kbbl/d (24 kbbl/d net to Eni) in 2009. Production is supported by an FPSO unit with a 45 kbbl/d capacity and an 800 kbbl storage capacity. Block OML 118
Production The Bonga oil field produced 18 kbbl/d of oil net to Eni in 2009. 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 Derived mainly from the Okono/Okpoho fields which yielded 10 kbbl/d of oil net to Eni in 2009. Production is supported by an FPSO unit with an 80 kbbl/d treatment capacity and a 1 mmbbl storage capacity. Blocks OML 120 and 121
Production In 2009 production of the Oyo offshore field started-up at 25 kbbl/d. The field is linked to an FPSO unit with treatment capacity of 40 kbbl/d and storage capacity of 1 mmbbl.

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SPDC Joint Venture (NASE)
In 2009 production from the SPDC JV accounted for approximately 19% of Eni’s production in Nigeria. The Forcados/Yokri oil and gas field with recoverable reserves of 320 mmboe is under development as part of the integrated associated gas gathering project aimed at supplying gas to the Bonny liquefaction plant. Offshore production facilities have been installed. Onshore activities regard the upgrading of the Yokri and North/South Bank flowstations and the construction of a gas compression plant with a 233 mmcf/d capacity. Completion is expected in 2012.
An integrated oil and gas project is underway in the Gbaran-Ubie area. The development plan provides for the construction of a Central Processing Facility (CPF) with treatment capacity of about 1 bcf/d of gas and 120 kbbl/day of liquids, the drilling of producing wells and the construction of a pipeline to carry the gas to the Bonny liquefaction plant. First gas is expected in the third quarter of 2010. The LNG business in Nigeria
Eni holds a 10.4% interest in joint-venture Nigeria LNG Ltd which is responsible for the management of the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The seventh unit is being engineered as it is pre-fid 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. In 2009, total supplies were 1,798 mmcf/d (130 mmcf/d net to Eni corresponding to 23 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 also has a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal which is 100 kilometers west of Bonny. This plant is expected to start operating in 2015 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 60 bcf/y net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity (corresponding to approximately 81 bcf/y). The LNG will be delivered to the United States market mainly at the re-gasification plant in Cameron, in Louisiana. Eni’s capacity amounts to approximately 201 bcf/y. Front end engineering activities continued. The final investment decision is expected at the end of 2010. nKazakhstan
Eni has been present in Kazakhstan since 1992 where the Company co-operates the Karachaganak producing field and is a partner of the consortium of the North Caspian Sea PSA to develop the Kashagan field. Kashagan
Eni holds a 16.81% participating 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 in an area a encompassing approximately 4,600 square kilometers. Kashagan is believed to be one of the most important oil discoveries in the world in the past thirty-five years. Management estimates that the gross recoverable reserves of the field amount to 7-9 billion barrels, extendible to 13 billion through partial gas re-injection and a full field production plateau of 1.5 mmbbl/d.
The exploration and development activities of the Kashagan field and of the other discoveries made in the contractual area are executed through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The new North Caspian Operating Company (NCOC) BV participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni is confirmed to be the operator of phase-one of the project (the so-called "Experimental Program") and in addition will retain operatorship of the onshore operations of phase 2 of the development plan.
The production start-up is planned at the end of 2012 and are expected development costs of phase-one, amounting to $32.2 billion (excluding general and administrative expenses) of which $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities.
In the following 12-15 months the treatment and compression plant for gas reinjection will be completed reaching an installed production capacity of 370 kbbl/d in 2014. Subsequently, production capacity of phase-one is expected to step up to 450 kbbl/d, leveraging on availability of further compressor capacity for gas re-injection associated with the start-up of phase-two offshore facilities.
Phase 2 is actually in the stage of Front End Engineering Design (FEED). Karachaganak
Production Located in West onshore Kazakhstan, Karachaganak is a giant liquid and gas field with recoverable reserves of 5 bboe. Operations are conducted by the Karachakansk Petroleum

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Operating consortium (KPO) and are regulated by a Production Sharing Agreement lasting 40 years, until 2037. Eni and British Gas are cooperators of the venture both with a 32.5% interest.
In 2009 production of the Karachaganak field averaged 238 kbbl/d of liquids (70 kbbl/d net to Eni) and 883 mmcf/d of natural gas (259 mmcf/d 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 two thirds of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity in excess of 150 kbbl/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline linking to Russian export networks. The remaining third of non stabilized liquid production and volumes of associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.
Development The execution fourth treatment unit has been progressing towards completion and will enable to increase export of oil volumes to Western markets of currently non-stabilized liquids delivered to the Orenburg terminal. The construction of the Uralsk Gas Pipeline is ongoing. This new infrastructure, with a length of 150 kilometers, will link the Karachaganak field to the Kazakhstan gas network. Start-up is expected in 2010.
The engineering activities of Phase 3 of the Karachaganak project identified a staged approach to best develop the field. The project provides for the installation of gas producing and re-injection facilities to increase gas sales at the Orenburg plant up to 565 bcf/y, and the liquids production up to approximately 14 mmtonnes/y.
With the view to sanctioning the Phase 3, technical and commercial discussions with the relevant authority are ongoing. nRest of Asia China
Eni has been present in China since 1984. In 2008 Eni’s production amounted to 8 kboe/d. Activities are located in the South China Sea over a developed and undeveloped acreage of 18,698 square kilometers (18,322 square kilometers net to Eni).
Exploration and production activities in China are regulated by Production Sharing Agreements.
Production Production derives mainly from offshore blocks 16/08 and 16/09 operated by the CACT-OG consortium (Eni’s interest 16.33%). Oil production, destined to the domestic market, derives mainly from the HZ25-4 field (Eni’s interest 49%) through 7 fixed platforms underwater linked to an FPSO. Natural gas production derives mainly from the HZ21-1 field and linked to an underwater transport facility to the Zhuhai treatment plant and is sold to the national Chinese oil Company.
Development Ongoing development activities concerned mainly the HZ25-4 field, on stream since 2007, where continued the drilling of additional producing wells as planned. Following the installation of a production platform, development is underway on the HZ25-3/1 field with the drilling of the producing wells.
Exploration In April 2009 Eni signed two new PSAs related to Blocks 3/27 and 28/20 located in the South China Sea near the areas operated by CACT-OG covering a total net acreage of 18,194 square kilometers. Eni’s participating interest in the exploration stage is equal to 100%. East Timor
Eni entered East Timor in 2006 and is operator with an 80% interest of 5 offshore blocks with an undeveloped acreage of 9,999 square kilometers (7,999 square kilometers net to Eni). The firs phase of the exploration plan with a three-year term provides the acquisition seismic data and was completed during the year, and the drilling of 2 wells, the first one to be drilled in 2010. India
Eni has been present in India since 2005 and is performing exploration and development activities over a developed and undeveloped acreage of 28,164 square kilometers (10,089 square kilometers net to Eni). Eni’s main fields in production/development are located in the onshore Cambay Basin near offshore in the Cauvery Basin near the south-eastern coast.
Production In 2009 production started-up at the PY-1 gas field, part of the assets acquired from Hindustan Oil Exploration Company Ltd (Eni’s interest 47.18%), acquired in 2008 as part of the Burren deal. Gas production is sold to the local national oil company.

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Exploration Exploration in the year concerned onshore Block RJ-ONN -2003/1 (Eni operator with a 34% interest) through the drilling of 4 commitment wells and the Hindustan assets acquired: RJ-ONN-2005/1 (Eni operator with a 25% interest) and RJ-ONN-2005/2 (Eni’s interest 20%) in Rajahstan basin, as well as block AAP-ON-94/1 (Eni operator with a 40% interest) in Assam basin, located in the north-east area.
Other exploration activities were carried out at the offshore Blocks AN-DWN-2003/2 (Eni operator with a 40% interest) and MN-DWN-2002/1 (Eni’s interest 34%) located west of the Andaman islands where 3 deepwater wells are going to be drilled at the end of 2011. In Block AN-DWN-2002/1 located in the deep offshore of the eastern coast the drilling of the first commitment well is expected in late, 2010. Indonesia
Eni has been present in Indonesia since 2001. Eni’s production amounted to 21 kboe/d, mainly gas, in 2009. Activities are concentrated in the eastern offshore and onshore of Borneo, the offshore Sumatra and the onshore and offshore area of the West Timor, over a developed and undeveloped acreage of 27,675 square kilometers (16,519 square kilometers net to Eni) in 12 blocks.
In November 2009, Eni was awarded a 37.8% participating interest in the new Sanga Sanga PSA in connection with coal bed methane (CBM) production. The PSA defines terms and conditions for the exploration, development and production of gas from shallow levels of coal within a contractual area that mostly coincides with the one regulated by the Sanga Sanga PSA for the production of conventional hydrocarbons. Exploration activity start-up is expected in 2010. If the results of these preliminary activities are positive, the project will benefit from the opportunities of synergy provided by the existing production and treatment facilities in Sanga Sanga and the Bontang LNG plant.
Exploration and production activities in Indonesia are regulated by PSAs.
Production Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%) 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 Eni is involved in the ongoing joint development of the oil and gas discoveries in the Bukat permit (Eni operator with a 66.25% interest) and the five gas discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%).
In 2009 the development plan of the Jau field in the Krueng Mane Block (Eni’s interest 75%) located offshore Sumatra was submitted to the relevant Authority.
Exploration Eni holds interests in 9 exploration blocks ranging from 20% to 100%, 6 as operator. Exploration activity yielded positive results with the Jangkrik gas discovery located in the Muara Bakau Block (Eni’s interest 55%) offshore Borneo. Iran
Eni has been present in Iran since 1957. In 2009 Eni’s production averaged 35 kbbl/d. Eni’s activities are currently limited mainly to the implementation of two buy-back contracts signed between 2000 and 2001.
In 2009 activities were executed at the Darquain project which related to plant commissioning and start-up in view of making formal hand over of operations to local partners at same point in 2010. Darquain was the sole Eni-operated project in the Country.
As for the South Pars 4&5 contract, Eni’s involvement essentially consists of being reimbursed for its past investments. Iraq
On January 22, 2010, Eni leading a consortium of international companies and the Iraqi National Oil Companies, South Oil Company and Missan Oil Company signed a technical service contract, under a 20-year term with an option for further 5 years, to develop the Zubair oil field (Eni’s interest 32.8%). The field was awarded to the Eni-led consortium following a successful first bid round and was offered under a competitive bid starting on June 30, 2009. The partners of the project plan to gradually increase production to a target plateau level of 1.2 mmboe/d over the next six years. The contract provides that the consortium will earn a remuneration fee on the incremental oil production once production has been raised by 10 percent from its current level of approximately 180 kbbl/d and will recover its expenditures through a cost recovery mechanism based on the revenues from the field’s production.

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The field development plan will take place in two phases: (i) the Rehabilitation Plan, which will improve the existing production rate to gain full knowledge of the reservoir; and (ii) the Redevelopment Plan, which will increase production to the target plateau. Pakistan
Eni has been present in Pakistan since 2000. In 2009 Eni’s production averaged 58 kboe/d, mainly gas. Activities are located onshore covering a developed and undeveloped acreage of 33,904 square kilometers (18,201 square kilometers net to Eni).
Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).
In March 2009 Eni signed a Protocol for Cooperation with the government of Pakistan to develop a number of important upstream, midstream and downstream projects in the Country aimed at consolidating Eni’s role of primary international operator. Eni will provide its expertise as well as new technologies developed in the field of exploring for and developing hydrocarbon fields.
Production Eni’s main permits are Bhit (Eni’s interest 40%), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.75%), which in 2009 accounted for 88% of Eni’s production in Pakistan. In 2009 activities were targeted to optimize production from the Bhit, Sawan and Kadanwari fields by means of the drilling additional wells.
Development Activities were focused on: (i) the Bhit field with the ongoing installation of a compressor plant aimed at maintaining the current production plateau; (ii) the Sawan field where construction activity of a compressor plant is ongoing; and (iii) the Zamzama permit where activities on the third treatment plant for the production of high calorific value (HCV) gas are aimed at optimizing current production.
Exploration Eni holds interests in 14 exploration blocks (onshore and offshore) ranging from 30% and 85%, 7 operated by Eni. In September 2009, following an international bid procedure, Eni was awarded as operator an exploration license for the Sukhpur onshore block in joint-venture with another international oil company and the national Pakistani oil company. The block is located near the Bhit operated production area. In case of commercial discovery relevant operating synergies will be possible.
Exploration activity yielded positive results with discoveries in the operated Badhra, Kadanwari areas and in the Miano field (Eni’s interest 15%). The production start-up of the recent discoveries benefited from the existing producing facilities. 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 OOO SeverEnergia completed the divestment of the 51% stake in the venture to Gazprom based on the call option exercised by the Russian company. Eni collected the total cash consideration ($940 million), 25% of which had been collected at the transaction date and the remaining 75% on March 31, 2010.
The 3 companies managed by the subholding OOO SeverEnergia (Eni’s current interest 29.4%), own significant predominantly gas resources located in the Yamal Nenets region, the largest natural gas producing region in the world:
(i) OAO Arctic Gas Company owns two exploration licenses,

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Sambugursky and Yevo-Yahinskii including seven gas and condensates fields currently in the appraisal/development phase. Main fields are Sambugorskoye and Urengoiskoye; the three partners are committed to producing first gas from the Samburskoye field by June 2011, targeting a production plateau of 150 kboe/d within two years from the start of production; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensates field. Ongoing development activities moved forward bringing the wells to a sufficient level of safety as well as an acquisition seismographic data; (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chaselskoye field where a seismic acquisition campaign is underway. Saudi Arabia
Eni entered Saudi Arabia in 2004 and is performing exploration activities in the so called C area in order to discover and develop gas reserves. This license covering undeveloped acreage of 51,687 square kilometers (25,844 square kilometers net to Eni) is located in the Rub al Khali basin at the border with Qatar and the United Arab Emirates. The exploration plan provides for the drilling of 4 wells in five years. In case of a commercial discovery, the contract will last 25 years with a possible extension to a maximum of 40 years. Any gas discovered will be sold locally for power generation and as feedstock for petrochemical plants. Condensates and NGL will be sold on international markets. Turkmenistan
Eni started its activities in Turkmenistan with the purchase of British company Burren Energy plc in 2008. Activities are mainly focused in the western part of the country over developed area of 200 square kilometers net to Eni, splitted into four development areas.
In December 2009 Eni signed a Memorandum of Understanding with Turkmenistan aimed at promoting and reinforcing the partnership in the development of the oil industry of the Country. Eni will co-operate with the State Companies and the Agency for Hydrocarbons to carry out studies to ascertain the oil and gas potential of the Country. Eni will contribute its expertise in technology in order to exploit the oil & gas potential of the Country. The agreement provides for an intense training of local staff.
In 2009 Eni’s production averaged 12 kboe/d.
Exploration and production activities in Turkmenistan are regulated by PSAs.
Production Eni is operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field. Oil production is carried to the Turkmenbashi refinery plant. Eni received by the Turkmen authorities an equivalent amount of oil at the Okarem plant on the south coast of Caspian Sea where Eni’s entitlement is sold FOB. Natural gas is mostly used to own consumption and gas lift system. The remaining amount was linked to the national grid. Activities were targeted to optimize production by means of drilling 18 development wells and continuation of the program for water injection and facilities upgrading.
Exploration Activity in the year concerned mainly the appraisal of areas nearby the Burun field. Yemen
Eni has been present in Yemen since 2008 following the acquisition of Burren Energy. Activities concern the exploration phase of onshore Block 6 (Eni’s interest 92%) and onshore/offshore Block 17 (Eni’s interest 87.5%) covering an undeveloped acreage of 23,296 square kilometers (20,560 square kilometers net to Eni).
Exploration and production activities in Yemen are regulated by PSA.
In 2009 two extension of the first exploration term of Block 6, located in the oil rich Shabwa Basin, have been requested. Drilling of the first exploration well is expected in the first half of 2010.
After the Government’s approval of the PSA for Block 17, exploration activities started with the collection and processing of geological and geophysical data.
nAmerica Brazil
Eni has been present in Brazil since 1999 and is performing exploration activities over an area of 1,389 square kilometers (1,067 square kilometers net to Eni) in operated Blocks BM-S-4 (Eni’s interest 50%) located in the Santos basin and BM-CAL-14 (Eni’s interest 100%) in the deep offshore of the Camamu-Almada basin. The awarding of the Block BM-S-M-857 in the deep offshore Santos basin has not yet been completed.
The current exploration program aims at appraising the Belmonte gas discovery in Block BM-S-4. Ecuador
Eni has been present in Ecuador since 1988. In 2009 Eni’s production averaged 14 kbbl/d. Activities are performed in Block 10 (Eni’s interest 100%) located in the Amazon forest over a developed acreage of 2,000 square kilometers net to Eni.
Exploration and production activities in Ecuador are regulated by a service contract.
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. During the year workover activities was performed and the Villano Phase 4-A started. The project provides for the drilling of 3 infilling wells to contrast the natural depletion. Trinidad & Tobago
Eni has been present in Trinidad & Tobago since 1970. In 2009 Eni’s production averaged 67 mmcf/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 & Tobago are regulated by PSAs.

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Production Production is provided by the Chaconia, Ixora and Hibiscus gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.4%). Production is supported by fixed platforms linked to the Hibiscus treatment facility.
Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant under long-term contracts. LNG production is sold in the United States, Spain and the Dominican Republic.
Development The main development project underway concerns the Poinsettia, Bougainvillea and Heliconia fields. The project provides for the installation of a production platform on the Poinsettia field and the linkage to the Hibiscus treatment facility which was already upgraded. The drilling program on Heliconia and Bougainvillea fields is underway. Start-up is expected in 2010. In 2009 production started-up as scheduled at the Poinsettia field. United States
Eni has been present in the United States since 1968. Activities are performed in the Gulf of Mexico and more recently in Alaska.
In May 2009, Eni signed a strategic alliance with Quicksilver Resources Inc, an independent US natural gas producer, to acquire a 27.5% interest in the Alliance area, in the Fort Worth basin, in Texas. The acquisition for cash consideration amounting to $280 million includes gas shale production assets with 40 mmbbl of resources base. Production plateau at 10 kboe/d net to Eni is expected in 2011.
Developed and undeveloped acreage covers 11,097 square kilometers (6,450 square kilometers net to Eni). In 2009 oil and gas production net to Eni amounted to 119 kboe/d.
Exploration and production activities in the United States are regulated by concessions. Gulf of Mexico
Eni holds interests in 370 exploration and production blocks in the deep and conventional offshore, 60% operated.

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Production The main fields operated by Eni with a 100% interest are Allegheny, East Breaks and Morphet. Eni is operator in joint-venture in the Devils Towers, King Kong, Longhorn, Pegasus, San Jacinto, Triton and Goldfinger fields. Eni also holds interests in the Medusa (Eni’s interest 25%) and Europa (Eni’s interest 32%) fields.
In 2009 production start-up was achieved in: (i) the Thunderhawk field (Eni’s interest 25%) through the drilling of underwater wells and linkage to a semi-submersible production unit with a treatment capacity of 45 kbbl/d of oil and about 71 mmcf/d of natural gas; (ii) the Longhorn field (Eni’s interest 75%) through the drilling of underwater wells and installation of production platform with a treatment capacity of approximately 247 mmcf/d; (iii) the Leo field (Eni’s interest 75%) by means of the linkage to the Longhorn production facilities.
DevelopmentThe development plan of the Appaloosa discovery (Eni’s interest 100%) was approved. The project provides for the linkage an underwater oil well to the operated Corral platform at nearby Longhorn field. Production start-up is expected in 2010 peaking at 1.5 kboe/d.
Exploration Exploration activities yielded positive results in the following blocks: (i) offshore Green Canyon 859 (Eni’s interest 12.5%) with the oil and gas Heidelberg-1 discovery at a water depth of 9,163 meters; (ii) Keathley Canyon 919 (Eni’s interest 25%) with the oil and gas Hadrian West discovery. Alaska
Eni holds interest in 173 exploration and development blocks with stake ranging from 10% to 100%, over half as operator.
Production The Ooguruk oil field (Eni’s interest 30%) produce 6 kbbl/d (2 kbbl/d net to Eni) in 2009. Production is treated at the onshore DS-3H plant. A peak of 3 kbbl/d net to Eni is expected in 2013.
Development Current activities concern the phased development plan of the Nikaitchuq oil field (Eni operator with a 100% interest), located in the North Slope. The project provides for the drilling 52 wells, of these 22 onshore and the remaining ones from a floating artificial island and linked to a treatment plant to be built at Oliktok Point. First oil is expected in early 2011 with a plateau of 28 kbbl/d. Venezuela
Eni has been present in Venezuela since 1998. In 2009 Eni’s production averaged 8 kbbl/d. Activity is concentrated in the Gulf of Venezuela and in the Gulf of Paria over a developed and undeveloped acreage of 1,556 square kilometers (614 square kilometers net to Eni).
Activities in Venezuela are regulated by an arrangement called Empresa Mixta. Under this regime, a company incorporated under the law of Venezuela is entitled to relevant mineral rights and to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of PDVSA preferably Corporación Venezuelana de Petróleo.
Production Production derives from the Corocoro field (Eni’s interest 26%) in the Gulf of Paria West. The plan provides for two phases, the second development phase will depend on the results achieved in the first one regarding well production rate and field performance under water and gas injection. A production peak of 40 kbbl/d (10 net to Eni) is expected in 2012.
Development In January 2010 Eni and the Venezuelan National Oil Company PDVSA signed an agreement for the joint development of the giant Junin 5 field with 35 billion barrels of certified heavy oil in place, located in the Orinoco oil belt. Production start-up is planned for 2013 at an initial level of 75 kbbl/d and a long-term production plateau of 240 kbbl/d is targeted. The agreement will be sanctioned in the next two months and provides for the establishment of an Empresa Mixta (Eni 40%, PDVSA 60%) and the payment by Eni of a $300 million bonus. Additional $346 million will be paid with the progress of the project. Finally, Eni will present a project for the construction of a power plant in the Guiria peninsula.
Exploration A large gas discovery was made with the Perla field, located in the Cardon IV block (Eni’s interest 50%) in the Gulf of Venezuela, yielding 21 mmcf/d (approximately 3.7 kboe/d) during flow tests. The field has been estimated to contain a reserve potential of more than 5,650 billion cubic feet of gas (1 billion of barrels of oil equivalent). In 2010 the Perla 2 well has been successfully drilled. The development plan targets about 353 mmcf/d by 2013.
Other activities are concentrated in: (i) the offshore Blanquilla and Tortuga areas (Eni’s interest 20%) in the Caribbean Sea over an area of approximately 5,000 square kilometers; (ii) Gulf of Paria Central (Eni’s interest 19.5%), covering an area of 259 square kilometers, where the Punta Sur oil discovery is located. nAustralia and Oceania Australia
Eni has been present in Australia since 2000. In 2009 Eni’s production of oil and natural gas averaged 17 kboe/d. Activities are focused on conventional and deep offshore fields over a developed and undeveloped area of 48,509 square kilometers (20,304 square kilometers net to Eni).
The main production blocks in which Eni holds interests are WA-33-L (Eni’s interest 100%), WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Eni’s interest 10.99%). In the exploration phase Eni holds interests in 13 licenses (in 8 as operator and in 4 of which with a 100% interest), of particular interest are the Albers blocks (WA-362/363/386/387-P in the rich Carnarvon basin) and JPDA

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06-15 (Eni’s interest 40%), where the Kitan discovery is located. The Kitan development activities started in April 2010.
Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between East Timor and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.
In the medium-term, Eni’s production in this Country is expected to increase through ongoing development activities. Block WA-25-L
Production The Woollybutt oil field, started-up in 2003, produced approximately 3 kbbl/d (approximately 2 kbbl/d net to Eni) in 2009. The field is operated by an FPSO unit. Block JPDA 03-13
Production The liquids and gas Bayu Undan field, started-up in 2004, produced 195 kboe/d (14 kboe/d net to Eni) in 2009. 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. A further development phase (phase 2) is being studied aimed at increasing liquids production and maintaining the field’s production profile. Block WA-33-L
Production In 2009, the Blacktip gas field (Eni’s interest 100%) started-up at 1 kboe/d. The project is supported by a production platform and carried by a 180-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. Peak production at 71 mmcf/d is expected in 2010.
Exploration Exploration underway is aimed at appraising the residual mineral potential of the area to capture new commercial opportunities. The evaluation of recent exploration leases is ongoing.

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Eni Fact BookExploration & Production

Estimated net proved hydrocarbons reserves by geographic area ^(a) (mmboe) 2005 2006 2007 ^(b) 2008 ^(b) 2009 ^(b)

(at December 31)
Italy	868	805	747	681	703
of which:
developed	620	562	534	465	490
undeveloped	248	243	213	216	213
Rest of Europe	781	706	638	525	590
of which:
developed	626	586	537	417	432
undeveloped	155	120	101	108	158
North Africa	2,026	2,018	1,879	1,922	1,922
of which:
developed	1,230	1,242	1,183	1,229	1,266
undeveloped	796	776	696	693	656
West Africa	1,279	1,122	1,095	1,146	1,141
of which:
developed	793	798	766	827	799
undeveloped	486	324	329	319	342
Kazakhstan	1,087	1,219	1,061	1,336	1,221
of which:
developed	548	525	494	647	614
undeveloped	539	694	567	689	607
Rest of Asia	271	235	198	265	236
of which:
developed	194	161	127	168	139
undeveloped	77	74	71	97	97
America	332	150	259	235	263
of which:
developed	223	82	158	133	168
undeveloped	109	68	101	102	95
Australia and Oceania	152	145	133	132	133
of which:
developed	41	76	63	62	122
undeveloped	111	69	70	70	11
Equity-accounted entities	41	36	360	358	362
of which:
developed	31	27	63	68	74
undeveloped	10	9	297	290	288
Total	6,837	6,436	6,370	6,600	6,571
of which:
developed	4,306	4,059	3,925	4,016	4,104
undeveloped	2,531	2,377	2,445	2,584	2,467

Reserve life index ^(b) (years) 2005 2006 2007 2008 2009

Italy	9.2	9.3	9.7	9.3	11.4
Rest of Europe	7.3	6.6	6.5	5.8	6.6
North Africa	11.7	10.0	8.8	8.2	9.3
West Africa	10.2	8.3	9.2	9.5	8.9
Kazakhstan	29.4	32.1	26.0	32.9	29.0
Rest of Asia	6.8	6.1	13.2	12.8	11.1
America	7.4	5.7	8.1	5.9	5.0
Australia and Oceania	18.7	14.9	19.7	21.0	21.5
	10.8	10.0	10.0	10.0	10.2

Reserve replacement ratio, all sources ^(b) (%) 2005 2006 2007 2008 2009

Italy	77	28	25	10	136
Rest of Europe	52	27	30	-	174
North Africa	60	95	36	118	99
West Africa	42	-	76	142	106
Kazakhstan	-	447	-	776	-
Rest of Asia	-	-	791	248	-
America	-	-	474	40	144
Australia and Oceania	537	25	-	75	112
	40	38	90	135	96

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

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Eni Fact BookExploration & Production

Estimated net proved liquids reserves by geographic area ^(a) (mmbbl) 2005 2006 2007 ^(b) 2008 ^(b) 2009 ^(b)

(at December 31)
Italy	228	215	215	186	233
of which:
developed	149	136	133	111	141
undeveloped	79	79	82	75	92
Rest of Europe	433	386	345	277	351
of which:
developed	353	329	299	222	218
undeveloped	80	57	46	55	133
North Africa	961	982	878	823	895
of which:
developed	697	713	649	613	659
undeveloped	264	269	229	210	236
West Africa	936	786	725	783	770
of which:
developed	568	546	511	576	544
undeveloped	368	240	214	207	226
Kazakhstan	778	893	753	911	849
of which:
developed	266	262	219	298	291
undeveloped	512	631	534	613	558
Rest of Asia	82	62	44	106	94
of which:
developed	68	53	35	92	45
undeveloped	14	9	9	14	49
America	291	98	138	131	153
of which:
developed	193	54	81	74	80
undeveloped	98	44	57	57	73
Australia and Oceania	39	35	29	26	32
of which:
developed	37	33	26	23	23
undeveloped	2	2	3	3	9
Equity-accounted entities	25	24	92	92	86
of which:
developed	19	18	21	27	34
undeveloped	6	6	71	65	52
Total	3,773	3,481	3,219	3,335	3,463
of which:
developed	2,350	2,144	1,974	2,036	2,035
undeveloped	1,423	1,337	1,245	1,299	1,428

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

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Eni Fact BookExploration & Production

Estimated net proved natural gas reserves by geographic area ^(a) (bcf) 2005 2006 2007 ^(b) 2008 ^(b) 2009 ^(b)

(at December 31)
Italy	3,676	3,391	3,057	2,844	2,704
of which:
developed	2,704	2,449	2,304	2,031	2,001
undeveloped	972	942	753	813	703
Rest of Europe	1,999	1,835	1,675	1,421	1,380
of which:
developed	1,567	1,480	1,364	1,122	1,231
undeveloped	432	355	311	299	149
North Africa	6,117	5,946	5,751	6,311	5,894
of which:
developed	3,060	3,042	3,065	3,537	3,486
undeveloped	3,057	2,904	2,686	2,774	2,408
West Africa	1,965	1,927	2,122	2,084	2,127
of which:
developed	1,289	1,447	1,469	1,443	1,463
undeveloped	676	480	653	641	664
Kazakhstan	1,774	1,874	1,770	2,437	2,139
of which:
developed	1,618	1,511	1,580	2,005	1,859
undeveloped	156	363	190	432	280
Rest of Asia	1,083	992	880	911	814
of which:
developed	728	614	530	439	539
undeveloped	355	378	350	472	275
America	238	299	696	600	629
of which:
developed	169	159	442	340	506
undeveloped	69	140	254	260	123
Australia and Oceania	649	633	598	606	575
of which:
developed	24	247	213	221	565
undeveloped	625	386	385	385	10
Equity-accounted entities	90	68	1,541	1,534	1,588
of which:
developed	70	48	237	230	234
undeveloped	20	20	1,304	1,304	1,354
Total	17,591	16,965	18,090	18,748	17,850
of which:
developed	11,229	10,997	11,204	11,368	11,884
undeveloped	6,362	5,968	6,886	7,380	5,966

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

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Eni Fact BookExploration & Production

Production of oil and natural gas by country ^(a) (kboe/d) 2005 2006 2007 2008 2009

Italy	261	238	212	199	169
Rest of Europe	290	294	270	249	247
Croatia	7	12	9	12	17
Norway	138	140	137	129	126
United Kingdom	145	142	124	108	104
North Africa	480	555	594	645	573
Algeria	88	91	88	83	83
Egypt	213	227	238	240	230
Libya	164	222	252	306	244
Tunisia	15	15	16	16	16
West Africa	343	372	327	335	360
Angola	124	156	136	126	130
Congo	67	67	69	87	102
Nigeria	152	149	122	122	128
Kazakhstan	102	103	112	111	115
Rest of Asia	118	111	108	124	135
China	7	8	8	8	8
India					1
Indonesia	27	23	20	20	21
Iran	35	29	26	28	35
Pakistan	49	51	52	56	58
Russia			2
Turkmenistan				12	12
America	121	71	95	117	153
Ecuador	17	15	16	16	14
Trinidad & Tobago	10	9	10	9	12
United States	33	32	69	87	119
Venezuela	61	15		5	8
Australia and Oceania	22	26	18	17	17
Australia	22	26	18	17	17
Total outside Italy	1,476	1,532	1,524	1,598	1,600
	1,737	1,770	1,736	1,797	1,769

(a) Includes production volumes of natural gas consumed in operations (300, 281, 296, 286 and 247 mmcf/d, in 2009, 2008, 2007, 2006 and 2005, respectively).

Oil and natural gas production sold (mmboe) 2005 2006 2007 2008 2009

Oil and natural gas production		634.2		645.9		633.7		657.5		645.7
Change in inventories/other		(3.1	)	(2.4	)	(3.5	)	(7.6	)	(3.8	)
Own consumption of gas		(16.2	)	(18.4	)	(18.8	)	(17.9	)	(19.1	)
Oil and natural gas production sold		614.9		625.1		611.4		632.0		622.8
Oil	(mmbbl)	402.60		391.07		370.28		370.24		365.20
- of which to R&M division		267.37		267.84		227.68		194.64		224.98
Natural gas	(bcf)	1,219		1,344		1,385		1,503		1,479
- of which to G&P division		377		534		510		480		444

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Eni Fact BookExploration & Production

Liquids production by Country (kbbl/d) 2005 2006 2007 2008 2009

Italy	86	79	75	68	56
Rest of Europe	179	178	157	140	133
Norway	96	98	90	83	78
United Kingdom	83	80	67	57	55
North Africa	308	329	337	338	292
Algeria	86	88	85	80	80
Egypt	90	85	97	98	91
Libya	120	144	142	147	108
Tunisia	12	12	13	13	13
West Africa	310	322	280	289	312
Angola	122	151	132	121	125
Congo	65	65	67	84	97
Nigeria	123	106	81	84	90
Kazakhstan	64	64	70	69	70
Rest of Asia	46	38	37	49	57
China	7	6	6	6	7
Indonesia	3	2	2	2	2
Iran	35	29	26	28	35
Pakistan	1	1	1	1	1
Russia			2
Turkmenistan				12	12
America	97	51	53	63	79
Ecuador	17	15	16	16	14
United States	19	21	37	42	57
Venezuela	61	15		5	8
Australia and Oceania	21	18	11	10	8
Australia	21	18	11	10	8
Total outside Italy	1,025	1,000	945	958	951
	1,111	1,079	1,020	1,026	1,007

Natural gas production by Country ^(a) (mmcf/d) 2005 2006 2007 2008 2009

Italy	1,002.9	911.4	789.7	749.9	652.6
Rest of Europe	642.8	663.8	647.2	626.7	655.5
Croatia	42.4	66.8	52.5	68.7	95.5
Norway	243.7	245.2	271.1	264.8	273.7
United Kingdom	356.7	351.8	323.6	293.2	286.3
North Africa	988.8	1,299.1	1,474.2	1,761.6	1,614.2
Algeria	14.1	19.4	18.8	18.5	19.7
Egypt	706.3	813.4	811.2	818.4	793.7
Libya	254.3	452.1	629.6	907.6	780.4
Tunisia	14.1	14.2	14.6	17.1	20.4
West Africa	190.7	281.7	274.2	260.7	274.3
Angola	17.7	24.1	25.1	28.1	29.3
Congo	7.1	9.8	11.4	12.7	27.3
Nigeria	165.9	247.8	237.7	219.9	217.7
Kazakhstan	222.5	227.6	237.9	244.7	259.0
Rest of Asia	413.2	416.7	408.9	426.2	444.8
China		9.4	11.0	10.9	8.2
India					3.7
Indonesia	137.7	118.1	105.4	99.7	104.8
Pakistan	275.5	289.2	292.5	315.6	328.1
America	130.7	116.0	240.3	311.5	424.7
Trinidad & Tobago	56.5	51.7	58.9	54.6	67.0
United States	74.2	64.3	181.4	256.9	357.7
Australia and Oceania	3.5	47.9	41.5	42.2	48.6
Australia	3.5	47.9	41.5	42.2	48.6
Total outside Italy	2,592.2	3,052.8	3,324.2	3,673.6	3,721.1
	3,595.1	3,964.2	4,113.9	4,423.5	4,373.7

(a) Includes production volumes of natural gas consumed in operations (300, 281, 296, 286 and 247 mmcf/d, in 2009, 2008, 2007, 2006 and 2005, respectively).

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Eni Fact BookExploration & Production

Production of oil and natural gas available for sale ^(a) (kboe/d) 2005 2006 2007 2008 2009

Italy	256	233	208	195	165
Rest of Europe	284	286	263	242	239
North Africa	465	536	573	627	554
West Africa	336	363	318	325	349
Kazakhstan	99	101	109	108	113
Rest of Asia	112	105	101	119	130
America	120	71	94	116	150
Australia and Oceania	21	25	18	16	16
	1,693	1,720	1,684	1,748	1,716

Natural gas production available for sale ^(a) (mmcf/d) 2005 2006 2007 2008 2009

Italy	972	883	763	725	630
Rest of Europe	605	622	607	588	608
North Africa	900	1,187	1,357	1,661	1,503
West Africa	151	232	220	204	213
Kazakhstan	207	214	222	227	241
Rest of Asia	382	386	380	396	417
America	127	112	232	304	416
Australia and Oceania		43	38	38	46
	3,344	3,679	3,819	4,143	4,074

(a) Do not include natural gas consumed in operation (300, 281, 296, 286 and 251 mmcf/d, in 2009, 2008, 2007, 2006 and 2005, respectively).

Average realizations by geographic area Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2005
Liquids	($/bbl)	45.50	52.67	50.11	51.45	41.87	47.73	39.24	52.85	49.09
Natural gas	($/mmcf)	6.32	5.35	3.37	0.79	0.35	4.05	7.21		4.49
Hydrocarbon	($/boe)	39.41	44.48	39.56	47.79	27.38	33.27	39.64	52.85	41.06
2006
Liquids	($/bbl)	55.22	63.01	60.99	61.55	53.18	58.70	50.53	65.12	60.09
Natural gas	($/mmcf)	8.23	7.09	4.17	1.05	0.39	4.24	5.92	4.86	5.29
Hydrocarbon	($/boe)	49.93	54.38	46.71	55.10	34.13	36.66	45.93	53.68	48.87
2007
Liquids	($/bbl)	62.47	70.84	67.86	69.77	59.34	64.73	66.37	71.23	67.70
Natural gas	($/mmcf)	8.58	6.71	4.60	1.21	0.41	4.34	6.69	5.94	5.42
Hydrocarbon	($/boe)	54.03	57.95	50.47	62.36	38.98	39.24	54.23	57.72	53.17
2008
Liquids (a)	($/bbl)	84.87	71.90	84.71	91.58	79.06	75.08	88.69	82.80	84.05
Natural gas	($/mmcf)	13.06	10.55	7.14	1.50	0.53	5.50	8.81	9.59	8.01
Hydrocarbon	($/boe)	78.46	67.15	64.64	81.77	51.30	49.60	71.05	71.43	68.13
2009
Liquids (a)	($/bbl)	56.02	56.46	55.97	59.75	52.34	55.23	55.74	50.40	56.95
Natural gas	($/mmcf)	9.01	7.06	5.78	1.66	0.45	4.30	4.05	8.14	5.62
Hydrocarbon	($/boe)	53.16	49.53	45.26	54.61	33.64	38.34	40.22	48.68	46.90

(a)

In 2008 Eni’s liquid realizations amounted to $84.05 per barrel and were reduced by approximately $4.13 per barrel due to the settlement of certain commodity derivatives relating to the sale of 46 mmbbl in the year. This was part of a derivative transaction the Company entered into to hedge exposure to variability in future cash flows expected from the sale of a portion of the Company’s proved reserves for an original amount of approximately 125.7 mmbbl in the 2008-2011 period, decreasing to 79.7 mmbbl by the end of December 2008.

(b)

In 2009 Eni’s liquid realizations amounted to $56.95 per barrel and were marginally affected ($0.03 per barrel) by the settlement of certain commodity derivatives relating to the sale of 42.2 mmbbl in the year (37.5 mmbbl at the end of December 2009).

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Eni Fact BookExploration & Production

Principal oil and natural gas interests at December 31, 2009

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

EUROPE		315	17,918	11,794	33,643	19,813		143	105
Italy	1926	167	11,641	9,692	15,537	12,346	Onshore/Offshore	87	84
Rest of Europe		148	6,277	2,102	18,106	7,467		56	21
Croatia	1996	2	1,975	987			Offshore	9	3
Norway	1965	51	2,277	338	8,907	3,074	Offshore	15	6
United Kingdom	1964	89	2,025	777	3,140	692	Offshore	32	12
Other countries		6			6,059	3,701	Offshore
AFRICA		276	70,121	19,865	230,549	138,884		272	130
North Africa		119	30,820	13,431	54,725	32,580		101	56
Algeria	1981	38	2,152	727	17,458	16,517	Onshore	26	15
Egypt	1954	57	4,445	1,571	18,652	6,757	Onshore/Offshore	39	24
Libya	1959	13	17,947	8,951	18,427	9,214	Onshore/Offshore	12	15
Tunisia	1961	11	6,276	2,182	188	92	Onshore/Offshore	24	2
West Africa		151	39,301	6,434	98,600	54,090		171	74
Angola	1980	67	4,532	590	16,317	2,803	Onshore/Offshore	47	27
Congo	1968	25	1,865	991	13,724	7,197	Onshore/Offshore	24	6
Gabon	2008	6			7,615	7,615	Onshore/Offshore
Ghana	2009	2			2,300	1,086	Offshore
Mali	2006	1			47,500	31,668	Onshore
Nigeria	1962	50	32,904	4,853	11,144	3,721	Onshore/Offshore	100	41
Other countries		6			77,224	52,214	Onshore/Offshore
ASIA		80	18,924	6,369	204,274	119,272		38	29
Kazakhstan	1992	6	324	105	4,609	775	Onshore/Offshore	1	5
Rest of Asia		74	18,600	6,264	199,665	118,497		37	24
China	1984	7	237	39	18,461	18,283	Offshore	10	1
East Timor	2006	5			9,999	7,999	Offshore
India	2005	14	303	143	27,861	9,946	Onshore/Offshore	5	1
Indonesia	2001	12	1,735	656	25,940	15,863	Onshore/Offshore	7	13
Iraq	2009	1	1,950	640			Onshore		1
Iran	1957	4	1,456	820			Onshore/Offshore	3
Pakistan	2000	21	9,122	2,708	24,782	15,493	Onshore/Offshore	10
Russia	2007	5	3,597	1,058	3,039	1,265	Onshore		8
Saudi Arabia	2004	1			51,687	25,844	Onshore
Turkmenistan	2008	1	200	200			Onshore	2
Yemen	2008	2			23,296	20,560	Onshore/Offshore
Other countries		1			14,600	3,244	Offshore
AMERICA		558	4,737	3,090	17,234	8,433		73	19
Brazil	1999	2			1,389	1,067	Offshore
Ecuador	1988	1	2,000	2,000			Onshore	1	1
Trinidad & Tobago	1970	1	382	66			Offshore	4	3
United States	1968	543	1,977	926	9,120	5,524	Onshore/Offshore	67	13
Venezuela	1998	3	378	98	1,178	516	Offshore	1	1
Other countries		8			5,547	1,326	Offshore		1
AUSTRALIA AND OCEANIA		17	1,057	676	48,216	19,666		3	3
Australia	2001	16	1,057	676	47,452	19,628	Offshore	3	3
Other countries		1			764	38	Offshore
Total		1,246	112,757	41,794	533,916	306,068		529	286

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

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Eni Fact BookExploration & Production

Net developed and undeveloped acreage (square kilometers) 2005 2006 2007 2008 2009

Europe	41,534	37,716	32,055	30,511	31,607
Italy	24,053	22,496	20,664	20,409	22,038
Rest of Europe	17,481	15,220	11,391	10,102	9,569
Africa	125,520	230,700	227,932	249,672	158,749
North Africa	66,456	63,557	62,886	31,088	46,011
West Africa	19,202	111,400	112,832	156,557	60,524
Other countries	39,862	55,743	52,214	62,027	52,214
Asia	66,760	74,013	80,339	93,710	125,641
Kazakhstan	959	960	959	880	880
Rest of Asia	65,801	73,053	79,380	92,830	124,761
America	9,802	10,618	12,804	12,043	11,523
Australia and Oceania	22,386	32,172	41,361	29,558	20,342
Total	266,002	385,219	394,491	415,494	347,862

Capital expenditures (euro million) 2005 2006 2007 2008 2009

Acquisition of proved and unproved property	301	152	96	836	697
Italy		139
North Africa		10	11	626	351
West Africa	60			210	73
Kazakhstan	169
Rest of Asia					94
America	49	3	85		179
Australia and Oceania	23
Exploration	656	1,348	1,659	1,918	1,228
Italy	38	128	104	135	40
Rest of Europe	127	180	195	227	113
North Africa	153	270	373	379	317
West Africa	75	471	246	485	284
Kazakhstan	15	25	36	16	20
Rest of Asia	64	101	162	187	159
America	158	138	505	441	243
Australia and Oceania	26	35	38	48	52
Development	3,919	3,589	4,643	6,429	7,478
Italy	378	363	461	570	689
Rest of Europe	463	451	429	598	673
North Africa	1,007	701	948	1,246	1,381
West Africa	889	864	1,343	1,717	2,105
Kazakhstan	593	593	733	968	1,083
Rest of Asia	285	254	238	355	406
America	271	339	345	655	706
Australia and Oceania	33	24	146	320	435
Other expenditures	56	74	82	98	83
	4,932	5,163	6,480	9,281	9,486

Economic indicators per boe ($/boe) 2005 2006 2007 2008 2009

Lifting cost (a)	5.5	5.6	6.7	7.5	7.3
Exploration cost (three-year average) - discovery cost (b)	1.67	2.86	7.8	5.2	4.9
Finding and development cost (three-year average) (c)	10.72	13.87	29.1	20.4	22.9
Income	12.20	14.97	14.03	15.8	7.96

(a)	Ratio of production costs (costs incurred to operate and maintain wells and related equipment and facilities and royalties) to volumes produced.
(b)	Exploration cost for each boe of new reserves added is calculated as ratio of costs incurred with respect to exploration activity and purchase of unproved property to proved reserve additions related to improved recovery, extensions and new discoveries and revisions of previous estimates. Data for 2007 and 2008 were calculated based on amounts determined in accordance with IFRS. Previous year data were in accordance with U.S. GAAP. Differences between the amounts determined under the two bodies of accounting standards were immaterial. Data disclosed in the table were calculated excluding the purchase costs of probable and possible reserves and other resources which were incurred in connection with acquisitions of properties and corporations, particularly the assets acquired in the Gulf of Mexico, Congo and Russia (according to a 60% interest) in 2007 as well as in Congo, Turkmenistan and Algeria in 2008.
(c)	Finding and development cost for each boe of new reserves added is calculated as ratio of costs incurred with respect to exploration and development activities and purchase of unproved property to proved reserve additions related to improved recovery, extensions and new discoveries and revisions of previous estimates. Data for 2007 and 2008 were calculated based on amounts determined in accordance with IFRS. Previous year data were in accordance with U.S. GAAP. Differences between the amounts determined under the two bodies of accounting standards were immaterial. Data disclosed in the table were calculated excluding the purchase costs of probable and possible reserves and other resources which were incurred in connection with acquisitions of properties and corporations, particularly the assets acquired in the Gulf of Mexico, Congo and Russia (according to a 60% interest) in 2007 as well as in Congo, Turkmenistan and Algeria in 2008. Data also excluded development costs incurred in connection with Iranian buy-back contracts and costs estimated to be incurred in connection with asset retirement obligations.

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Eni Fact BookExploration & Production

Net exploration and development drilling activity (units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2007
Exploratory	4.0	1.4	15.3	1.7	0.2	0.2	9.6	0.6	33.0
Productive	0.5		7.7	0.5		0.2	3.6		12.5
Dry (a)	3.5	1.4	7.6	1.2	0.2		6.0	0.6	20.5
Development	17.0	27.3	45.8	18.5	1.3	37.8	8.4	0.6	156.7
Productive	17.0	27.2	45.8	18.5	1.3	34.1	5.9	0.6	150.4
Dry (a)		0.1				3.7	2.5		6.3
2008
Exploratory	0.7	3.7	22.9	7.4		16.2	3.4	1.4	55.7
Productive		0.7	8.7	4.0		9.4	1.4		24.2
Dry (a)	0.7	3.0	14.2	3.4		6.8	2.0	1.4	31.5
Development	12.9	5.5	47.6	37.2	2.6	43.0	6.3		155.1
Productive	11.3	5.5	46.4	36.4	2.6	36.5	6.3		145.0
Dry (a)	1.6		1.2	0.8		6.5			10.1
2009
Exploratory	1.0	4.3	8.6	2.7		6.2	4.8	2.2	29.8
Productive		4.1	4.8			2.3	1.0	0.8	13.0
Dry (a)	1.0	0.2	3.8	2.7		3.9	3.8	1.4	16.8
Development	18.3	12.5	41.1	37.7	3.8	42.9	16.6	2.2	175.1
Productive	18.3	12.5	40.7	35.8	3.8	38.6	15.6	2.2	167.5
Dry (a)			0.4	1.9		4.3	1.0		7.6

(a) 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.

Drilling activity in progress (units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2009
Exploratory (a)
gross	6.0	25.0	26.0	60.0	13.0	19.0	22.0	1.0	172.0
net	4.4	6.6	18.6	15.4	2.3	8.8	8.4	1.0	65.5
Development
gross	6.0	8.0	16.0	23.0	2.0	13.0	47.0	1.0	116.0
net	5.8	1.2	6.9	8.2	0.7	6.2	12.1	0.1	41.2

(a) Included long-term suspended wells pending further evaluation.

Productive oil and gas wells ^(a) (units) Italy Rest of Europe North Africa West Africa Kazakhstan Rest of Asia America Australia and Oceania Total

2009 (b)
Oil wells
gross	185.0	384.0	1,103.0	2,764.0	85.0	355.0	125.0	4.0	5,005.0
net	145.7	64.5	469.2	474.3	27.6	255.1	56.3	2.6	1,495.3
Gas wells
gross	481.0	198.0	120.0	501.0		658.0	207.0	11.0	2,176.0
net	421.1	75.2	49.1	36.6		264.3	72.6	3.0	921.9

(a)	Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.
(b)	Includes approximately 2,144 gross (633 net to Eni) multiple wells (more than one producing into the same well bore).

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Eni Fact BookGas & Power

Key performance indicators ^(a) 2005 2006 2007 2008 2009

Net sales from operations (b)	(euro million)	23,174	28,547	27,793	37,062	30,447
Operating profit		3,580	4,022	4,465	4,030	3,687
Adjusted operating profit		3,784	4,117	4,414	3,564	3,901
Market		1,713	2,035	2,284	1,309	1,721
Regulated businesses in Italy		1,776	1,610	1,685	1,732	1,796
International transport		295	472	445	523	384
Adjusted net profit		2,704	3,002	3,127	2,648	2,916
EBITDA pro-forma adjusted		4,213	4,841	5,029	4,310	4,403
Market		2,505	2,973	3,061	2,271	2,392
Regulated businesses in Italy		1,160	1,160	1,248	1,284	1,345
International transport		548	708	720	755	666
Capital expenditures		1,185	1,214	1,511	2,058	1,686
Adjusted capital employed, net at year end		19,995	19,671	21,364	22,273	25,024
Adjusted ROACE	(%)	13.7	15.1	15.2	12.2	12.3
Worldwide gas sales	(bcm)	94.21	98.10	98.96	104.23	103.72
of which: E&P sales (c)		4.51	4.69	5.39	6.00	6.17
LNG sales (d)		7.00	9.90	11.70	12.00	12.90
Customers in Italy	(million)	6.02	6.54	6.61	6.63	6.88
Gas volumes transported in Italy	(bcm)	85.10	87.99	83.28	85.64	76.9
Electricity sold	(TWh)	27.56	31.03	33.19	29.93	33.96
Employees at year end	(units)	12,615	12,370	11,582	11,692	11,404

(a)	From January 1, 2009, results of the gas storage business are reported within the Gas & Power segment reporting unit, within the regulated businesses results, following restructuring of Eni regulated gas businesses in Italy. As of that date, the results of the regulated businesses in Italy therefore include results of the Transport, Distribution, Regasification and Storage activities in Italy. Results of the power generation activity are reported within the marketing business as it is ancillary to the latter. Prior period results have been restated accordingly.
(b)	Before the elimination of intragroup sales.
(c)	Exploration & Production sales in Europe and in the Gulf of Mexico.
(d)	Refer to LNG sales of the G&P division (included in worldwide gas sales) and the E&P division.

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Eni Fact BookGas & Power

2009 Highlights

Presentation to the European Commission of a set of structural remedies related to some international gas pipelines
IOn February 4, 2010, Eni formally presented to the European Commission a set of structural remedies relating to certain international gas pipelines. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines.
In case the Commission approves those remedies, Eni will be in the position to resolve an inquiry started in May 2006 for alleged infringement of the European antitrust regulations in the gas sector, which involved the main players in European gas market. European gas market
IIn 2009, the mandatory tender offer on the minorities of Distrigas was finalized and Distrigas shares have been delisted from Euronext Brussels. The Distrigas acquisition represented for Eni a remarkable result in strengthening its leadership in the European gas market.
Despite the unfavorable trends in natural gas demand, in 2009 Eni achieved organic growth outside Italy, increasing market shares in target European gas markets. This factor, coupled with the full contribution of Distrigas sales, determined a change in natural gas sales portfolio as compared to 2008. In 2009 international sales at 63.68 bcm represented 61% of total sales (49% in 2008). Growth on European markets allowed to dampen the sharp decline in domestic gas demand and the increased competitive pressure in Italy (2009 Italian sales were down 12.83 bcm, or 24.3%) leading to total sales of 103.72 bcm in 2009 (down 0.5% from 2008). Reorganization of regulated businesses in the Italian gas sector
IIn 2009 the reorganization of gas infrastructures was finalized through the sale of Italgas SpA and Stoccaggi Gas Italia SpA (Stogit) to Snam Rete Gas. The transaction is expected to create significant synergies in the segment of regulated businesses allowing Eni to maximize the value of both gas distribution and storage activities and strengthen the financial soundness of the Group’s capital structure. Strategic partnership with Gazprom - South Stream Project
IBased on agreements between Italy and Russia of May 15, 2009, a new scope of work in the development project of the South Stream pipeline has been defined providing for an increase in the design of transport capacity from an original amount of 31 bcm/y to 63 bcm. Projects in the Hewett area
IIn order to strengthen its competitive position in the European gas market, Eni continued pre-development activities for a project to build an offshore storage facility in the Hewett area, near the Bacton terminal (North Sea basin). Eni targets to develop storage capacity in depleted gas fields in order to support the seasonal swings of gas demand in the United Kingdom. The project sanction is expected in 2010, with start-up in 2015. Financial and operating results
IIn 2009 adjusted net profit was euro 2,916 million, increasing by euro 268 million from 2008 (up 10.1%) due to the positive performance recorded by the Marketing business. An improved scenario for energy parameters, the full contribution of the acquisition of Distrigas in terms of integration synergies and improved performance, as well as the impact of the renegotiation of long-term supply contracts, were the main positive drivers of the year. These trends were partly offset by lower sales volumes and margins, mainly on the Italian market.
Regulated Businesses in Italy recorded steady results. The International transport business reported weaker results. IEni expects to achieve gas sales of approximately 118 bcm by 2013 with an average annual growth rate higher than 3.2%. IReturn on average capital employed (ROACE) on an adjusted basis was 12.3% (12.2% in 2008). ICapital expenditures totaled euro 1,686 million and mainly related to the development and upgrading of Eni’s transport and distribution networks in Italy, the upgrading of storage capacity and ongoing plans for improving power generation efficiency standards. IElectricity volumes sold were 33.96 TWh, increasing by 4.03 TWh, or 13.5%, from 2008. INatural gas volumes transported on the Italian network were 76.90 bcm, down 10.2% from 2008.

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Eni Fact BookGas & Power

Strategies

Eni boasts European leadership in the gas market leveraging on synergies from its fully integrated presence along the whole gas value chain: supply, transport, distribution, storage and marketing of natural gas and power generation and sale. Its large and diversified gas supply portfolio, market knowledge, long-term relationships with key producing countries, and integration with the Exploration & Production segment represent competitive advantages. Against the backdrop of an uncertain demand outlook over the next 2-3 years and increasingly strong competitive pressures both on European and Italian markets, Eni intends to maintain the profitability of the business targeting continuing sales growth on European markets. In Italy Eni aims at preserving profitability and market shares. Expected results will be supported by continuously improving efficiency and efficacy of operations and stable returns from regulated businesses. By 2013 Eni intends to increase worldwide gas sales by approximately 14 bcm (from 104 bcm to 118 bcm) leveraging on additional synergies expected from the integration with Distrigas and strengthening both its direct presence and strategic partnerships in selected European markets, particularly in France, Benelux and Germany. We intend to optimize our supply portfolio, including the renegotiation of long-term supply contracts, and improving operating flexibility so as to enhance the competitiveness of Eni’s offer.

The high degree of integration with the Exploration & Production division will enable the Company to achieve growth options on the gas market and monetize equity gas reserves. These actions, coupled with tight cost control will allow Eni to face an extremely challenging trading environment that is expected over the next two to three years, in particular in 2010 when the first signs of recovery in gas demand are expected to emerge. Beyond the timeline of our plan, European demand is expected to grow driven by the fundamental trends deriving from the environmental compatibility of natural gas, the depletion of European reserves and economic growth. Thanks to its integrated presence in the natural gas and power chain and contribution from regulated assets, the Gas & Power segment confirmed its ability to provide stable results and registered in 2009 pro-forma adjusted EBITDA of euro 4.4 billion, increasing from 2008 despite an unfavorable market scenario. The strategic guidelines to maintain the business profitability levels in the medium-term are: - To strengthen leadership on European natural gas markets. - To implement effective marketing initiatives. - To improve operating efficiency.

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Eni Fact BookGas & Power

SupplyIt is a free activity where prices are determined by free negotiations of demand and supply involving gas resellers and natural gas producers. Eni’s supply volumes are purchased under long-term contracts or supplied from equity production. In the case of power, supplies derive from access to negotiations on the Power Exchange (in the case of trading) and from Eni’s power generation activities. InfrastructureIn Italy the Authority for Electricity and Gas is granted regulatory powers in matters of natural gas pricing and access to infrastructures (storage, transport and regasification) and in matters of technical quality of services. SaleEni 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 yet chosen their supplier on the free market, mainly residential customers. The Italian market includes four segments of customers: large businesses, the power generation sector, wholesalers and residential customers. Large businesses and power generation utilities are directly linked to the national and the regional natural gas networks. Wholesalers mainly include local selling companies which resell natural gas to residential customers through low pressure distribution networks, and distributors of natural gas for automotive use. Residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and small businesses (also referred to as the middle market) located in large metropolitan areas and urban centers.
Overall Eni supplies approximately 2,500 clients including large businesses, power generation utilities, wholesalers and distributors of natural gas for automotive use. Residential users are 6.88 million and include households, professionals, small and medium sized enterprises, and public bodies located all over Italy.

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Eni Fact BookGas & Power

Gas market trends Overview
In 2009 European gas demand was severely impacted by the economic downturn (down 7.4% from 2008, assuming normal average temperatures). As a result of that trend, both producing activities and request for electricity reduced. The Italian market was particularly hit by the downturn as demand fell by approximately 9 bcm from 2008, down 10%, and almost 10 bcm from the pre-crisis levels seen in 2007, down 12%, assuming normal average temperatures. The situation on the Italian market was worsened also by the relevant increase in gas supply as several operators, including Eni, completed plans to upgrade gas import pipelines coupled to a lower ability to absorb gas supplies of the US market, where the effect of the recession was enlarged by an increase in domestic production from non conventional sources (in particular shale gas). The outlook for gas supply and demand both in Europe and Italy is challenging as GDP growth in the EU 27 Countries will remain weak over the next few years and gas demand is expected to recover only gradually to pre-crisis levels. In addition, ongoing patterns towards energy preservation and rising competition from renewable or alternative sources of energy will further dampen recovery perspectives of gas demand. Specifically, at the March 2007 European Council, the European Heads of Government decided to adopt a Climate Action and Renewable Energy Package. This legislation was voted by the European Parliament in December 2008. The package, also known as "ECCP 20-20-20", includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 compared to emission levels recorded in 1990 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020.
Based on current assumptions and its ongoing perception of market trends, management expects that the gas market will recover the consumption levels of 2008 by 2013. Beyond 2013, management forecasts that demand will resume growing as a consequence of the fundamental trends represented by:
- the higher environmental compatibility of natural gas as compared to other fossil fuels, which represents a basic determinant of energy choices that are currently driven by a political commitment to reducing greenhouse gas emissions and implementing environmental regulations, in particular in the European Union;
- the depletion of European reserves;
- economic and demographic growth in particular in China and India and the increase in domestic consumption in the main producing countries;
- the evolution of technologies to bring significant volumes of stranded gas to markets (LNG; Gas to liquids-GTL); - an increase in gas used for power generation, in particular with reference to the adoption of the combined cycle technology that has lower investment costs, higher efficiency and lower emissions as compared to other technologies based on the use of fossil fuels.
Eni’s long-term projections of European gas demand growth consider a compound average growth rate of 1.5%. These assumptions imply an overall consumption of approximately 600 bcm by 2020. Management also expects the Italian market to grow less than anticipated at an annual rate that will be slightly lower than 2%, implying a level of consumption amounting to 94 bcm at 2020.
1. Marketing 1.1 Natural Gas
Supply
In order to secure long-term access to gas availability, particularly in view of supplying the Italian gas market, the Company has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets (mainly Russia, Algeria and Libya). These contracts will ensure approximately 62.4 bcm of gas availability in 2010 (excluding the contribution of other subsidiaries and affiliates) with an average residual life of approximately 20 years. A further competitive advantage is represented by availability of natural gas deriving from equity production and the access to all infrastructure in the LNG chain (liquefaction, shipping and regasification) and to storage infrastructure, as well as synergies deriving from the integration with Distrigas. The acquisition of the Belgian company in fact significantly increased Eni’s portfolio of supplies with long-term supplies for about 14.7 bcm/y from the Netherlands, Norway and Qatar (all with an average residual duration of 18 years).
Eni’s gas requirements are met by natural gas from a total of 10 countries, where Eni also holds upstream activities and by access to European spot markets.
In 2009 volumes purchased under take-or-pay contracts by consolidated companies amounted to 88.65 bcm. Main gas volumes from equity production derived from: (i) Italian gas fields (6.5 bcm); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2009 these two fields supplied 2.5 bcm net to Eni; (iii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.9 bcm); and (iv) other European areas (in particular Croatia with 0.8 bcm).
Considering also the direct sales of the Exploration & Production division in Europe and in the Gulf of Mexico and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 20.1 bcm, representing 19% of total volumes available for sale.

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Eni Fact BookGas & Power

Marketing in Italy
In 2009, sales volumes in Italy (including own consumption) decreased by 12.83 bcm, down by 24.3%, to 40.04 bcm reflecting sharply lower supplies to power generation utilities (down 8.01 bcm), industrial customers (down 2.01 bcm) and wholesalers (down 1.60 bcm) dragged down by the economic downturn and rising competitive pressures. Volumes sold to the residential sector increased slightly due to effective marketing and higher weather-related sales.
In Italy against the backdrop of a weak demand outlook and increased competition, management intends to maintain the Company’s 51%¹ market share and preserve profitability by leveraging on a number of marketing initiatives designed to enhance the Company’s gas offer.
Planned actions include:
- diversifying the commercial offer in terms of combinations of pricing formulae and services designed to better suit to different customers’ needs; - increasing capillarity through wide sale-force presence.
In the segment of large customers (power generation, industries and wholesalers) Eni intends to make use of its ability in providing large volumes meeting customers’ specific needs in terms of offering and pricing and flexibility in offtaking volumes also extending to them the dual offer of gas and electricity.
In the residential segment, Eni intends to strengthen its leadership through excellent services and retaining and enlarging its portfolio of customers, in particular leveraging on the potential of its dual offer.
These actions will be supported by a continuing commitment to reducing the cost to serve, leveraging on innovation, streamlining front-end and back-end processes and achieving economies of scale and synergies, particularly those deriving from integrating marketing of both gas and electricity in the dual offer scheme.

(1) In accordance with Article 19, paragraph 4 of Legislative Decree No. 164/2000 the volumes of natural gas consumed in own operations by a company or its subsidiaries are excluded from calculation of ceilings for sales to end customers and for volumes input into the Italian network to be sold in Italy (50%). In 2009 Eni’s presence on the Italian market complied with the limits set by current laws as it was 48%.

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Eni Fact BookGas & Power

Sales and market shares on the Italian gas market (bcm) 2008 2009

	Volumes sold	Market share (%)	Volumes sold	Market share (%)	% Ch. 2009 vs 2008
Italy to third parties	47.24	55.7	34.23	43.8	(27.5	)
Wholesalers	7.52		5.92		(21.3	)
Gas release	3.28		1.30		(60.4	)
Gas Exchange and spot markets	1.89		2.37		25.4
Industries	9.59		7.58		(21.0	)
Medium-sized enterprises and services	1.05		1.08		2.9
Power generation	17.69		9.68		(45.3	)
Residential	6.22		6.30		1.3
Own consumption	5.63		5.81		3.2
TOTAL SALES IN ITALY	52.87	62.3	40.04	51.2	(24.3	)
Gas demand (a)	84.88		78.13		(8.0	)

(a) Source: Ministry of Economic Development.

Marketing in the rest of Europe
In spite of a challenging environment due to a weak demand outlook and strong competitive pressures, management intends to maintain the profitability of the gas business by strengthening its European leadership. Planned actions are targeted to expand sales volumes and revenues in the European markets where the Company’s presence is well established and market opportunities are being created. Those markets will include France, Germany, the Benelux countries and continental hubs in Northern Europe.
In 2009 sales on European markets were 44.97 bcm (47 bcm when including E&P sales), up 41.5%, mainly due to the contribution of Distrigas and increases achieved in France and in Northern Europe. Eni intends to develop its market share in Europe (including E&P sales in Europe and excluding sales in Italy and sales to importers in Italy). Management plans to achieve sales volumes in Europe of approximately 59 bcm by 2013, with an annual growth rate of 6% from 2009 when sales in European markets amounted to 47 bcm. The drivers of this growth are expected to be integration with Distrigas activities, competitive advantages ensured by gas availability under long-term supply contracts and equity gas, including benefits associated with contract re-negotiations, access to infrastructures, long-term relationships with key producing countries (mainly Russia, Algeria and Libya), market knowledge, a widespread commercial sale force and a diversified portfolio of clients.

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Eni Fact BookGas & Power

Gas sales by market (bcm) 2005 2006 2007 2008 2009

ITALY	58.08	57.09	56.13	52.87	40.04
Wholesalers	12.05	11.54	10.01	7.52	5.92
Gas release	1.95	2.00	2.37	3.28	1.30
Italian gas exchange and spot markets			1.90	1.89	2.37
Industries	13.07	13.33	11.77	9.59	7.58
Medium-sized enterprises and services	1.00	1.00	1.00	1.05	1.08
Power generation	17.60	16.67	17.21	17.69	9.68
Residential	6.87	6.42	5.79	6.22	6.30
Own consumption	5.54	6.13	6.08	5.63	5.81
INTERNATIONAL SALES	36.13	41.01	42.83	51.36	63.68
Rest of Europe	29.91	34.81	35.02	43.03	55.45
Importers in Italy	11.53	14.10	10.67	11.25	10.48
European markets	18.38	20.71	24.35	31.78	44.97
Iberian Peninsula	4.59	5.24	6.91	7.44	6.81
Germany-Austria	4.23	4.72	5.03	5.29	5.36
Belgium				4.57	14.86
Hungary	3.39	3.10	2.74	2.82	2.58
Northern Europe	2.93	2.62	3.15	3.21	4.31
Turkey	2.46	3.68	4.62	4.93	4.79
France	0.15	1.07	1.62	2.66	4.91
Other	0.63	0.28	0.28	0.86	1.35
Outside Europe	1.71	1.51	2.42	2.33	2.06
E&P in Europe and in the Gulf of Mexico	4.51	4.69	5.39	6.00	6.17
WORLDWIDE GAS SALES	94.21	98.10	98.96	104.23	103.72

Follows a description of Eni’s presence in main European markets.

Benelux
The acquisition of Distrigas completed in the first half of 2009 represents a strategic achievement for Eni. Distrigas is a key operator in Benelux, in particular in Belgium, the strategic hub of the continental European gas market thanks to its central position and high level of interconnectivity with the gas transit networks of Central and Northern Europe. The company currently operates in Belgium, Luxembourg, France, the Netherlands and Germany selling natural gas mainly to industries, wholesalers and power generation utilities. Distrigas also has diversified sources of supply, which are ensured by long-term supply contracts from the Netherlands, Norway and Qatar, spot supplies mainly made at the Zeebrugge hub on the Belgian coast, access to capacity via pipeline transport and

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Eni Fact BookGas & Power

LNG operations. It also owns an 11% interest in Interconnector UK Ltd, the company that owns the interconnection of the gas transit networks between Belgium and the UK.
In 2009 Distrigas natural gas sales in Benelux amounted to approximately 15.72 bcm.
Over the medium-term Eni plans to achieve further synergies by integrating Distrigas operations targeting both revenue opportunities and cost efficiencies by:
- optimizing the supply portfolio of long-term contracts by integrating gas flows and relevant arbitration activities;
- unitizing logistics operations so as to achieve cost efficiencies deriving from a joint use of transport capacity;
- integrating trading activities in Italy and abroad;
- pursuing gas marketing opportunities on continental spot markets (Zeehub, NBP, TTF), exploiting Distrigas consolidated presence and transport capacity;
- reallocating Eni’s sales portfolio in target countries shifting volumes to more profitable markets and segments: in particular in France the commercial strategy will target acquisition and retention of final customers focusing on the medium-large industrial segment leveraging on Distrigas consolidated presence in this segment; in Benelux the growth of Distrigas sales will focus mainly on the Netherlands (a market worth about 40 bcm);
- reducing marketing costs by integrating local commercial units in France and Germany. France
Eni sells natural gas to industrial clients, wholesalers and power generation as well as to the segments of small business and retail segments. Eni’s presence consists of direct commercial activities and the partnerships with Altergaz in which it holds a 41.62% interest and Gaz de Bordeaux SAS with a 17% interest (and a further 17% interest held by Altergaz). Altergaz supplies approximately 69,000 clients, of which 58,000 are residential customers (23,000 in 2008, of which 17,000 residentials). Eni will benefit from Altergaz’s development plans as Eni already supplies 1.3 bcm/y to its associate. Gaz de Bordeaux engages in selling natural gas in the municipality of Bordeaux. Eni plans to develop this partnership.
The integration with Distrigas generated important synergies thanks to a wide customer base and sound commercial structures mainly focused on the industrial segment.
In 2009 sales in France amounted to 4.91 bcm. Germany/Austria
Eni is present on the German natural gas market through its affiliate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 3.98 bcm in 2009 (1.99 bcm being Eni’s share) and through a direct marketing structure that in 2009 sold about 2.57 bcm in Germany and 0.8 bcm in Austria. Iberian Peninsula
Portugal Eni operates on the Portuguese market through its affiliate Galp Energia (Eni’s interest 33.34%) which sold approximately 4.34 bcm in 2009 (1.45 bcm being Eni’s share). Spain Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2009 UFG gas sales in Europe amounted to 4.68 bcm (2.34 bcm Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) regasification plants (42.5% and 18.9%, respectively). In 2009 Eni sales in Spain amounted to 5.36 bcm representing a slight decline from a year ago. Turkey
Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2009 sales amounted to 4.79 bcm, a 2.8% decline from 2008. UK/Northern Europe
Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets in the UK equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zee, TTF). Projects in the Hewett area
Eni is assessing the economic and technical aspects of a project intended to build an offshore storage facility in the Hewett area (Eni’s interest 89%) located in the Southern Gas Basin in the North Sea, near the Bacton terminal, where certain depleted fields are expected to be converted into gas storage deposits. Peak working gas is estimated at 5.6 bcm with a production of approximately 60 mmcm/d. An appraisal well is planned to be drilled shortly, whose outcome will provide further data to confirm those estimates. The storage capacity will support Eni’s production, sales and trading activities in Europe by providing the necessary flexibility to manage seasonal swings of gas demand in the United Kingdom. The activity of gas storage in the UK is de-regulated and results from this project are expected be reported within the "Marketing business".
The project sanction is expected in 2010 with start-up in 2015. 1.2 LNGEni is present in all phases of the LNG business: liquefaction, shipping, regasification and sale through operated activities or

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interests in joint-ventures and affiliates. Eni’s presence in the business is tied to the Company’s plans to develop its large gas reserve base in Africa. The LNG business has been deeply impacted by the economic downturn of 2009 and structural modifications in the US market where large availability of gas from non traditional sources promise to reduce in perspective the Country’s dependence from gas imports via LNG
Eni’s main assets in LNG are: Italy
Eni, through Snam Rete Gas, operates the regasification terminal of Panigaglia (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. Qatar
The closing of the acquisition of Distrigas allowed Eni to increase its development opportunities in the LNG business with access to new supply sources mainly from Qatar, under a 20-year long agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and the Zeebrugge LNG terminal on the Belgian coast. Egypt
Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant producing approximately 5 mmtonnes/y of LNG equal to a feedstock of 7.56 bcm/y of natural gas. In 2009, the Gas & Power segment withdrew 0.96 mmtonnes of LNG (approximately 1.4 bcm of natural gas) to be marketed in Europe. Spain
Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto regasification plant, near Valencia, with a capacity of 9.6 bcm/y. At present, Eni’s 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 regasification plant, located in Galicia, which started operations in November 2007, with a treatment capacity of approximately 4 bcm/y, 0.35 bcm/y being Eni’s capacity entitlements. USA
Cameron
In the third quarter of 2009 operations started at the Cameron regasification plant located on the banks of the Calcasieu River, approximately 15 miles south of Lake Charles in Louisiana.
In consideration of a changed demand outlook, Eni renegotiated certain terms of the contract with the US company Cameron LNG, relating to the farming out of a share of its regasification capacity. 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.
Taking into account current conditions of oversupply on the US gas market, Eni rescheduled the Brass project (West Africa) for developing gas reserves to fuel the Cameron plant. The start-up is now expected in 2015. Pascagoula
This project is part of an upstream development related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes of LNG (approximately 7.3 bcm/y) for the North American market. As part of the downstream leg of the project, Eni signed with Gulf LNG a 20-year contract to buy 5.8 bcm/y of the regasification capacity of the plant under construction near Pascagoula in Mississippi, with expected start-up by the end of 2012 in line with the start-up of the upstream project in Angola.
At the same time Eni Usa Gas Marketing Llc entered a 20-year contract for the purchase of approximately 0.9 bcm/y of regasified gas downstream the terminal owned by Angola Supply Services, a company whose partners also own Angola LNG. 1.3 Power generation
In 2009 Eni sold 33.96 TWh of electricity mainly on the Italian market. By 2013 Eni targets sales volumes of 41.66 TWh.
Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi, Ferrara and in

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the recently acquired Bolgiano plant.
In 2009, power generation was 24.09 TWh, up 0.76 TWh, or 3.3% from 2008, due mainly to higher production at the Ferrara plant (Eni’s interest 51%), in connection with the coming on line of two new 390 megawatt combined cycle units.
At December 31, 2009, installed capacity was 5.3 GW (4.9 GW in 2008).
Power availability in 2009 was supported by the growth in electricity trading activity (up 3.27 TWh from 2008, or 49.5%) as a consequence of higher volumes traded on the Italian power exchange benefiting from lower purchase prices.
By 2013 Eni intends to complete its plan for expanding its power generation capacity, targeting an installed capacity of 5.4 GW². Residual expected capital expenditure amounts to euro 0.7 billion in addition to the euro 2.4 billion already invested until 2009. Development plans are underway at Taranto (Eni 100%) and Ferrara (Eni 51%), as well as at the recently acquired Bolgiano plant (Eni 100%).
This expansion will allow Eni to consolidate its market share and its position as third power producer in Italy. At full capacity in 2013, production is expected to amount to approximately 26 TWh, corresponding to approximately 8% of power expected to be generated in Italy at that date.
When fully operational, natural gas supplied will amount to 5.3 bcm/y from Eni’s supply portfolio.

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

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2. International transport and regulated businesses in Italy OverviewEni operates a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (Russia, Algeria, the North Sea and Libya).
In Italy through Snam Rete Gas and its subsidiaries Eni operates almost all the lines which form the national transport network, gas underground storage deposits and related facilities, a re-gasification plant in Panigaglia and can count on an extended system of local distribution networks.

2.1 International TransportEni owns capacity entitlements in an extensive network of international high pressure pipelines for a total length of approximately 4,400 kilometers enabling the Company to import natural gas produced in Russia, Algeria, the North Sea and Libya to Italy.
- The TAG pipeline, 1,140-kilometer long, made up of three lines, each about 380-kilometer long, with a transport capacity of 37.4 bcm/y, and five compression stations. This pipeline transports Russian natural gas from Baumgarten, the delivery point at the border of Austria and Slovakia, to Tarvisio, point of entry in the Italian natural gas transport system. In 2009 the upgrading of this facility was finalized by completing construction of two new compression stations that increased transport capacity by 6.5 bcm/y. The whole new capacity has been entirely awarded to third parties.
- The TTPC pipeline, 740-kilometer long, made up of two lines each 370-kilometer long with a transport capacity of 33.5 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 so as to enable transportation of additional 6.5 bcm/y. The upgrade was finalized in 2008 and came fully on line in the course of 2009. The whole new capacity has been entirely awarded to third parties.
- The TMPC pipeline for the import of Algerian gas, 775-kilometer long, made up of five lines each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses underwater the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system. In 2009, the operation of the TMPC gas pipeline was fully restored. One of the five lines of the import pipeline from Algeria was damaged by an oil tanker anchor crossing the Sicily channel on December 19, 2008.
- The TENP pipeline, 1,000-kilometer long (two 500-kilometer long lines) with transport capacity of 15.5 bcm/y and four compression stations. It transports natural gas through Germany, from the German-Dutch border of Bocholtz to Wallbach at the German-Swiss border.
- The Transitgas pipeline, 290-kilometer long, with one compression station, that transports natural gas crossing Switzerland with its 165-kilometer long main line and a 70-kilometer long doubling line, from Wallbach where it joins the TENP pipeline to Passo Gries at the Italian border. It has a transit capacity of 20 bcm/y. A new 55-kilometer long line from Oltingue/Rodersdorf at the French-Swiss border to Lostorf, an interconnection point with the line coming from Wallbach, was built for the transport of Norwegian gas.
- The GreenStream pipeline that started operations in October 2004 for the import of Libyan gas produced in

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Eni operated fields at Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y and crosses underwater the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system. In 2009 the pipeline was upgraded by 3 bcm/y, which are expected to come fully on stream in 2010, bringing total capacity to 11 bcm/y. This new capacity will support Eni’s planned ramp-up of equity gas production in Libya, part of the Western Libyan Gas Project. 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. On February 4, 2010, Eni formally filed a set of structural remedies relating certain international gas pipelines with the European Commission. With prior agreement from its partners, Eni committed to dispose of its interests in the German TENP, the Swiss Transitgas and the Austrian TAG gas pipelines. The European Commission intends to submit these remedies to a market test. In case the Commission approves those remedies upon conclusion of the market test, Eni will be in the position to settle the above mentioned antitrust proceeding without imposition of any fine or other measures. In light of the strategic importance of the Austrian TAG pipeline to the supply of the Italian system, which transports gas from Russia to Italy, Eni negotiated a solution with the Commission which called for the transfer of its stake to an entity controlled by the Italian State. If they are implemented, the remedies negotiated with the Commission will not affect Eni’s contractual gas transport rights. 2.2 Regulated businesses in ItalyReorganization of the regulated business in the Italian gas sector
In June 2009 the parent company Eni SpA finalized the sale of the entire share capital of its fully-owned subsidiaries Italgas SpA and Stoccaggi Gas Italia SpA to its subsidiary Snam Rete Gas (Eni’s interest 52.54%). The transaction is expected to deliver significant synergies in the segment of regulated businesses allowing Eni to maximize the value of both gas distribution and storage activities.

Italian Transport Activity
Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport and regasification 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.

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Major pricing elements for regulated activities

	TRANSPORT	REGASIFICATION	DISTRIBUTION	STORAGE
Calculation of net invested capital recognized for regulatory purpose (RAB)	- Re-valued historical cost	- Re-valued historical cost	- Re-valued historical cost - Parametric method for centralized revenues	- Re-valued historical cost
Remuneration of net investment capital recognized for regulatory purposes (WACC pre-tax)	- 6.7%	- 7.6%	- 7.6% (distribution) - 8% (metering)	- 7.1%
INCENTIVES of new investments	- 1% for 5 years (on investments in security) - 2% for 7/10 years (on investments in capacity development) - 3% for 10/15 years (on investments in entry capacity development)	- 2% for 8 years (on upgrading existing terminals less than 30%) - 3% for 16 years (on upgrading existing terminals more than 30%)	- 2% for 8 years (on substitutions of cast-iron pipes and renewal of odorization systems)	- 4% for 8 years (on upgrading existing capacities) - 4% for 16 years (on development of new storage sites)
Efficiency factor (X FACTOR)	- 2% on operating costs - 2% on amortization and depreciation - 3.5% on commodity components	- 0.5% on operating costs	- 3.2% on distribution operating costs - 3.6% on metering operating costs	- 2% on operating costs - 1.5% on amortization and depreciation

Snam Rete Gas is the leading Italian operator in transport and dispatching of natural gas in Italy, as it manages nearly all transport infrastructures in Italy, with over 31,500 kilometers of high and medium pressure trunk-lines (approximately 94% of the whole transport system).

Transport capacity in Italy (mmcm/d) 2008-2009 Thermal year 2009-2010 Thermal year

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

Tarvisio	106.0	97.8	92.2	119.7	102.8	85.9
Mazara del Vallo	101.8	93.2	91.6	103.6	98.7	95.3
Passo Gries	64.9	60.8	93.7	64.9	59.0	90.9
Gela	30.5	30.5	100.0	33.0	32.9	99.7
Cavarzere (LNG)				26.4	21.0	79.5
Panigaglia (LNG)	13.0	11.4	87.7	13.0	7.2	55.4
Gorizia	4.8			4.8
	321.0	293.7	91.5	365.4	321.6	88.0

Eni’s network comprises:
- a national transport network extending over 8,871 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 network
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.
In 2009 the national gasline network increased by 92 kilometers with the construction of pipelines from Montalbano to Messina, Rende to Tarsia, Gagliano to Sparacollo and for upgrades of existing structures.
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, Passo Gries, 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;
- a regional transport network extending over 22,660 kilometers, made up of smaller lines 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 trunklines that are part of Eni’s 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

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Bologna). This pipeline is undergoing an upgrade with the laying of a third line with a 48-inch diameter 583-kilometer long (of these 505 are already operating). 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 104 mmcm/d;
for natural gas imported from Libya (Gela delivery point):
- a 36-inch line, 67-kilometer long linking Gela, the entry point of the GreenStream underwater pipeline, to the national network near Enna along the trunkline transporting gas coming from Algeria. Transport capacity at the Gela entry point is approximately 33 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 connect the Austrian network at Tarvisio. This facility crosses the Po Valley reaching Sergnano (near Cremona) and Minerbio. This pipeline has been upgraded by the laying of a third 264-kilometer long line with diameter from 48 to 56 inches. The pipeline transport capacity at the Tarvisio entry point amounts to approximately 120 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 (Passo Gries delivery point):
- one line, with a 48-inch diameter, 177-kilometer long extends from the Italian border at Passo Gries (Verbania), to the node of Mortara, in the Po Valley. The pipeline transport capacity at the Passo Gries entry point amounts to 65 mmcm/d;
for natural gas coming from the Panigaglia LNG terminal:
- one line, with a 30-inch diameter, 170-kilometer long links the Panigaglia terminal to the national transport network near Parma. The pipeline transport capacity at the Panigaglia entry point amounts to 13 mmcm/d;
for natural gas coming from the Rovigo Adriatic LNG terminal:
- a 36 inch 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. Eni’s system is completed by: (i) eleven compressor stations with a total power of 830 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 23 linkage and dispatching nodes and by 567 plant units including pressure reduction and regulation plants. These plants allow to regulate 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 he transport network, receiving data from approximately 3,000 plant, of which over 1,500 are remotely controlled and are located all over Italy. Distribution activityDistribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. The subsidiary Italgas (Eni’s interest 100%) and other subsidiaries operate in the distribution activity in Italy serving 1,322 municipalities through a low pressure network consisting of approximately 50,000 kilometers of pipelines supplying 5.8 million customers and distributing 7.7 bcm in 2009. Under Legislative Decree No. 164/2000 on the opening up of the natural gas market in Italy, 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. This business, therefore, presents a low risk and a steady cash generation profile. Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. According to Legislative Decree No. 164/2000, the award of the service has to take place by competitive bid from the end of a transition period no later than December 31, 2012. Future concessions will have a term no longer than twelve years. For the next four years Eni defined a capital expenditures plan of approximately euro 1 billion for the development/upgrade of its distribution networks and their technological upgrade, and the substitution of gas metering. Storage activity
Eni through Stoccaggi Gas Italia SpA, operates in natural gas storage in Italy since 2001. Gas storage is regulated by concessions and compensates the different requirements of supply and consumption; in fact, supply is basically constant over the year, while demand is characterized by high seasonality with significantly higher demand in the winter as compared to the summer.
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;

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- 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 field’s 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 2009, 8.71 bcm of gas were supplied (up 3.44 bcm from 2008) while 7.81 bcm were input to the Company’s storage deposits, an increase of 1.51 bcm compared to 2008. In 2009 storage capacity amounted to 13.9 bcm, of which 5 were destined to strategic storage. The share of storage capacity used by third parties was 70% (61% in 2008).
Through Stogit, Eni is the leading Italian operator and one of the major operators in Europe. The development of storage projects aimed at increasing capacity, represents on of the core elements for Eni’s business as it allows to increase the security of supplies and introduce greater flexibility in meeting demand in peak periods, contributing to the optimization of Eni’s gas supply portfolio.

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Supply of natural gas (bcm) 2005 2006 2007 2008 2009

Italy	10.73		10.21		8.65		8.00		6.86
Outside Italy
Russia	23.50		24.98		23.44		22.91		22.02
Algeria (including LNG)	21.03		20.42		18.41		19.22		13.82
Libya	4.61		7.70		9.24		9.87		9.14
Netherlands	8.29		10.28		7.74		9.83		11.73
Norway	5.78		5.92		5.78		6.97		12.65
United Kingdom	2.28		2.50		3.15		3.12		3.06
Hungary	3.63		3.28		2.87		2.84		0.63
Qatar (LNG)							0.71		2.91
Other supplies of natural gas	2.02		2.41		2.20		4.07		4.49
Other supplies of LNG	0.69		1.57		2.32		2.11		1.34
	71.83		79.06		75.15		81.65		81.79
Total supplies of Eni’s own companies	82.56		89.27		83.80		89.65		88.65
Offtake from (input to) storage	0.84		(3.01	)	1.49		(0.08	)	1.25
Network losses, measurement differences and other changes	(0.78	)	(0.50	)	(0.46	)	(0.25	)	(0.30	)
Available for sale by Eni’s consolidated subsidiaries	82.62		85.76		84.83		89.32		89.60
Available for sale of Eni’s affiliates	7.08		7.65		8.74		8.91		7.95
E&P volumes	4.51		4.69		5.39		6.00		6.17
Gas volumes available for sale	94.21		98.10		98.96		104.23		103.72

Gas sales by entity (bcm) 2005 2006 2007 2008 2009

Sales of consolidated companies	82.62	85.76	84.83	89.32	89.60
Italy (including own consumption)	58.01	57.07	56.08	52.82	40.04
Rest of Europe	23.44	27.93	27.86	35.61	48.65
Outside Europe	1.17	0.76	0.89	0.89	0.91
Sales of Eni’s affiliates (net to Eni)	7.08	7.65	8.74	8.91	7.95
Italy	0.07	0.02	0.05	0.05	-
Rest of Europe	6.47	6.88	7.16	7.42	6.8
Outside Europe	0.54	0.75	1.53	1.44	1.15
E&P in Europe and in the Gulf of Mexico	4.51	4.69	5.39	6.00	6.17
Worldwide gas sales	94.21	98.10	98.96	104.23	103.72

LNG sales (bcm) 2006 2007 2008 2009

G&P sales	6.4	8.0	8.4	9.8
Italy	1.5	1.2	0.3	0.1
Rest of Europe	4.4	5.6	7.0	8.9
Extra European markets	0.5	1.2	1.1	0.8
E&P sales	3.5	3.7	3.6	3.1
Liquefaction plants:
- Bontang (Indonesia)	0.9	0.7	0.7	0.8
- Point Fortin (Trinidad & Tobago)	0.4	0.6	0.5	0.5
- Bonny (Nigeria)	1.8	2.0	2.0	1.4
- Darwin (Australia)	0.4	0.4	0.4	0.4
	9.9	11.7	12.0	12.9

Electricity sales (TWh) 2005 2006 2007 2008 2009

Free market	14.76	16.22	20.73	22.89	24.74
Italian power exchange	7.74	9.67	8.66	3.82	4.70
Industrial plants	2.71	2.70	2.81	2.71	2.92
Other (a)	2.35	2.44	0.99	0.51	1.60
Electricity sales	27.56	31.03	33.19	29.93	33.96
Power generation	22.77	24.82	25.49	23.33	24.09
Trading of electricity (a)	4.79	6.21	7.70	6.60	9.87

(a) Include positive and negative unbalancings.

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EniPower power stations Installed capacity in 2009 ^(a) Full installed capacity (2013) ^(b) Effective/planned start up Fuel

Power stations	(GW)	(GW)
Brindisi	1.3	1.4	2006	gas
Ferrera Erbognone	1.0	1.0	2004	gas/syngas
Livorno	0.2	0.2	2000	gas
Mantova	0.9	0.8	2005	gas
Ravenna	1.0	1.0	2004	gas
Taranto	0.1	0.1	2014	gas
Ferrara	0.8	0.8	2008	gas
Bolgiano (c)		0.1	2012	gas
	5.3	5.4

(a)	Installed and operational generation capacity.
(b)	Capacity available after completion of dismantling of obsolete plants.
(c)	Acquired in January 2010.

Power generation 2005 2006 2007 2008 2009

Purchases
Natural gas	(mmcm)	4,384	4,775	4,860	4,530	4,790
Other fuels	(ktoe)	563	616	720	560	569
- of which steam from cracking		96	136	137	131	82
Production
Power generation	(TWh)	22.77	24.82	25.49	23.33	24.09
Steam	(ktonnes)	10,660	10,287	10,849	10,584	10,048
Installed generation capacity	(GW)	4.5	4.9	4.9	4.9	5.3

Gas volumes transported in Italy ^(a) (bcm) 2005 2006 2007 2008 2009

Eni	54.88	57.09	52.39	51.80	39.63
On behalf of third parties	30.22	30.90	30.89	33.84	37.27
	85.10	87.99	83.28	85.64	76.90

(a) Include amounts destined to domestic storage.

Regasified gas volumes (bcm) 2005 2006 2007 2008 2009

Eni	0.73	1.50	1.11	0.29	0.10
On behalf of third parties	1.76	1.63	1.27	1.23	1.22
	2.49	3.13	2.38	1.52	1.32

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	103.6	75	7
Tarvisio-Sergnano-Minerbio	3	433	42/36, 34 and 48/56	119.7	58/75	3
Passo Gries-Mortara	1/2	177	48/34	64.9	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)
TENP (Bocholtz-Wallbach)	2 lines of km 500	1,000	36/38/40	22.9	15.5	4
Transitgas (Rodersdorf-Lostorf)	3 lines of km 165, 71 and 55	291	36/48	24.9	19.9	1
TAG (Baumgarten-Tarvisio)	3 lines of km 380	1,140	36/38/40/42	45.2	37.4	5
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	33.2	33.2
GreenStream (Mellitah-Gela)	1 line of km 520	520	32	8.0	8.0	1
Blue Stream (Beregovaya-Samsun)	2 lines of km 387	774	24	16.0	16.0	1

(a)	Transport capacity refers to the capacity at the entry point connected to the import pipelines.
(b)	Include both transit capacity and volumes of natural gas destined to local markets and offtaken at various points along the pipeline.
(c)	Maximum volume of natural gas input at various entry points along the pipeline and transported to the next pipeline.

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Distribution Italy 2005 2006 2007 2008 2009

Volumes distributed	(bcm)	8.65	7.54	7.44	7.63	7.73
to Eni		8.13	6.33	5.66	6.33	6.26
to third parties		0.52	1.41	1.78	1.30	1.47
Installed network	(km)	48,146	48,724	48,746	49,410	49,973
Active meters	(contracts)	5,838,085	5,550,700	5,598,677	5,676,105	5,770,672
Municipalities served	(units)	1,282	1,315	1,318	1,320	1,322

Storage 2005 2006 2007 2008 2009

Total storage capacity:	(bcm)	12.6	13.5	13.6	13.7	13.9
- of which strategic storage		5.1	5.1	5.1	5.1	5.0
- of which available storage		7.5	8.4	8.5	8.6	8.9
Available capacity:	(%)
- share utilized by Eni		44	54	44	39	30
- share utilized by third parties		56	46	56	61	70
Total offtake from (input to) storage	(bcm)	18.27	16.40	9.27	11.57	16.52
- input to storage		8.55	9.91	4.00	6.30	7.81
- offtake from storage		9.72	6.49	5.27	5.27	8.71
Total customers	(No.)	35	38	44	48	56

Capital expenditures (euro million) 2005 2006 2007 2008 2009

Italy	1,099	1,054	1,219	1,750	1,564
Outside Italy	86	160	292	308	122
	1,185	1,214	1,511	2,058	1,686
Market	279	292	238	198	175
Market	40	63	63	91	102
Italy	2		13	16	12
Outside Italy	38	63	50	75	90
Power generation	239	229	175	107	73
Regulated businesses in Italy	858	825	1,031	1,627	1,479
Transport	643	627	691	1,130	919
Distribution	182	158	195	233	278
Storage	33	40	145	264	282
International transport	48	97	242	233	32
	1,185	1,214	1,511	2,058	1,686

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Key performance indicators 2005 2006 2007 2008 2009

Net sales from operations (a) (b)	(euro million)	33,696	38,176	36,349	45,017		31,769
Operating profit		1,852	324	686	(988	)	(102	)
Adjusted operating profit		1,210	794	292	580		(357	)
Adjusted net profit		943	631	294	521		(197	)
Capital expenditures		656	645	979	965		635
Adjusted capital employed, net at year end		5,326	5,766	7,149	8,260		7,560
Adjusted ROACE	(%)	18.1	10.7	4.6	6.5		(2.6	)
Refinery throughputs on own account	(mmtonnes)	38.79	38.04	37.15	35.84		34.55
Refinery conversion index	(%)	56	57	56	58		60
Balanced capacity of refineries	(kbbl/d)	701	711	748	737		747
Retail sales in Europe (c)	(mmtonnes)	12.42	12.48	12.65	12.03		12.02
Agip branded service stations in Europe at period end (c)	(units)	6,282	6,294	6,440	5,956		5,986
Average throughput per service stations in Europe	(kliters)	2,479	2,470	2,486	2,502		2,477
Employees at year end	(units)	8,894	9,437	9,428	8,327		8,166

(a)	From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programmes be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results have been restated accordingly.
(b)	Before elimination of intragroup sales.
(c)	2005-2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

2009 Highlights

Portfolio developmentIOn January 21, 2010 Eni signed an agreement for the acquisition of downstream activities in Austria, including a retail network of 135 service stations, wholesale activities (with 36 additional Esso branded retail service stations) as well as commercial assets in the aviation business and related logistic and storage activities. The finalization of the transaction is subject to the approval of the relevant antitrust authorities. Re-branding of downstream oil activitiesIThe upgrading process of Eni’s retail network of service stations continued aimed at improving service and quality standards. In 2010 the re-branding to the "eni" brand of all downstream activities was launched. Financial and operating resultsIIn 2009 the Refining & Marketing division reported an adjusted net loss of euro 197 million (down euro 718 million, reversing a prior year profit of euro 521 million) mainly driven by a lower operating performance, reflecting lower refining

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margins as a result of an unfavorable trading scenario, as well as decreased earnings reported by equity-accounted subsidiaries. IReturn on average capital employed on an adjusted basis was a negative 2.6% declining from 2008 (6.5%). ICapital expenditures totaled euro 635 million and related mainly to projects designed to improve the conversion rate and flexibility of refineries, logistic assets, the upgrade of the refined product retail network in Italy and in the rest of Europe. IIn the medium-term, management plans to recover profitability by improving the refining system and reinforcing Eni’s leadership in the Italian retail market and increasing market shares in core European countries.

Strategies

Eni’s Refining & Marketing segment engages in refining of crude oil and marketing of refined products primarily in Italy and in Central-Eastern Europe. Eni is leader in the retail marketing of refined products in Italy with a market share of 31.5 as of the end of 2009. The Company’s operations are fully integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations. Integration with upstream activities, technological know-how in refining, a well known brand, the quality of products and services provided to a wide and loyal customer base, represent further competitive advantages on which Eni can leverage to better face an extremely challenging scenario. To cope with this challenging outlook, management plans to: - Keep tight control on capital expenditures, particularly in refining through strong financial discipline in selecting capital projects.

- Strongly focus on cost reductions and energy efficiency improvements. - Improve profitability of marketing activities by increasing the quality and range of its retail offer. As a result of all these actions, management believes that the Refining & Marketing segment will be cash flow positive in 2012. In the medium-term capital expenditure is projected at euro 2.7 billion, confirming the same level of the previous four-year plan. However, the share of expenditures dedicated to marketing is planned to increase from 25% to 40% as the Company intends to upgrade its network in Italy and selected European markets, also finalizing the process of restyling and re-branding to the "eni" brand all its service stations. Management plans to upgrade the Company best refineries by investing euro 1.6 billion to increase plant conversion and flexibility as well as to comply with all applicable HSE regulations.

Market trends RefiningIn 2009 the trading environment was particularly unfavorable. Refining margins plunged to historical lows due to a rapid recovery in oil prices which the Company was unable to transfer on to final prices of refined products due to weak European and US demand, high worldwide and regional inventory levels and excess refining capacity. In addition, profitability of complex throughputs was severely impacted by the compression of light-heavy crude differentials (from 5.1 $/bbl to 1.9 $/bbl in 2008 and 2009, respectively) due to the reduced availability of heavy crude oil in the Mediterranean area. Another negative factor was the exceptional decline of gasoil prices, whose spread over raw materials fell significantly. Management believes that those trends are likely to persist for the next two to three years as demand for refined products will continue being affected by:
- increasing demand for high energy efficient engines and use of bio-fuels based on the more and more widespread attention to environmental issues;
- increasing refining capacity particularly in Middle and Far East;
- lower propensity of the US market to import gasoline.
On the plus side, the eventual margin level will be influenced by the pace of the global economic recovery

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and the extent of refinery rationalization in the face of weak margins.
To cope with this challenging outlook, management confirms a strategy aimed at improving the competitive positioning of refining operations through selected capital expenditure focused on its best positioned assets including monetization of know-how and key proprietary technologies (EST).
To cope with an expected challenging scenario, efficiency improvement actions for an estimated total of euro 100 million in the next four years will mostly concern control of labor costs and of consumption in refining processes. MarketingIn fuel retail marketing in Europe, Eni expects the sluggish dynamics of demand to persist along with increased competition especially in premium products and non oil services.
In this context Eni intends to achieve constant improvement of service quality, a diversification of its commercial offer, widening its client base with innovative promotional campaigns and client retention actions, as well as recovery of operating efficiency.
Activities
1. RefiningEni’s refining system has total refinery capacity (balanced with conversion capacity) of approximately 37.3 mmtonnes (equal to 747 kbbl/d) and a conversion index of 59.8%.
In 2009 refinery throughputs on own account in Italy and outside Italy were 34.55 mmtonnes.
In the next four years, Eni plans to selectively upgrade its refining system by increasing complexity and flexibility at its best refineries. Middle distillate yields are expected to come in at 43% from 41% in 2009 (approximately double of gasoline yields) as the new hydro-cracking units recently started-up in Sannazzaro, Taranto and Bayernoil are planned to improve yields.
Additionally, management plans to build a new conversion unit at the Sannazzaro refinery which will be based on the EST proprietary technology for converting the heavy barrel by almost zeroing residue. The start-up of this unit is scheduled in 2012.
Higher conversion capacity is expected to enable the Company to extract value from equity crude as well as capture opportunities of monetizing heavy crudes and non conventional resources. Equity crude volumes processed are also expected to increase from 19.0% to 19.6% in 2013. Management also targets flexibility enhancement at the Company refineries whereby the Company intends to achieve a 15 percentage point increase in the share of spot crude supplies to processes. Logistics and process optimization will help in selecting the most profitable slate to satisfy market needs also in light of expected development in European regulations on environmental performance of fuels.
The actions described will allow Eni to:
- increase internally tracked PUI (Process Utilization Index) by 10 percentage points from the current 77% to 87% by 2013;
- reduce direct consumption and optimize the quality of fuels used in refineries, while respecting all the limits imposed by regulations and authorizations obtained;
- reduce and optimize indirect consumption in particular of refining utilities;
- identify innovative energy saving actions as compared to traditional ones.

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nItaly Eni’s refining system in Italy is composed of five wholly owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to end markets and the integration with Eni’s other activities. Sannazzaro: with balanced refining capacity of 180 kbbl/d and a conversion index of 61.2%, it is one of the most efficient refineries in Europe. Located in the Po Valley, it supplies mainly markets in North-Western Italy and Switzerland. The high degree of flexibility of this refinery allows it to process a wide range of 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 mild hydrocracker (HDCK) middle distillate conversion units one of them came on stream in 2009 and a visbreaking thermal conversion unit, with a gasification facility using the heavy residue from visbreaking (tar) to produce syngas to feed the nearby EniPower power plant at Ferrera Erbognone. In 2009 Eni completed the upgrading of the refinery capacity and flexibility increased by a new HDCK with 28 kbbl/d capacity that came on stream in June 2009. In addition Eni plans to develop a conversion plant employing the Eni Slurry Technology with a 23 kbbl/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled in 2012. Taranto: with balanced refining capacity of 110 kbbl/d and a conversion index of 64.8%, this refinery can process a wide range of crude and other feedstock. It mainly produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2009 a total of 1.5 mmtonnes of this oil were processed). The new hydrocracking unit with a capacity of 17 kbbl/d is expected to start production in 2010. Eni’s plan to upgrade the conversion capacity of this refinery will enable to extract value from fuel oil and other semifinished products currently exported. Gela: with a balanced refining capacity of 100 kbbl/d and a conversion index of 142.4%, this refinery located on the Southern coast of Sicily is highly integrated with upstream operations as it processes heavy crude produced from nearby Eni fields offshore and onshore Sicily. In addition, it

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is integrated downstream as it supplies large volumes of petrochemical feedstock to Eni’s in site petrochemical plants. The refinery mostly manufactures fuels for automotive use and petrochemical feedstock. Its high conversion level is ensured by an FCC unit with go-finer for the upgrading of feedstocks and two coking plants for the vacuum conversion of heavy residues. The power plant of this refinery also contains modern residue and exhaust fume treatment plants which allow full compliance with the tightest environmental standards. An upgrade of the Gela refinery is underway by means of the: (i) construction of a new steam reformer by 2012; (ii) upgrade of its power plant and revamping of its boilers, aimed at increasing profitability by exploiting the synergies deriving from the integration of refining and power generation; (iii) introduction of a new tank for the segregation of extra-heavy crude and start of a new sulphur recovery plant both by 2012. Livorno: with a balanced refining capacity of 84 kbbl/d and a conversion index of 11.4%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its pipeline links with the local harbor and with the Florence storage sites by means of two pipelines and optimizes intake, handling and distribution of products. Venice: with a balanced refining capacity of 80 kbbl/d and a conversion index of 20.2%, 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. nOutside Italy In Germany Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that includes the Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 60 kbbl/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. In 2008 the restructuring of the Bayernoil complex was completed and a new hydrocraking unit come on stream in 2009 determining an increase of middle distillate yields and a corresponding reduction of the production of gasoline giving more profitability to the activities conducted there.
Eni holds a 32.4% stake in Ceska Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to about 53kbbl/d.
In addition, with its 33.34% interest in Galp, with the Portuguese group Amorim Eni jointly controls two refineries in Portugal: a small one in Porto specialized in the manufacture of lubricant bases and a larger and more complex one in Sines integrated with petrochemicals. 2. Logistics
Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 21 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude.
Eni’s logistic model is organized on a hub structure including five main areas. These hubs monitor and centralize the handling of products 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 costs, and increasing efficiency. Eni operates in the transport of oil and refined products: (i) on land through a pipeline network of leased and owned pipelines extending over 3,019 kilometers (of which 1,447 kilometers in operation are owned by Eni); and (ii) by sea through spot and long-term lease contracts of tanker ships. Secondary distribution to retail and wholesale markets is effected through third parties who also own their

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means of transportation, in some instances with minority participation of Eni. 3. Marketing nRetail Italy In Italy Eni is leader in retail marketing of refined products with a 31.5% market share. At year end 2009 Eni’s distribution network included 4,474 service stations. Retail fuel sales amounted to approximately 11 billion liters (9.03 million tonnes) with average throughput of 2.48 million liters.
In marketing operations, Eni plans to strengthen its competitive positioning in Italy and targets to expand its share in the domestic retail market for fuels to 34% by 2013.
Planned actions focus in particular on:
- re-branding to the "eni" brand and upgrading and restyling its service stations;
- strengthening customers’ loyalty through the launch of new fidelity programs, improving quality and range of service offer and premium fuels;
- implementing innovative non oil formats.
Planned actions are also designed to attain European standards in terms of both quality of offered services and environmental regulation compliance. A strong focus will be devoted to pursue high levels of operating efficiency.
In the next four years Eni expects to achieve volumes of approximately 12.2 billion liters sold (approximately 11.4 billion liters in 2009) with a retail network composed of 4,451 service stations, of which 75% owned. Premium fuelsEni plans to continue innovating in the field of fuels, leveraging on the know-how gained by producing and marketing its "Blu" line (BluSuper and BluDieselTech), high performance and low environmental impact fuels.
In 2009, sales of premium fuels increased from 2008 despite the fact that in a period of economic recession fuel prices averaged high levels. Sales of BluDieselTech amounted approximately to 600 ktonnes (720 mmliters), increasing by 17 ktonnes from 2008 and represented 10.5% of gasoil sales on Eni’s retail network. At December 31, 2009, service stations marketing BluDiesel totaled 4,104 units (4,095 at 2008 year end) covering approximately 92% of Eni’s network.
Retail sales of BluSuper amounted to 82 ktonnes (110 mmliters), barely unchanged from 2008, and covered 2.7% of gasoline sales on Eni’s retail network. At December 31, 2009, service stations marketing BluSuper totaled 2,679 units (2,631 at December 31, 2008), covering approximately 60% of Eni’s network.
Promotional actions
Iperself
In 2009, Eni continued successfully its "Iperself" promotional campaign, which provides a discount to customers purchasing fuel in self service stations during closing hours. Supported by other marketing activities, this initiative allowed to achieve higher sales and a higher market share in retail marketing even in an environment characterized by declining domestic consumption. You&Agip
"You&Agip", the promotional campaign launched in March 2007 and lasting 3 years finished in 2009.
This three-year long initiative offered prizes to customers in proportion to purchases of fuels and convenience items at service stations stores as well as at the outlets of certain partners to the program. As of December 31, 2009, the number of customers that actively used the card in the year amounted to approximately 5.4 million. The average number of cards active each month was over 3.1 million. Volumes of fuel marketed under this initiative represented over 45% of total volumes marketed on Eni’s service stations joining the program, and 44% of overall volumes marketed on Eni’s network.
In February 2010 Eni launched the new promotional campaign "you&eni" lasting 3 years until January 31, 2013, designed to boost customer loyalty to the unique "eni" brand for all the Company’s downstream activities.
As a support and complement of its promotional strategy, Eni intends to launch specific short-term promotional initiatives (traffic builder promotion) aimed at attracting new clients and retaining them by enrolling them in longer term loyalty programs leveraging also on co-marketing initiatives in cooperation with commercial partners. 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

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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). In 2009 volumes bought with this card in Agip service stations represented approximately 16.6% of total sales in Italy and 11.4% in Europe. Non oil
Eni continued the development of its non oil retail activities aimed at promoting the development of its network in line with European standards, such as the diffusion of high-tech car care systems and services dedicated to customers. In 2009 Eni tested the results of the opening of three convenience stores jointly with GS, a new and innovative format in Italy but well established in Europe. Eni’s retail network includes about 1,050 fast food and high quality commercial outlets both on ordinary and motorway service stations with a wide range of brands such as Pans & Co, McDonald’s. Eni also boasts the largest automated car-wash network in Italy, with approximately 800 high quality and fast service facilities.
With the aim of developing and upgrading its non oil activities Eni continued opening new outlets and converting existing ones to more effective formats with the addition of 51 new outlets reaching a total of 511 units.
In 2009 sales of non oil products and services amounted to euro 58.6 million (euro 54 million in 2008); operating profit represented approximately 71% of sales (65% in 2008).
In the next four years Eni confirms its development and upgrading strategy for non oil activity by opening new units and converting existing ones to more visible formats targeting over 1,100 bars, shops, convenience stores and washing areas, reaching a coverage of its owned service stations of nearly 68% by 2013 (about 62% at year end 2009). nRest of Europe In 2009 retail sales of refined products marketed in the rest of Europe (2.99 mmtonnes) were down approximately 230 ktonnes from 2008, or 7.1%, mainly in Germany and Eastern Europe due to a decrease in fuel demand.
At December 31, 2009, Eni’s retail network in the rest of Europe consisted of 1,512 units, a decrease of 35 units from December 31, 2008 (1,547 service stations). The network evolution was as follows: (i) 32 low throughput service stations were closed; (ii) negative balance of acquisitions/releases of lease concessions (32 units) with negative changes in Germany and positive changes in Hungary; (iii) purchased 21 service station, in particular in Romania; (iv) opened 8 new outlets. Average throughput (2,461 kliters) decreased by 116 kliters from 2008.
The key markets of Eni’s presence are: Austria with a 7.3% market share, Hungary with 11.6%, Czech Republic with 11.3%, Slovakia with 9.2%, Switzerland with 6.4% and Germany with a 3.4% on a national base. Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets in particular in Central Eastern Europe, based on the competitive advantage provided by synergies in supply, logistics and brand awareness.
Non oil activities in the rest of Europe are carried out under the CiaoAgip^® brand name in 1,152 service stations, of these 398 are in Germany and 159 in France with a 76% coverage of the network and a virtually complete coverage of owned stations. 4. Wholesale businesses Fuels
Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and heating purposes, agricultural vehicles and 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 standards, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transport. 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 2009, sales volumes on wholesale markets in Italy (9.56

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mmtonnes) were down 1.59 mmtonnes from 2008, or 14.3%, reflecting mainly a decrease in demand for jet fuel, the bunkering market and fuel oil for power generation, as well as in gasoil sales due to lower industrial consumption reflecting the economic downturn. Sales on wholesale markets in the rest of Europe (3.66 mmtonnes) decreased by approximately 280 ktonnes, or 7.1% (excluding the impact of asset divestments in the Iberian Peninsula), mainly in Germany, in the Czech Republic and Switzerland due to declining consumption in particular of gasoil for heating.
Eni also markets jet fuel directly at 46 airports, of which 27 in Italy. In 2009, these sales amounted to 1.8 mmtonnes (of which 1.4 mmtonnes in Italy).
Eni is active also in the international market of bunkering, marketing marine fuel mainly in 40 ports, of which 23 are in Italy. In 2009 marine fuel sales were 2.1 mmtonnes (2.0 mmtonnes in Italy). Other sales were 18.60 mmtonnes down 1.17 mmtonnes or 5.9% due mainly to a decline in volumes sold to traders and oil companies and lower activities in the cargo market due to lower throughputs.
Supplies of feedstock to the petrochemical industry (1.33 mmtonnes) declined by approximately 370 ktonnes due to declining demand. LPGIn Italy Eni is leader in LPG production, marketing and sale with 575 ktonnes sold for heating and automotive use (retail and wholesale) equal to an 18% market share. Additional 227 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. In order to expand its presence on the marketplace, in the medium-term Eni plans to increase the number of service stations providing dispensers for LPG for automotive use, targeting an increase market share to 26% by 2013. LubricantsEni operates 7 (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).
In Italy Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Eni’s refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero.
In 2009, retail and wholesale sales in Italy amounted to 93 ktonnes with a 23.3% market share. Eni also sold approximately 4 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 102 ktonnes, of these about 70% were registered in Europe (mainly Spain, Germany, and France). OxygenatesEni, through its subsidiary Ecofuel (Eni’s interest 100%), sells approximately 2 mmtonnes/y of oxygenates mainly ethers (approximately 7% of world demand) and methanol (approximately 1.5% of world demand). About 77% of products are manufactured in Italy in Eni’s plants in Ravenna, in Venezuela (in joint-venture with Pequiven) and Saudi Arabia (in joint-venture with Sabic), the remaining 23% 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.

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Refining system in 2009

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

Wholly owned refineries		685	685	554	60.3	69	33	37	29	89	46	82	94
Italy
Sannazzaro	100	223	223	180	50.9	34	11		29	29		73	99
Gela	100	129	129	100	144.8	35		37			46	82	101
Taranto	100	120	120	110	64.6		22			38		97	79
Livorno	100	106	106	84	11.4							88	102
Porto Marghera	100	107	107	80	20.2					22		79	86
Partially owned refineries (a)		874	245	193	49.7	163	25		99	27		77	98
Italy
Milazzo	50	248	124	80	73	41	25		32			68	99
Germany
Vohburg/Neustadt      (Bayernoil)	20	215	43	41	34	49			43			93	95
Schwedt	8.33	231	19	19	41.8	49				27		98	102
Czech Republic
Kralupy and Litvinov      (Ceska Rafinerska)	32.4	180	59	53	29.6	24			24			86	80
Total		1,559	930	747	57.6	232	58	37	128	116	46	81	95

(a) Capacity of conversion plant is 100%.

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Eni Fact BookRefining & Marketing

Supply of oil (mmtonnes) 2005 2006 2007 2008 2009

Equity crude oil
Production outside Italy	32.86		32.76		27.47		26.14		29.84
Production in Italy	4.44		4.05		4.10		3.57		2.91
Other crude oils
Purchases on spot markets	14.33		10.73		11.34		12.09		14.94
Purchases under long-term contracts	14.85		18.16		16.65		16.11		19.71
	29.18		28.89		27.99		28.20		34.65
Total crude oil purchases	66.48		65.70		59.56		57.91		67.40
Purchases of intermediate products	3.58		3.18		3.59		3.39		2.92
Purchase of products	16.21		16.00		16.14		17.42		13.98
Consumption for power generation	(1.09	)	(1.10	)	(1.13	)	(1.00	)	(0.96	)
Other changes (a)	(2.49	)	(1.99	)	(2.19	)	(1.04	)	(1.64	)
TOTAL PURCHASES	82.69		81.79		75.97		76.68		81.70

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

Refinery capacity 2005 2006 2007 2008 2009

Primary distillation capacity (a)	(kbbl/d)	886	886	910	930	930
Balanced capacity (a)		701	711	748	737	747
Refinery throughputs on own account		776	761	743	717	480
Distillation capacity utilization rate	(%)	82	82	81	81	73

(a) Eni’s share.

Availability of refined products (mmtonnes) 2005 2006 2007 2008 2009

ITALY
At wholly-owned refineries	27.34		27.17		27.79		25.59		24.02
Less input on account of third parties	(1.70	)	(1.53	)	(1.76	)	(1.37	)	(0.49	)
At affiliate refineries	8.58		7.71		6.42		6.17		5.87
Refinery throughputs on own account	34.22		33.35		32.45		30.39		29.40
Consumption and losses	(1.87	)	(1.45	)	(1.63	)	(1.61	)	(1.60	)
Products available for sale	32.35		31.90		30.82		28.78		27.80
Purchases of refined products and change in inventories	4.85		4.45		2.16		2.56		3.73
Products transferred to operations outside Italy	(5.41	)	(4.82	)	(3.80	)	(1.42	)	(3.89	)
Consumption for power generation	(1.09	)	(1.10	)	(1.13	)	(1.00	)	(0.96	)
Sales of products	30.70		30.43		28.05		28.92		26.68
OUTSIDE ITALY
Refinery throughputs on own account	4.57		4.69		4.70		5.45		5.15
Consumption and losses	(0.24	)	(0.32	)	(0.31	)	(0.25	)	(0.25	)
Products available for sale	4.33		4.37		4.39		5.20		4.90
Purchases of finished products and change in inventories	11.19		11.51		13.91		15.14		10.12
Products transferred from Italian operations	5.41		4.82		3.80		1.42		3.89
Sales of products	20.93		20.70		22.10		21.76		18.91
Refinery throughputs on own account	38.79		38.04		37.15		35.84		34.55
Total equity crude input	12.53		12.50		9.29		6.98		5.11
Total sales of refined products	51.63		51.13		50.15		50.68		45.59
Crude oil sales	31.06		30.66		25.82		26.00		36.11
TOTAL SALES	82.69		81.79		75.97		76.68		81.70

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Eni Fact BookRefining & Marketing

Production and sales (mmtonnes) 2005 2006 2007 2008 2009

Products
Gasoline	9.30	9.02	8.85	8.32	8.43
Gasoil	14.72	14.37	13.91	13.44	13.33
Jet fuel/kerosene	1.46	1.57	1.38	1.54	1.42
Fuel oil	5.08	4.85	4.89	4.34	4.01
LPG	0.65	0.72	0.69	0.71	0.66
Lubricants	0.65	0.55	0.64	0.60	0.49
Petrochemical feedstocks	1.35	1.65	1.89	2.16	2.08
Other	3.47	3.54	2.96	2.86	2.28
Total products	36.68	36.27	35.21	33.97	32.70
Sales
Italy	30.70	30.43	28.05	28.92	26.68
Gasoline	4.40	3.53	3.34	3.26	3.17
Gasoil	10.35	9.69	9.67	10.03	10.04
Jet fuel/kerosene	1.65	1.84	1.97	1.94	1.42
Fuel oil	1.49	1.26	0.95	0.85	0.72
LPG	0.66	0.59	0.54	0.57	0.57
Lubricants	0.10	0.14	0.13	0.13	0.09
Petrochemical feedstocks	3.07	2.61	1.93	1.70	1.33
Other	8.98	10.77	9.52	10.44	9.34
Rest of Europe	18.62	17.02	20.08	19.63	16.02
Gasoline	2.14	2.06	2.14	2.21	1.89
Gasoil	4.71	4.89	5.16	5.11	3.55
Jet fuel/kerosene	0.34	0.34	0.38	0.47	0.35
Fuel oil	0.12	0.23	0.25	0.23	0.29
LPG	0.11	0.12	0.13	0.16	0.14
Lubricants	0.07	0.10	0.10	0.11	0.08
Other	11.13	9.28	11.92	11.34	9.72
Extra Europe	2.31	3.68	2.02	2.13	2.89
Gasoline	1.59	1.94	1.52	1.63	2.51
LPG	0.34	0.34	0.36	0.37	0.36
Lubricants	0.04	0.02	0.02	0.03	0.02
Other	0.34	1.38	0.12	0.10
Worldwide
Gasoline	8.13	7.53	7.00	7.10	7.57
Gasoil	15.06	14.58	14.83	15.14	13.59
Jet fuel/kerosene	1.99	2.18	2.35	2.41	1.77
Fuel oil	1.61	1.49	1.20	1.08	1.01
LPG	1.11	1.05	1.03	1.10	1.07
Lubricants	0.21	0.26	0.25	0.27	0.19
Petrochemical feedstocks	3.07	2.61	1.93	1.70	1.33
Other	20.45	21.43	21.56	21.88	19.06
Total sales	51.63	51.13	50.15	50.68	45.59

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Eni Fact BookRefining & Marketing

Sales in Italy and outside Italy by market (mmtonnes) 2005 2006 2007 2008 2009

Retail	10.05	8.66	8.62	8.81	9.03
Wholesale	12.11	11.74	11.09	11.15	9.56
	22.16	20.40	19.71	19.96	18.59
Petrochemicals	3.07	2.61	1.93	1.70	1.33
Other markets	5.47	7.42	6.41	7.26	6.76
Sales in Italy	30.70	30.43	28.05	28.92	26.68
Retail rest of Europe	3.67	3.82	4.03	3.22	2.99
Wholesale rest of Europe	4.10	4.19	4.39	3.94	3.66
Wholesale outside Europe	0.40	0.41	0.57	0.56	0.41
	8.17	8.42	8.99	7.72	7.06
Other markets	12.76	12.28	13.11	12.52	11.85
Sales outside Italy	20.93	20.70	22.10	20.24	18.91
Total sales (a)	51.63	51.13	50.15	49.16	45.59

(a) 2005-2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Sales by product/market (mmtonnes) 2005 2006 2007 2008 2009

Italy	22.16	20.40	19.71	19.96	18.59
Retail sales	10.05	8.66	8.62	8.81	9.03
Gasoline	4.35	3.38	3.19	3.11	3.05
Gasoil	5.49	5.09	5.25	5.50	5.74
LPG	0.20	0.18	0.17	0.19	0.22
Lubricants	0.01	0.01	0.01	0.01	0.02
Wholesale sales	12.11	11.74	11.09	11.15	9.56
Gasoline	0.16	0.15	0.15	0.15	0.12
Gasoil	4.86	4.60	4.42	4.52	4.30
LPG	0.46	0.41	0.37	0.38	0.35
Lubricants	0.13	0.13	0.13	0.12	0.09
Fuel oil	1.50	1.27	0.95	0.85	0.72
Bunker	1.63	1.68	1.58	1.70	1.38
Other	3.37	3.50	3.49	3.43	2.60
Outside Italy (retail + wholesale)	8.17	8.42	8.99	7.72	7.06
Gasoline	2.14	2.06	2.29	2.12	1.89
Gasoil	4.71	4.90	5.16	3.80	3.54
LPG	0.44	0.46	0.49	0.52	0.50
Lubricants	0.10	0.10	0.09	0.11	0.10
Fuel oil	0.12	0.23	0.25	0.23	0.28
Jet fuel	0.34	0.34	0.38	0.47	0.35
Other	0.32	0.33	0.33	0.47	0.40
Total (a)	30.33	28.82	28.70	27.68	25.65

(a) 2005-2007 data include downstream activities in the Iberian Peninsula divested to Galp in October 2008.

Number of service stations (units) 2005 2006 2007 2008 2009

Italy		4,349	4,356	4,390	4,409	4,474
Ordinary stations		4,204	4,214	4,253	4,273	4,344
Highway stations		145	142	137	136	130
Outside Italy		1,933	1,938	2,050	1,547	1,512
Germany		689	681	672	521	478
France		197	204	202	199	196
Iberian Peninsula (a)		373	358	371	-	-
Austria/Switzerland		432	444	443	458	446
Eastern Europe		242	251	362	369	392
Service stations selling Blu products		4,042	4,242	4,357	4,445	4,822
"Multi-Energy" service stations		1	3	4	4	4
Service stations selling LPG and natural gas		476	490	538	537	690
Non-oil sales	(euro million)	135	137	144	153	147

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

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Eni Fact BookRefining & Marketing

Average throughput (kliters/No. of service stations) 2005 2006 2007 2008 2009

Italy	2,509	2,463	2,444	2,470	2,482
Germany	2,875	2,978	2,968	2,868	3,167
France	2,478	2,388	2,365	2,152	2,193
Iberian Peninsula (a)	2,633	2,707	2,910	2,519	-
Austria/Switzerland	1,697	1,743	1,767	1,763	1,691
Eastern Europe	2,124	2,212	2,348	2,832	2,642
Average throughput	2,479	2,470	2,486	2,502	2,477

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

Market shares in Italy (%) 2005 2006 2007 2008 2009

Retail	29.7	29.3	29.2	30.6	31.5
Gasoline	27.5	27.2	27.3	28.5	29.0
Gasoil	32.3	31.6	31.2	32.7	33.8
LPG (automotive)	17.9	18.1	18.2	19.1	20.2
Lubricants	23.2	24.4	24.3	23.7	21.5
Wholesale	28.0	26.9	29.0	30.4	27.5
Gasoil	32.8	31.2	31.3	31.8	32.0
Fuel oil	17.9	15.2	16.2	16.3	17.2
Bunker	46.5	46.6	44.0	44.6	40.1
Lubricants	23.2	24.0	24.3	25.0	23.3
Domestic market share	29.0	28.2	29.5	31.0	29.3

Retail market shares outside Italy (%) 2005 2006 2007 2008 2009

Central Europe
Austria	7.4	7.2	7.8	7.0	7.3
Switzerland	5.7	5.8	5.9	6.4	6.4
Germany	4.1	4.4	4.2	3.8	3.4
France	1.1	1.2	1.1	1.1	1.1
Eastern Europe
Hungary	6.0	6.3	7.9	11.6	11.6
Czech Republic	5.5	5.9	7.7	11.4	11.3
Slovakia				10.2	9.2
Slovenia	1.3	1.7	2.0	2.1	2.4
Iberian Peninsula (a)
Spain	3.1	3.2	3.3	3.4	-
Portugal	0.9	0.7	1.0	0.9	-

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

Capital expenditures (euro million) 2005 2006 2007 2008 2009

Italy	585	547	873	850	581
Outside Italy	71	98	106	115	54
	656	645	979	965	635
Refining, supply and logistics	349	376	675	630	436
Italy	349	376	675	630	436
Marketing	225	223	282	298	172
Italy	154	125	176	183	118
Outside Italy	71	98	106	115	54
Other	82	46	22	37	27
	656	645	979	965	635

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Eni Fact BookEngineering & Construcion

Key performance indicators ^(a) 2005 2006 2007 2008 2009

Net sales from operations (a)	(euro million)	5,733	6,979	8,678	9,176	��	9,664
Operating profit		307	505	837	1,045		881
Adjusted operating profit		314	508	840	1,041		1,120
Adjusted net profit		328	400	658	784		892
Capital expenditures		349	591	1,410	2,027		1,630
Adjusted ROACE	(%)	12.0	12.8	17.1	16.8		15.4
Orders acquired:	(euro million)	8,395	11,172	11,845	13,860		9,917
- Offshore construction		3,096	3,681	3,496	4,381		5,089
- Onshore construction		4,720	4,923	6,070	7,522		3,665
- Offshore Drilling		367	2,230	1,644	760		585
- Onshore Drilling		212	338	635	1,197		578
Order backlog:		10,122	13,191	15,390	19,105		18,730
- Offshore construction		3,721	4,283	4,215	4,682		5,430
- Onshore construction		5,721	6,285	7,003	9,201		8,035
- Offshore Drilling		382	2,247	3,471	3,759		3,778
- Onshore Drilling		298	376	701	1,463		1,487
Employees at year end	(units)	28,684	30,902	33,111	35,629		35,969

(a) Before elimination of intragroup sales.

2009 Highlights IAdjusted net profit was euro 892 million, up euro 108 million from a year ago, or 13.8%, driven by steady revenue flows and profitability as a result of the large number of oil & gas projects that were started during the upward phase of the oil cycle. IReturn on average capital employed calculated on an adjusted basis was 15.4% in 2009, lower than in 2008 (16.8%). IOrders acquired amounted to euro 9,917 million, down euro 3,943 million from 2008 (down 28.4%), in particular in onshore construction and onshore drilling activities. IOrder backlog amounting to euro 18,730 million at December 31, 2009 (euro 19,105 million at December 31, 2008), related in particular to projects in North Africa (30%), West Africa (15%) and the Rest of Europe (13%). ICapital expenditures amounted to euro 1,630 million, down euro 397 million from 2008, or 19.6%. The main projects relate to the upgrade of the construction and drilling fleet.

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Eni Fact BookEngineering & Construcion

Strategies

Eni operates in engineering, construction and drilling both offshore and onshore for the oil & gas industry through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 43%). Saipem boasts a strong position in the relevant market leveraging on technological and operational skills mainly in frontier areas, harsh environments and complex projects, as well as on engineering and project management capabilities and ownership or availability of necessary technologies as a result of a challenging internal (investments on offshore fleet) and external (acquisition of Bouygues Offshore and Snamprogetti) growth process. In spite of the uncertainty on the time of the recovery of global economy, Saipem plans to continue consolidating its position in the main business segments, implementing the following strategic guidelines: - To maximize the efficiency in all business areas maintaining top execution and security standards, preserving competitive supply costs, optimizing the utilization rate of the fleet, increasing structure flexibility in order to mitigate the effects of negative business cycles as well as developing and promoting a company culture that will permit the identification and management of risks and business opportunities.

- To continue focusing on the more complex and difficult projects in the strategic segments of deepwater, FPSO, heavy crude and LNG upgrading (offshore and onshore, for the monetization of stranded gas reserves) in order to consolidate the Company’s competitive position in large offshore and onshore projects for the development of hydrocarbon fields. - To promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries. - To leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition. - To complete the expansion and revamping program of its construction and drilling fleet in consideration of the future needs of the oil & gas industry, in order to confirm the Company’s leading position in the segment of complex projects with high profitability.

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Eni Fact BookEngineering & Construcion

Business areas 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 (one of the most relevant acquisitions was Bouygues Offshore).
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 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 the construction process through the creation of a large construction yard in South-East Asia and revamping/upgrading its construction fleet.
Over the next four years, Saipem will invest in the completion of new offshore vessels: an innovative pipelayer (CastorOne), a field development ship for deep waters (FDS2) and other supporting assets for offshore activity. These capital expenditures will allow the company to reinforce its capabilities in the operations performed in the deepwater and sub-Arctic areas. The company will also continue to invest (assets and infrastructures) supporting relevant projects in portfolio (among them the new Aquila FPSO, that will be operative in 2011). In 2009, revenues of the offshore segment were euro 4,317 million, accounting for 45% of total revenues. Contribution from operations came in at euro 719 million, up euro 108 million representing 55% of total contribution from operations. These results reflect in particular higher levels of activity in West Africa, Kazakhstan and the Mediterranean Area. Among the main acquisitions of 2009 were:
- a contract on behalf of Agip KCO as part of the development program of the Kashagan field related to the hook-up and commissioning of offshore facilities, as well as activities to be executed in the Kuryk construction yard in Kazakhstan;
- a contract on behalf of Eni for the conversion of a tanker into an FPSO (Floating Production Storage and Offloading) vessel that will have a storage and production capacity of 700 kbbl/d and 12 kbbl/d, respectively;
- an EPC contract on behalf of Esso Exploration Angola for

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Eni Fact BookEngineering & Construcion

the development of the Kizomba Satellites Project offshore Angola. The project is aimed to link the Mavacola and Clochas fields to the existing FPSO units. OnshoreSaipem is one of the world’s largest engineering and construction operator on a turnkey contract base in the oil & gas segment and in the onshore construction business, especially after its 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).
Leveraging on its distinctive know-how in the gas monetizing, Saipem is capable to manage large and complex turnkey projects in the high-tech sector of LNG. Saipem is currently building a large gas liquefaction plant in Algeria, as main contractor.
Saipem’s competitiveness is granted by the technological excellence of its engineering hubs and the management of large parts of engineering activities in cost efficient areas (Engineering Centre in India).
At the end of the current economic downturn, when a new cycle of investments in the oil & gas industry will take place, Saipem will be focused on taking advantage of the opportunities raising from the market in the plant and pipeline segments leveraging on its solid competitive position in the realization of complex projects in the strategic areas of the Middle East, Caspian Sea, North and West Africa and Russia. In 2009 revenues of the Onshore construction segment amounted to euro 4,258 million, accounting for 44% of total revenues. Contribution from operations of euro 313 million decreased by euro 28 million from 2008, mainly due to the postponement of the activities related to the Manifa project on behalf of Saudi Aramco. Among the major orders acquired in 2009 were:
- an EPC contract on behalf of the joint-venture between Eni and Sonatrach for the construction of facilities for the treatment of natural gas extracted from the Menzel Ledjmet field and from the future developments of the CAFC (Central Area Field Complex) in Algeria;
- an EPC contract on behalf of Sonatrach for the construction of the GK3 gas pipeline that will connect various cities situated in the north-eastern region of Algeria for a total length of approximately 350 kilometers;
- an EPC contract on behalf of Qafco for the construction of a new urea plant in the city of Mesaieed, in Qatar.

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Eni Fact BookEngineering & Construcion

Offshore drillingSaipem is the only engineering and construction contractor that provides also offshore and onshore drilling services to oil companies. In the offshore drilling segment Saipem mainly operates in West Africa, North Sea, Mediterranean Sea and 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 operating at a maximum depth of 3,000 meters.
Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments and to be adherent to the actual and future needs of the oil industry. In particular, in the next years Saipem intends to complete the building of: (i) the Scarabeo 8 and 9, new generation semi-submersible platforms, that have been already rented to Eni under multi-year contracts; and (ii) the new deepwater S12000 drilling ship to perform operations in West Africa on behalf of Total. In parallel, investments are underway 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 2009 revenues of the offshore drilling segment were euro 566 million, accounting for 6% of total revenues. Contribution from operations increased by euro 19 million to euro 207 million from a year earlier mainly related to higher levels of activity of the Perro Negro 3 and Perro Negro 7 jack up and of a Tender Assisted Drilling Barge. Main orders acquired in 2009 related to:
- a 3-year extension for the use of the Scarabeo 5 semi-submersible platform in the Norwegian section of the North Sea on behalf of Statoil;
- a 5-year extension of the contract for the use of the semi-submersible platform Scarabeo 6 in Egypt on behalf of Burullus Gas Company;
- a 12-month extension for the use of the recently built Perro Negro 6 jack up on behalf of Sonangol. Onshore drilling
Saipem operates in this area as 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 these areas Saipem can leverage on 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 2009, revenues of the onshore drilling segment were euro 523 million, accounting for 5% of total revenues. Contribution from

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operations came in at euro 71 million, down euro 15 million from 2008 reflecting lower average utilization rate of equipment.
The most significant contracts awarded during the period include:
- a contract on behalf of Agip KCO for the lease of 2 rigs in Kazakhstan for the development of the Kashagan field with a contract duration of five and half years; - a contract on behalf of Eni in Congo for the lease of two rigs that will operate in the M’Boundi field with a contract duration of two years;
- a contract on behalf of the joint-venture between First Calgary Petroleum and Sonatrach in Algeria for the lease of 2 rigs that will operate in the 405B block situated in the Berline basins with a contract duration of three years.

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Eni Fact BookEngineering & Construcion

Main operating data 2005 2006 2007 2008 2009

Offshore pipelines laid	(km)	883	1,514	665	815	1,000
Onshore pipelines laid	(km)	1,005	871	770	683	716
Offshore structures installed	(t)	134,602	120,453	187,054	24,835	62,333
Onshore structures installed	(t)	7,112	5,242	194,561	163,137	76,543
Offshore drilling	(km)	114	126	123	150	140
Onshore drilling	(km)	548	599	657	622	719
Offshore wells drilled	(units)	67	75	47	50	54
Onshore wells drilled	(units)	213	236	256	241	241

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
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			60
Castoro Otto	Crane and pipelay vessel	S	2,200	600	60
Saipem 3000	Mono-hull, self-propelled DP crane ship, capable of laying flexible pipes and umbilicals in deep waters and lifting structures	Reel, J, S	2,200	3,000	6
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
Saipem Trenching barge	Barge for post-trenching and backfilling of pipelines operating in 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		1,800
Ersai 2 (a)	Work barge equipped with a fixed crane capable of lifting structures		200
Ersai 400 (a)	Accommodation vessel (maximum capacity: 400 people), refuge provided
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	Launching/cargo barge		8,000
S44	Launching/cargo barge		30,000
S45	Launching/cargo barge		20,000
Bos 600	Launching/cargo barge		30,000
Saibos 103	Lightweight cargo barge		3,600
FPSO - Cidade de Vitoria	FPSO unit with a production capacity of up to 100,000 barrels a day

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

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Eni Fact BookEngineering & Construcion

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
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 TAD	Tender assisted drilling barge	Bentec 1500 Hp	150	4,877	Heliport provided

Main capital expenditures

Name Type Business Unit Start-up year

Scarabeo 8	Semi-submersible drilling platform self-propelled capable of operating in deep waters	Offshore drilling	2010
CastorOne	Dynamically positioned crane and pipelay (S-lay) vessel utilized for the development of hydrocarbon fields in deep waters	Offshore construction	2011
S12000	Dynamically positioned drillship	Offshore drilling	2010
Scarabeo 9	Semi-submersible self-propelled drilling platform capable of operating in deep waters	Offshore drilling	2010
New FDS 2	Multipurpose monohull dynamically positioned crane and pipelay (J-lay) vessel utilized for the development of hydrocarbon fields in deep waters	Offshore construction	2011
New DSV	Support vessel for offshore projects	Offshore construction	2011

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Eni Fact BookResearch and Innovation

Research and innovation

Research and innovation have been confirmed as key elements of Eni’s activities. Technologies developed at Eni will allow to access new energy resources, to improve their collection from the subsoil and their efficient use, reducing the environmental impact and effect on climate change of Eni’s businesses.
In 2009 Eni continued its commitment both at the level of energy supply, providing access to new and complex mineral basins or producing countries, and at the level of consumption and environmental sustainability of energy production.
In 2009 overall expenditure in R&D amounted to approximately euro 207 million, excluding general and administrative expenses (euro 217 million in 2008 and euro 208 million in 2007) net of general and overhead costs.
At December 31, 2009, a total of 1,019 persons were employed in research and development activities.
Within its growth strategy Eni considers intellectual property as a key factor. In the past few years Eni engaged in the generation, identification and protection of innovative results obtained in R&D both on the areas of technologies related to its core business and in the field of renewable energy sources. In 2009 Eni filed 106 patent applications (96 in 2008). In particular, 61 applications derived from Eni’s R&D departments, 15 concerned petrochemical technology and 30 the area of Engineering & Construction, In 2009 a total of 7,760 patents were in Eni’s portfolio, including patent applications and patents still in force.
In the next four years Eni defined a relevant capital expenditure plan in R&D amounting to approximately euro 1.4 billion, focusing in particular on:
- developing techniques aiming at improving the assessment of the production potential of fields and the performance of exploration and production activities; - increasing the hydrocarbon recovery factor;
- monetizing natural gas reserves and upgrading transport infrastructure;
- converting low grade products (e.g. ultra-heavy crude, bitumen, fuel oil) to higher grade distillates;
- producing biofuels from non food biomass;
- converting solar energy by means of innovative materials and processes.
Main innovation projects Depth Velocity Analysis (DVA)
Proprietary technology based on calculations on speed data from seismic prospecting for visualizing underground areas. In 2009 it has been successfully applied in Egypt and Angola. Depositional models
for meandering channel system
Proprietary technology based on geologic simulation codes that allows to build models on the more favorable conditions for hydrocarbon reservoirs. It allows to prepare three-dimensional simulations of past erosion and accumulation phases, typical of underwater channels. It has been successfully applied for the evaluation of mineral potential in fields in India and Angola. Uncertainty estimation
for thinly bedded reservoir
This methodology has been successfully applied in Angola for estimating the production potential of a field as it allows to detail some parts of the subsoil.

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Eni Fact BookResearch and Innovation

Coil shooting
This technology, applied for the first time ever in Indonesian waters, allows to obtain more detailed images of the subsoil than conventional techniques thanks to its innovative way of collecting and processing data: streamers pushed on spiraling routes instead of the traditional grid routes, reducing operating times and mineral risks. Dual casing running
This technology allows to drill a well with two different diameters and inserting casings with different diameters at the same time, thus reducing completion time and risks. In 2009 it has been successfully applied in West Africa. Radial drilling
This technology, applied by Eni in a pioneering effort, allows to increase production in heavy oil fields reducing also their footprint. Drilling is performed radially from the main well with small diameter bores. Enhanced Oil Recovery with CO₂ injection
In 2009 Eni completed the research phase for the application of this technique to increasing the recovery factor of heavy crudes in Eni operated fields. A field application is planned for 2010. CO₂ will be recovered from industrial plants near the fields. Bright Water Injection
This technology is based on an additive that is injected in the ground and selectively blocks the rock parts where water is present, thus potentially increasing the extraction of crude. A field test has been started with results scheduled for 2011. Gas-to-Liquids (GtL)
The GTL project, started in 1996 with IFP-Axens, developed a proprietary technique for turning natural gas into distillates. In 2009 the life test for the industrial catalyst for Fischer-Tropsch synthesis in the pilot plant at the Sannazzaro refinery has been completed, while the design has been started of a plant with a 15 bbl/d capacity.

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Eni Fact BookResearch and Innovation

Monitoring of offshore pipelines
(Dionisio project)
Eni is developing a proprietary technology based on vibro-acoustic systems (patent application filed) capable of detecting damage to underwater pipelines in real time. In 2009 a prototype has been installed at a gas import terminal. A field test on an offshore pipeline confirmed the potential of this approach. TPI-intermediate pressure transport
Eni is examining the potential and maturity of this transport option that seems to have a shorter time to market than the TAP technology (high pressure transport, still showing criticalities). The TPI project was started in 2008 with the production of the first grade X80 pipes by some world leading manufacturers. In 2009 other pipes have been bought and agreements have been signed for their welding. Tests on a real scale simulating operating conditions have been started. Conversion of heavy crude and fractions into lighter products
In 2009 Eni continued testing this proprietary technology at the Taranto demonstration plant. Testing was mainly aimed at validating the upgrading performance and the plant operation. Innovative solutions for maximizing process yields have been devised. Construction is underway of an industrial plant with a capacity of 23,000 bbl/d at the Sannazzaro refinery with start-up expected in 2012. The EST proprietary process consists in the conversion of heavy crudes and fractions into middle distillates for vehicles. As compared to the conversion technologies available on the market EST allows to fully convert feedstocks. Flexible FCC (fluid catalytic cracking)
A proprietary material – the ERS-10 zeolite – has been developed and used as additive in an FCC catalyst thus increasing the conversion of heavier fractions. In 2009 the catalytic results have been confirmed and cooperation has started with a leading firm in FCC catalyst production aimed at industrial testing in an Eni refinery. Dual Catalyst Slurry System
Aim of this project is to develop a catalyst that further increases the conversion of heavy residues into fuels. The development of a bi-functional catalyst is underway that hydrogenates and desulphorates feedstocks and increases the cracking rate and nitrogen removal. H₂S splitting
Aim of this project is the enhancement of hydrogen sulphide contained in natural gas or by-product of refining obtaining hydrogen from it. A promising technology consists in the decomposition of H₂S by means of cold plasma into sulphur and hydrogen. Lab activities were completed in 2009. Tests will be performed in a pilot plant in 2010. Downstream application of microwave technology
This application aims at significantly and permanently reducing the viscosity of crude and heavy cuts by applying microwaves. In the lab we tested the possibility of reducing the viscosity of crude, residues and bitumen improving their handling and reducing the use of flux oil. Based on the results reached, in 2009 two patent applications have been filed. For 2010 tests on a continuous reactor are scheduled.

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Eni Fact BookResearch and Innovation

Hydrogen
SCT-CPO (Short Contact Time-Catalytic Partial Oxidation) is a reforming technology that can convert gaseous and liquid hydrocarbons (also derived from biomass) into synthetic gas (carbon monoxide and hydrogen). This technology can contribute to process intensification as it allows to produce synthetic gas and hydrogen using reactors up to 100 times smaller than those currently in use with relevant savings. New formulas for fuels and lubricants
The development of the new premium products of the Blu line has been completed. Tests were performed on engines and vehicles in order to optimize engine efficiency and reducing noxious emissions. Tests of the new premium gasoline were performed on new Fiat engines in the framework of an agreement with the Fiat research center. In 2009 two new lubricants that reduce consumption and emissions reached the commercial stage. GHG program (Green House Gas)
Eni organized meetings with the people living in the area of Cortemaggiore aimed at informing them on the pending capture and sequestration of CO₂ in the subsoil of the municipality. Zero waste
The basic design has been completed of a pilot plant with a 50 kg/h capacity along with a feasibility study for the treatment of an annual volume of 5,000 tonnes of slime. This technology for the treatment of oily and biological waste generated by the oil industry by means of a thermal process developed by Eni allows to transform them in utilizable gas and inert residue that is easier and less costly to dispose. A patent application has been filed on this project. Ensolvex^® process
In the framework of the cleaning up of an area within the Gela refinery Eni plans to build an Ensolvex^® plant for the reclaiming of soil polluted by hydrocarbons within the limits imposed by the law. The design phase has been completed in 2009 and the plant is expected to be built by the first half of 2010. En-Z-lite^® process
In 2009 at the Taranto refinery a demonstration plant has been tested for removing organic compounds from water by means of adsorption on synthetic hydrophobic zeolites, complying with the most stringent standards on MTBE and TPH levels as well as metal content. This technology can be used for treating underground waters and discharge waters that can thus be re-used. A new system for regenerating zeolites has been patented. Green Diesel
In 2009 tests have been started for using non-food feedstock in the Ecofining^TM process, that has already been used with traditional vegetable oils at industrial level. Biodiesel by means of micro algae
The project aims at testing the technical and economic feasibility of a process based on the biofixation of CO₂ by means of micro algae for the purification of discharge waters with production of biomass that can be converted into biofuel. A pilot plant is nearing start-up at the Gela refinery. Biodiesel from waste
In the field of better use of biomass for energy production, Eni is developing an integrated thermal-fermenting process for the conversion of the organic fraction of urban waste into bio-oil that allows to reduce the volume of waste disposed of in land fills. Micro-organisms for diesel
Aim of the project is the identification of micro-organisms that metabolize organic substances and produce lipids, optimal precursors of biodiesel. A yeast has been identified that can grow efficiently on all the sugars present in wood-cellulose biomass and accumulates lipids up to 75% of its weight, thus improving the results obtained in 2008 (60%). Photoactive materials
In 2009 the first samples were obtained of devices allowing

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Eni Fact BookResearch and Innovation

to use a much smaller surface of silicon as compared to conventional photovoltaic technology, at parity of power produced, with a potential cost reduction for electricity generation. This result was obtained by using dull, transparent or colored plates including adequate substances playing a double role: converting solar light, concentrating and carrying light to the edges of the plate where silicon is located and converting radiating energy into electricity. The conversion of light is exerted on components of solar radiation that are usually underused by traditional silicon materials, converting them into radiation with a wavelength that can induce a photovoltaic effect. These results are expected to be consolidated in 2010 thus testing the reproducibility and stability of the process and preparing large prototypes.
When touched by ultraviolet light, invisible to human eyes, these plates emit blue or red visible light according to the element used and operate a spectrum conversion. This device increases the fraction of solar energy transformed into electricity of a photovoltaic system.

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Eni Fact BookFinancial Data

Profit and loss account (euro million) 2005 2006 2007 2008 2009

Net sales from operations (a)	73,692		86,071		87,204		108,082		83,227
Other income and revenues	801		796		833		728		1,118
Total revenues	74,493		86,867		88,037		108,810		84,345
Purchases, services and other	(48,534	)	(57,469	)	(58,133	)	(76,350	)	(58,351	)
Payroll and related costs	(3,351	)	(3,650	)	(3,800	)	(4,004	)	(4,181	)
Total operating expenses	(51,885	)	(61,119	)	(61,933	)	(80,354	)	(62,532	)
Other operating income (expense) (b)	(163	)	9		(129	)	(124	)	55
Depreciation, depletion, amortization and impairments	(5,781	)	(6,421	)	(7,236	)	(9,815	)	(9,813	)
Operating profit	16,664		19,336		18,739		18,517		12,055
Finance (expense) income	(203	)	152		46		(640	)	(551	)
Net income from investments	914		903		1,243		1,373		569
Profit before income taxes	17,375		20,391		20,028		19,250		12,073
Income taxes	(8,128	)	(10,568	)	(9,219	)	(9,692	)	(6,756	)
Tax rate (%)	46.8		51.8		46.0		50.3		56.0
Net profit	9,247		9,823		10,809		9,558		5,317
Attributable to:
- Eni	8,788		9,217		10,011		8,825		4,367
- minority interest	459		606		798		733		950
Net profit attributable to Eni	8,788		9,217		10,011		8,825		4,367
Exclusion of inventory holding (gain) loss	(759	)	33		(499	)	723		(191
Exclusion of special items	1,222		1,151		57		616		1,031
of which:
- non recurring items	290		239		35		(21	)	250
- other special items	932		912		22		637		781
Eni’s adjusted net profit	9,251		10,401		9,569		10,164		5,207

(a)

From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programmes be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results have been restated accordingly.

(b)

From year 2009, the Company accounts gains and losses on non-hedging commodity derivative instruments, including both fair value re-measurement and settled transactions, as items of operating profit. Adjusted operating profit and net profit only include gains and losses associated with settled transactions, gross and net of the associated tax impact respectively. Prior period results have been restated accordingly.

Summarized Group Balance Sheet (euro million) 2005 2006 2007 2008 2009

Fixed assets
Property, plant and equipment	45,013		44,312		50,137		59,255		63,177
Other assets			629		563
Inventories - compulsory stock	2,194		1,827		2,171		1,196		1,736
Intangible assets	3,194		3,753		4,333		7,697		8,057
Equity-accounted investments and other investments	4,311		4,246		6,111		5,881		6,244
Receivables and securities held for operating purposes	775		557		725		1,219		1,261
Net payables related to capital expenditures	(1,196	)	(1,090	)	(1,191	)	(787	)	(749	)
	54,291		54,234		62,849		74,461		79,726
Net working capital
Inventories	3,563		4,752		5,499		6,082		5,495
Trade receivables	14,101		15,230		15,609		16,444		14,916
Trade payables	(8,170	)	(10,528	)	(11,092	)	(12,590	)	(10,078	)
Tax payables and provision for net deferred tax liabilities	(4,857	)	(5,396	)	(4,412	)	(5,323	)	(1,988	)
Provisions	(7,643	)	(8,580	)	(8,433	)	(9,506	)	(10,319	)
Other current and non-current assets and liabilities (a)	(562	)	(675	)	(2,653	)	(4,544	)	(3,968	)
	(3,568	)	(5,197	)	(5,482	)	(9,437	)	(5,942	)
Current investments					2,476		2,741
Provisions for employee post-retirement benefits	(1,031	)	(1,071	)	(935	)	(947	)	(944	)
Net assets held for sale including related net borrowings			286		68		266
CAPITAL EMPLOYED, NET	49,692		47,966		59,194		66,886		73,106
Shareholders’ equity:
attributable to:
- Eni (b)	36,868		39,029		40,428		44,436		46,073
- Minority interest	2,349		2,170		2,439		4,074		3,978
	39,217		41,199		42,867		48,510		50,051
Net borrowings	10,475		6,767		16,327		18,376		23,055
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	49,692		47,966		59,194		66,886		73,106

(a)	Include receivables and securities for financing operating activities and securities covering technical reserves of Eni’s insurance activities.
(b)	Net of own shares in portfolio.

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Eni Fact BookFinancial Data

Summarized Group Cash Flow Statement (euro million) 2005 2006 2007 2008 2009

Net profit	9,247		9,823		10,809		9,558		5,317
Adjustments to reconcile to cash generated from operating profit before changes in working capital:
- amortization and depreciation and other non monetary items	6,518		5,753		6,346		11,388		9,847
- net gains on disposal of assets	(220	)	(59	)	(309	)	(219	)	(226	)
- dividends, interest, taxes and other changes	8,471		10,435		8,850		9,080		6,687
Net cash generated from operating profit before changes in working capital	24,016		25,952		25,696		29,807		21,625
Changes in working capital related to operations	(2,422	)	(1,024	)	(1,667	)	2,212		(1,769	)
Dividends received, taxes paid, interest (paid) received during the period	(6,658	)	(7,927	)	(8,512	)	(10,218	)	(8,720	)
Net cash provided by operating activities	14,936		17,001		15,517		21,801		11,136
Capital expenditures	(7,414	)	(7,833	)	(10,593	)	(14,562	)	(13,695	)
Investments and purchase of consolidated subsidiaries and businesses	(127	)	(95	)	(9,665	)	(4,019	)	(2,323	)
Disposals	542		328		659		979		3,595
Other cash flow related to capital expenditures, investments and disposals	293		361		(35	)	(267	)	(295	)
Free cash flow	8,230		9,762		(4,117	)	3,932		(1,582	)
Borrowings (repayment) of debt related to financing activities	(109	)	216		(479	)	911		396
Changes in short and long-term finance debt	(540	)	(682	)	8,761		980		3,841
Dividends paid and changes in minority interest and reserves	(7,284	)	(6,443	)	(5,836	)	(6,005	)	(2,956	)
Effect of changes in consolidation and exchange differences	33		(201	)	(200	)	7		(30	)
NET CASH FLOW FOR THE PERIOD	330		2,652		(1,871	)	(175	)	(331	)

Change in net borrowings (euro million) 2005 2006 2007 2008 2009

Free cash flow	8,230		9,762		(4,117	)	3,932		(1,582	)
Net borrowings of acquired companies	(19	)			(244	)	(286	)
Net borrowings of divested companies	21		1				181
Exchange differences on net borrowings and other changes	(980	)	388		637		129		(141	)
Dividends paid and changes in minority interest and reserves	(7,284	)	(6,443	)	(5,836	)	(6,005	)	(2,956	)
CHANGE IN NET BORROWINGS	(32	)	3,708		(9,560	)	(2,049	)	(4,679	)

Net sales from operations (euro million) 2005 2006 2007 2008 2009

Exploration & Production	22,120		26,738		26,920		33,042		23,801
Gas & Power	23,174		28,547		27,793		37,062		30,447
Refining & Marketing	33,696		38,176		36,349		45,017		31,769
Petrochemicals	6,255		6,823		6,934		6,303		4,203
Engineering & Construction	5,733		6,979		8,678		9,176		9,664
Other activities	863		823		205		185		88
Corporate and financial companies	1,239		1,174		1,313		1,331		1,280
Impact of unrealized intragroup profit elimination (a)							75		(66	)
Consolidation adjustment	(19,388	)	(23,189	)	(20,988	)	(24,109	)	(17,959	)
	73,692		86,071		87,204		108,082		83,227

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

Net sales to customers (euro million) 2005 2006 2007 2008 2009

Exploration & Production	7,562	8,545	10,640	14,125	10,171
Gas & Power	22,605	27,800	27,036	36,189	29,812
Refining & Marketing	32,604	36,876	35,073	43,521	30,804
Petrochemicals	5,572	6,156	6,571	5,905	3,965
Engineering & Construction	4,808	6,208	7,496	7,957	8,349
Other activities	317	303	174	156	64
Corporate and financial companies	224	183	214	154	128
Impact of unrealized intragroup profit elimination				75	(66	)
	73,692	86,071	87,204	108,082	83,227

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Eni Fact BookFinancial Data

Net sales by geographic area of destination (euro million) 2005 2006 2007 2008 2009

Italy	32,810	36,309	37,294	42,843	27,950
Other EU countries	19,601	23,949	23,074	29,341	24,331
Rest of Europe	5,123	6,975	5,507	7,125	5,213
Africa	5,259	5,949	8,010	12,331	10,174
Americas	6,103	6,250	6,447	7,218	7,080
Asia	4,399	5,595	5,840	8,916	8,208
Other areas	397	1,044	1,032	308	271
Total outside Italy	40,882	49,762	49,910	65,239	55,277
	73,692	86,071	87,204	108,082	83,227

Purchases, services and other (euro million) 2005 2006 2007 2008 2009

Production costs - raw, ancillary and consumable materials and goods	35,271		44,625		44,850		58,662		40,331
Production costs - services	9,405		10,015		10,828		13,355		13,520
Operating leases and other	1,929		1,903		2,276		2,558		2,567
Net provisions	1,654		769		573		884		1,055
Other expenses	1,103		1,102		1,101		1,660		1,507
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(828	)	(945	)	(1,495	)	(769	)	(629	)
	48,534		57,469		58,133		76,350		58,351

Principal accountant fees and services (euro million) 2005 2006 2007 2008 2009

Audit fees	12,591	22,240	26,383	27,962	30,748
Audit-related fees	190	166	169	152	276
Tax fees	246	303	81	46	51
All other fees	38	6	120	1
	13,065	22,715	26,753	28,161	31,075

Payroll and related costs (euro million) 2005 2006 2007 2008 2009

Wages and salaries	2,484		2,630		2,906		3,204		3,330
Social security contributions	662		691		690		694		706
Cost related to defined benefit plans and defined contribution plans	126		230		161		107		137
Other costs	255		305		275		282		342
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(176	)	(206	)	(232	)	(283	)	(334	)
	3,351		3,650		3,800		4,004		4,181

Depreciation, depletion, amortization and impairments (euro million) 2005 2006 2007 2008 2009

Exploration & Production	3,897		4,589		5,431		6,678		6,789
Gas & Power	732		744		739		797		981
Refining & Marketing	462		434		433		430		408
Petrochemicals	118		124		116		117		83
Engineering & Construction	176		195		248		335		433
Other activities	16		6		4		3		2
Corporate and financial companies	112		70		68		76		83
Impact of unrealized intragroup profit elimination	(4	)	(9	)	(10	)	(14	)	(17	)
Total depreciation, depletion and amortization	5,509		6,153		7,029		8,422		8,762
Impairments	272		268		207		1,393		1,051
	5,781		6,421		7,236		9,815		9,813

Operating profit by division (euro million) 2005 2006 2007 2008 2009

Exploration & Production	12,324		15,368		13,433		16,239		9,120
Gas & Power	3,580		4,022		4,465		4,030		3,687
Refining & Marketing	1,852		324		686		(988	)	(102	)
Petrochemicals	202		172		100		(845	)	(675	)
Engineering & Construction	307		505		837		1,045		881
Other activities	(934	)	(622	)	(444	)	(346	)	(382	)
Corporate and financial companies	(526	)	(300	)	(312	)	(743	)	(474	)
Impact of unrealized intragroup profit elimination	(141	)	(133	)	(26	)	125
	16,664		19,336		18,739		18,517		12,055

- 94 -

Eni Fact BookFinancial 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. Further more, finance charges on finance debt, interest income, gains or losses deriving from 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 of 34% is applied to finance charges and income (33% in previous reporting periods). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or U.S. GAAP. Management includes them in order to facilitate a comparison of base business performance across periods and allow financial analysts to evaluate Eni’s 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 transaction, 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 management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives, including the ineffective portion of cash flow hedges. 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 BookFinancial Data

2005 (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	12,324		3,580		1,852		202		307		(934	)	(526	)	(141	)	16,664
Exclusion of inventory holding (gains) losses			(127	)	(1,064	)	(19	)									(1,210	)
Exclusion of special items
of which:
Non-recurring (income) charges			290														290
Other special (income) charges:	325		40		422		78		7		638		142				1,652
- environmental charges			31		337						413		54				835
- asset impairments	247		1		5		29		4		75		2				363
- risk provisions					39		36				126						201
- increase insurance charges	57		6		30		17				4		64				178
- provision for redundancy incentives	7		8		22		4		3		6		29				79
- re-measurement gains/losses on commodity derivatives	14		(7	)	1								(7	)			1
- other			1		(12	)	(8	)			14						(5	)
Special items of operating profit	325		330		422		78		7		638		142				1,942
Adjusted operating profit	12,649		3,783		1,210		261		314		(296	)	(384	)	(141	)	17,396
Net finance (expense) income (a)	(72	)	29										(133	)			(176	)
Net income from investments (a)	10		370		231		3		141		(1	)	23				777
Income taxes (a)	(6,555	)	(1,478	)	(498	)	(37	)	(127	)			356		52		(8,287	)
Tax rate (%)	52.1		35.3		34.6				27.9								46.0
Adjusted net profit	6,032		2,704		943		227		328		(297	)	(138	)	(89	)	9,710
of which:
- Adjusted net profit of minority interest																	459
- Eni’s adjusted net profit																	9,251
Eni’s reported net profit																	8,788
Exclusion of inventory holding (gains) losses																	(759	)
Exclusion of special items:																	1,222
- non-recurring (income) charges																	290
- other special (income) charges																	932
Eni’s adjusted net profit																	9,251

(a) Excluding special items.

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Eni Fact BookFinancial Data

2006 (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	15,368		4,022		324		172		505		(622	)	(300	)	(133	)	19,336
Exclusion of inventory holding (gains) losses			(67	)	215		(60	)									88
Exclusion of special items
of which:
Non-recurring (income) charges			55		109		13				62						239
Other special (income) charges:	153		107		146		94		3		261		56				820
- environmental charges			44		111						126		11				292
- asset impairments	231		51		14		50		1		22						369
- gains on disposals of assets	(61	)															(61	)
- risk provisions					8		31				75						114
- provision for redundancy incentives	13		37		47		19		2		17		43				178
- re-measurement gains/losses on commodity derivatives	(30	)	15		(1	)											(16	)
- other			(40	)	(33	)	(6	)			21		2				(56	)
Special items of operating profit	153		162		255		107		3		323		56				1,059
Adjusted operating profit	15,521		4,117		794		219		508		(299	)	(244	)	(133	)	20,483
Net finance (expense) income (a)	(50	)	7								(7	)	196				146
Net income from investments (a)	85		489		184		2		66		5						831
Income taxes (a)	(8,421	)	(1,611	)	(347	)	(47	)	(174	)			93		54		(10,453	)
Tax rate (%)	54.1		34.9		35.5				30.3								48.7
Adjusted net profit	7,135		3,002		631		174		400		(301	)	45		(79	)	11,007
of which:
- Adjusted net profit of minority interest																	606
- Eni’s adjusted net profit																	10,401
Eni’s reported net profit																	9,217
Exclusion of inventory holding (gains) losses																	33
Exclusion of special items:																	1,151
- non-recurring (income) charges																	239
- other special (income) charges																	912
Eni’s adjusted net profit																	10,401

(a) Excluding special items.

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Eni Fact BookFinancial 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:
- Adjusted net profit of minority interest																	624
- Eni's adjusted net profit																	9,569
Eni's reported net profit																	10,011
Exclusion of inventory holding (gains) losses																	(499	)
Exclusion of special items:																	57
- non-recurring (income) charges																	35
- other special (income) charges																	22
Eni's adjusted net profit																	9,569

(a) Excluding special items.

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Eni Fact BookFinancial 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		(346	)	(743	)	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	)	102		461				2,176
- environmental charges			12		76						101		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	)	102		461				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:
- Adjusted net profit of minority interest																	631
- Eni's adjusted net profit																	10,164
Eni's reported net profit																	8,825
Exclusion of inventory holding (gains) losses																	723
Exclusion of special items:																	616
- non-recurring (income) charges																	(21	)
- other special (income) charges																	637
Eni's adjusted net profit																	10,164

(a) Excluding special items.

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Eni Fact BookFinancial 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		(382	)	(474	)			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	)	124		132				1,162
- environmental charges			19		72						153		54				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		124		132				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:
- Adjusted net profit of minority interest																	950
- Eni's adjusted net profit																	5,207
Eni's reported net profit																	4,367
Exclusion of inventory holding (gains) losses																	(191	)
Exclusion of special items:																	1,031
- non-recurring (income) charges																	250
- other special (income) charges																	781
Eni's adjusted net profit																	5,207

(a) Excluding special items.

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Eni Fact BookFinancial Data

Breakdown of special items (euro million) 2005 2006 2007 2008 2009

Non-recurring charges (income)	290		239		8		(21	)	250
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	290		239		91		(21	)
Other special charges (income):	1,652		820		877		2,176		1,162
- environmental charges	835		292		365		309		298
- asset impairments	363		369		290		1,572		1,162
- gains on disposal of assets			(61	)			(8	)	(277	)
- risk provisions	201		114		22		4		128
- increase insurance charges	178
- provision for redundancy incentives	79		178		156		91		134
- re-measurement gains/losses on commodity derivatives	1		(16	)	147		(61	)	(287	)
- other	(5	)	(56	)	(103	)	269		4
Special items of operating profit	1,942		1,059		885		2,155		1,412
Net finance (expense) income	27		(6	)	(23	)
Net income from investments	(137	)	(72	)	(321	)	(239	)	179
of which:
gain on the disposal of Italiana Petroli (IP)	(132	)
gain on Galp Energia SGPS SA (disposal of A21 assets Rede Electrica National)			(73	)
gain from the sale of stakes in Haldor Topsøe AS and Camom SA					(290	)
gain on divestment of GTT (Gaztransport et Technigaz SAS)							(185	)
Income taxes	(610	)	170		(658	)	(1,402	)	(560	)
of which:
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	)
supplemental tax rate UK			91
wind-fall tax Algeria			179
tax proceedings Venezuela			77
impairment of deferred tax assets E&P									72
other tax items					(50	)	(46	)	(192	)
taxes on special items of operating profit	(610	)	(177	)	(214	)	(623	)	(413	)
Total special items of net profit	1,222		1,151		(117	)	514		1,031
attributable to:
- Minority interest					(174	)	(102	)
- Eni	1,222		1,151		57		616		1,031

Adjusted operating profit by division (euro million) 2005 2006 2007 2008 2009

Exploration & Production	12,649		15,521		13,770		17,222		9,484
Gas & Power	3,783		4,117		4,414		3,564		3,901
Refining & Marketing	1,210		794		292		580		(357	)
Petrochemicals	261		219		116		(398	)	(426	)
Engineering & Construction	314		508		840		1,041		1,120
Other activities	(296	)	(299	)	(207	)	(244	)	(258	)
Corporate and financial companies	(384	)	(244	)	(195	)	(282	)	(342	)
Impact of unrealized intragroup profit elimination	(141	)	(133	)	(26	)	125
	17,396		20,483		19,004		21,608		13,122

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Eni Fact BookFinancial Data

Adjusted net profit by division (euro million) 2005 2006 2007 2008 2009

Exploration & Production	6,032		7,135		6,328		7,900		3,878
Gas & Power	2,704		3,002		3,127		2,648		2,916
Refining & Marketing	943		631		294		521		(197	)
Petrochemicals	227		174		74		(323	)	(340	)
Engineering & Construction	328		400		658		784		892
Other activities	(297	)	(301	)	(210	)	(279	)	(245	)
Corporate and financial companies	(138	)	45		(62	)	(532	)	(744	)
Impact of unrealized intragroup profit elimination (a)	(89	)	(79	)	(16	)	76		(3	)
	9,710		11,007		10,193		10,795		6,157
of which attributable to:
Minority interest	459		606		624		631		950
Eni	9,251		10,401		9,569		10,164		5,207

Finance income (expense) (euro million) 2005 2006 2007 2008 2009

Income from equity instruments					188		241		163
Exchange differences, net	169		(152	)	(51	)	206		(106	)
Finance income (expense) related to net borrowings and other	(235	)	(121	)	(279	)	(668	)	(612	)
Net income from securities	36		51		39		21		3
Financial expense due to the passage of time (accretion discount)	(109	)	(116	)	(186	)	(249	)	(218	)
Income (expense) on derivatives	(223	)	374		155		(427	)	(4	)
less:
Finance expense capitalized	159		116		180		236		223
	(203	)	152		46		(640	)	(551	)
of which, net income from receivables and securities held for financing operating activities and interest on tax credits	106		119		96		62		39

Income (expense on) from investments (euro million) 2005 2006 2007 2008 2009

Share of profit of equity-accounted investments	770		887		906		761		693
Share of loss of equity-accounted investments	(33	)	(36	)	(135	)	(105	)	(241	)
Gains on disposals	179		25		301		218		16
Losses on disposals	(8	)	(7	)	(1	)	(1	)
Dividends	33		98		170		510		164
Decreases (increases) in the provision for losses on investments			(56	)	2		(16	)	(59	)
Other income (expense), net	(27	)	(8	)			6		(4	)
	914		903		1,243		1,373		569

- 102 -

Eni Fact BookFinancial Data

Property, plant and equipment by division (at year end) (euro million) 2005 2006 2007 2008 2009

Property, plant and equipment gross
Exploration & Production	47,916		47,619		52,780		64,338		71,189
Gas & Power	22,730		23,660		24,641		26,566		27,998
Refining & Marketing	9,420		11,273		12,421		12,899		13,378
Petrochemicals	4,402		4,380		4,918		5,036		5,174
Engineering & Construction	3,878		4,363		5,823		7,702		9,163
Other activities	1,999		1,967		1,543		1,550		1,592
Corporate and financial companies	453		321		344		391		373
Impact of unrealized intragroup profit elimination	(88	)	(128	)	(227	)	(355	)	(343	)
	90,710		93,455		102,243		118,127		128,524
Property, plant and equipment net
Exploration & Production	23,956		22,355		25,751		32,355		34,462
Gas & Power	14,289		14,714		15,204		16,360		17,190
Refining & Marketing	3,556		3,791		4,495		4,496		4,397
Petrochemicals	1,139		1,072		1,099		912		853
Engineering & Construction	1,847		2,225		3,513		5,154		6,305
Other activities	117		93		82		83		79
Corporate and financial companies	193		176		196		212		179
Impact of unrealized intragroup profit elimination	(84	)	(114	)	(203	)	(317	)	(288	)
	45,013		44,312		50,137		59,255		63,177

Capital expenditures by division (euro million) 2005 2006 2007 2008 2009

Exploration & Production	4,932	5,163		6,480		9,281		9,486
Gas & Power	1,185	1,214		1,511		2,058		1,686
Refining & Marketing	656	645		979		965		635
Petrochemicals	112	99		145		212		145
Engineering & Construction	349	591		1,410		2,027		1,630
Other activities	48	72		59		52		44
Corporate and financial companies	132	88		108		95		57
Impact of unrealized intragroup profit elimination		(39	)	(99	)	(128	)	12
	7,414	7,833		10,593		14,562		13,695

Capital expenditures by geographic area of origin (euro million) 2005 2006 2007 2008 2009

Italy	2,442	2,529	3,246	3,674	3,198
Other European Union countries	545	713	1,246	1,660	1,454
Rest of Europe	415	436	469	582	574
Africa	2,233	2,419	3,152	5,153	4,645
Americas	507	572	1,004	1,240	1,207
Asia	1,181	1,032	1,253	1,777	2,033
Other areas	91	132	223	476	584
Total outside Italy	4,972	5,304	7,347	10,888	10,497
	7,414	7,833	10,593	14,562	13,695

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Eni Fact BookFinancial 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

2005
Short-term debt	5,345	(1,333	)	(903	)	(12	)	3,097
Long-term debt	7,653			(28	)	(247	)	7,378
	12,998	(1,333	)	(931	)	(259	)	10,475
2006
Short-term debt	4,290	(3,985	)	(552	)	(143	)	(390	)
Long-term debt	7,409					(252	)	7,157
	11,699	(3,985	)	(552	)	(395	)	6,767
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

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Eni Fact BookFinancial Data

Employees

Employees at year end (units) 2005 2006 2007 2008 2009

	Italy	4,736	4,977	5,224	5,468	5,287
Exploration & Production	Outside Italy	3,003	3,063	3,799	5,423	5,583
		7,739	8,040	9,023	10,891	10,870
	Italy	10,024	9,898	9,425	9,113	8,911
Gas & Power	Outside Italy	2,591	2,472	2,468	2,579	2,493
		12,615	12,370	11,893	11,692	11,404
	Italy	6,680	7,196	7,101	6,641	6,493
Refining & Marketing	Outside Italy	2,214	2,241	2,327	1,686	1,673
		8,894	9,437	9,428	8,327	8,166
	Italy	5,164	4,948	5,476	5,230	5,054
Petrochemicals	Outside Italy	1,298	1,077	1,058	1,044	1,014
		6,462	6,025	6,534	6,274	6,068
	Italy	5,799	6,164	6,618	7,316	7,003
Engineering & Construction	Outside Italy	22,885	24,738	26,493	28,313	28,966
		28,684	30,902	33,111	35,629	35,969
	Italy	2,636	2,219	1,172	1,070	968
Other activities	Outside Italy
		2,636	2,219	1,172	1,070	968
	Italy	5,153	4,363	4,411	4,642	4,583
Corporate and financial companies	Outside Italy	75	216	290	355	389
		5,228	4,579	4,701	4,997	4,972
	Italy	40,192	39,765	39,427	39,480	38,299
Total employees at year end	Outside Italy	32,066	33,807	36,435	39,400	40,118
		72,258	73,572	75,862	78,880	78,417
of which: senior managers		1,748	1,603	1,585	1,658	1,649

(a) From January 1, 2009, employees of "Stoccaggi Gas Italia", accounted for in the Exploration & Production segment until December 31, 2008, are reported within the Gas & Power segment, in the regulated business results, following restructuring of Eni regulated gas business in Italy. As of that date, regulated businesses in Italy therefore include the Transport, Distribution, Regasification and Storage activities in Italy. Prior period have been restated accordingly.

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Eni Fact BookFinancial Data

Supplemental oil and gas information

Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of 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 price¹ 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.
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 evaluation² 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 report³.
In the preparation of their reports, independent evaluators rely, without independent verification, upon information 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; technical analysis relevant to field performance, reservoir performance, long-term development plans, future capital and operating costs.
In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided.
In 2009 Ryder Scott Company and DeGolyer and MacNaughton³ provided an independent evaluation of almost 28% of Eni’s total proved reserves as of December 31, 2009⁴ confirming, as in previous years, the reasonableness of Eni’s internal evaluations.
In the three year period from 2007 to 2009, 86% of Eni’s total proved reserves were subject to independent evaluation.
As of December 31, 2009 among the most important Eni properties, the only one which was not subject to an independent review was Barbara (Italy).
Eni operates under Production Sharing Agreements, PSAs, in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery.
Proved oil and gas reserves associated with PSAs represented 46%, 54% and 57% of total proved reserves as of

(1)	In prior periods, year-end liquids and natural gas prices were used in the estimate of proved reserves.
(2)	From 1991 to 2002 DeGolyer and MacNaughton, from 2003 also Ryder Scott Company.
(3)	The reports of independent engineers are available on Eni website www.eni.com, section Documentation/Annual Report 2009.
(4)	Including reserves of joint ventures and affiliates.

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Eni Fact BookFinancial Data

December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis.
Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 1%, 2% and 2% of total proved reserves on an oil-equivalent basis as of December 31, 2007, 2008 and 2009, respectively.
Oil and gas reserve quantities include: (i) oil and natural gas quantities in excess to 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 1.8%, 0.1% and 0.3% of total proved reserves as of December 31, 2007, 2008 and 2009, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption, (iii) the quantities of natural gas produced to feed the Angola LNG plant and (iv) volumes of natural gas held in certain Eni’s 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 judgment. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be actually produced.
The following tables present yearly changes in estimated proved reserves, developed and undeveloped, of hydrocarbon, oil (including condensate and natural gas liquids) and natural gas as of December 31, 2007, 2008 and 2009.

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Eni Fact BookFinancial Data

Movements in net proved hydrocarbons reserves ^(a) (mmboe)

Italy ^(b) Rest of Europe North Africa West Africa Kazakhstan ^(c) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities^(d) Total

Reserves at December 31, 2006	805		706		2,018		1,122		1,219		235		150		145		6,400		36		6,436
of which:
- developed	562		586		1,242		798		525		161		82		76		4,032		27		4,059
- undeveloped	243		120		776		324		694		74		68		69		2,368		9		2,377
Purchase of Minerals in Place							33						123				156		617		773
Revisions of Previous Estimates	18		26		8		(13	)	(153	)	(2	)	(21	)	(6	)	(143	)	20		(123	)
Improved Recovery			2		9		12										23		1		24
Extensions and Discoveries	1		2		59		59		36		1		42		1		201		1		202
Production	(77	)	(98	)	(215	)	(118	)	(41	)	(36	)	(35	)	(7	)	(627	)	(7	)	(634	)
Reserves at December 31, 2007	747		638		1,879		1,095		1,061		198		259		133		6,010		668		6,678
of which:
- developed	534		537		1,183		766		494		127		158		63		3,862		101		3,963
- undeveloped	213		101		696		329		567		71		101		70		2,148		567		2,715
Purchase of Minerals in Place			2				33				56						91				91
Revisions of Previous Estimates	2		(41	)	259		87		374		51		9		5		746		5		751
Improved Recovery					7		26										33		1		34
Extensions and Discoveries	5		17		11		26				4		8				71				71
Production	(73	)	(91	)	(234	)	(121	)	(40	)	(44	)	(41	)	(6	)	(650	)	(8	)	(658	)
Sales of Minerals in Place									(59	)							(59	)			(59	)
Reserves at December 31, 2008	681		525		1,922		1,146		1,336		265		235		132		6,242		666		6,908
of which:
- developed	465		417		1,229		827		647		168		133		62		3,948		107		4,055
- undeveloped	216		108		693		319		689		97		102		70		2,294		559		2,853
Purchase of Minerals in Place							2						24				26				26
Revisions of Previous Estimates	74		65		76		102		(72	)	(26	)	44		(2	)	261		3		264
Improved Recovery			13		10		14										37				37
Extensions and Discoveries	10		79		121		6				44		13		9		282		15		297
Production	(62	)	(91	)	(207	)	(129	)	(43	)	(47	)	(53	)	(6	)	(638	)	(8	)	(646	)
Sales of Minerals in Place			(1	)													(1	)	(314	)	(315	)
Reserves at December 31, 2009	703		590		1,922		1,141		1,221		236		263		133		6,209		362		6,571
of which:
- developed	490		432		1,266		799		614		139		168		122		4,030		74		4,104
- undeveloped	213		158		656		342		607		97		95		11		2,179		288		2,467

(a)	The conversion rate of natural gas from cubic feet to boe is 1,000 cubic feet = 0.1742 barrels of oil.
(b)	Including approximately, 754, 749, 746 and 769 billion of cubic feet of natural gas held in storage at December 31, 2006, 2007, 2008 and 2009, respectively.
(c)	Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007 and 2006.
(d)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).

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Eni Fact BookFinancial Data

Movements in net proved liquids reserves (mmbbl)

Italy Rest of Europe North Africa West Africa Kazakhstan ^(a) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(b) Total

Reserves at December 31, 2006	215		386		982		786		893		62		98		35		3,457		24		3,481
of which:
- developed	136		329		713		546		262		53		54		33		2,126		18		2,144
- undeveloped	79		57		269		240		631		9		44		2		1,331		6		1,337
Purchase of Minerals in Place							32						54				86		101		187
Revisions of Previous Estimates	28		14		(35	)	(26	)	(114	)	(6	)	(23	)	(2	)	(164	)	20		(144	)
Improved Recovery			1		9		12										22		1		23
Extensions and Discoveries			1		43		22						28		1		95		1		96
Production	(28	)	(57	)	(121	)	(101	)	(26	)	(12	)	(19	)	(5	)	(369	)	(5	)	(374	)
Reserves at December 31, 2007	215		345		878		725		753		44		138		29		3,127		142		3,269
of which:
- developed	133		299		649		511		219		35		81		26		1,953		26		1,979
- undeveloped	82		46		229		214		534		9		57		3		1,174		116		1,290
Purchase of Minerals in Place							32				36						68				68
Revisions of Previous Estimates	(8	)	(30	)	56		80		239		42		11		1		391		4		395
Improved Recovery					7		25										32		1		33
Extensions and Discoveries	4		13		4		26				2		3				52				52
Production	(25	)	(51	)	(122	)	(105	)	(25	)	(18	)	(21	)	(4	)	(371	)	(5	)	(376	)
Sales of Minerals in Place									(56								(56	)			(56	)
Reserves at December 31, 2008	186		277		823		783		911		106		131		26		3,243		142		3,385
of which:
- developed	111		222		613		576		298		92		74		23		2,009		33		2,042
- undeveloped	75		55		210		207		613		14		57		3		1,234		109		1,343
Purchase of Minerals in Place							2										2				2
Revisions of Previous Estimates	57		40		129		78		(36	)	(35	)	36		1		270				270
Improved Recovery			8		10		15										33				33
Extensions and Discoveries	10		74		38		5				44		12		8		191		1		192
Production	(20	)	(48	)	(105	)	(113	)	(26	)	(21	)	(26	)	(3	)	(362	)	(6	)	(368	)
Sales of Minerals in Place																			(51	)	(51	)
Reserves at December 31, 2009	233		351		895		770		849		94		153		32		3,377		86		3,463
of which:
- developed	141		218		659		544		291		45		80		23		2,001		34		2,035
- undeveloped	92		133		236		226		558		49		73		9		1,376		52		1,428

(a)	Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007 and 2006.
(b)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).

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Eni Fact BookFinancial Data

Movements in net proved natural gas reserves (bcf)

Italy ^(a) Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(c) Total

Reserves at December 31, 2006	3,391		1,836		5,946		1,927		1,874		991		299		633		16,897		68		16,965
of which:
- developed	2,449		1,480		3,042		1,447		1,511		614		159		247		10,949		48		10,997
- undeveloped	942		356		2,904		480		363		377		140		386		5,948		20		5,968
Purchase of Minerals in Place							5						395				400		2,963		3,363
Revisions of Previous Estimates	(53	)	66		250		74		(222	)	23		4		(20	)	122		5		127
Improved Recovery			3														3				3
Extensions and Discoveries	4		6		89		213		205		4		86				607				607
Production	(285	)	(236	)	(534	)	(97	)	(87	)	(138	)	(88	)	(15	)	(1,480	)	(14	)	(1,494	)
Reserves at December 31, 2007	3,057		1,675		5,751		2,122		1,770		880		696		598		16,549		3,022		19,571
of which:
- developed	2,304		1,364		3,065		1,469		1,580		530		442		213		10,967		428		11,395
- undeveloped	753		311		2,686		653		190		350		254		385		5,582		2,594		8,176
Purchase of Minerals in Place			8				6				114						128				128
Revisions of Previous Estimates	56		(58	)	1,163		45		772		52		(13	)	24		2,041		6		2,047
Improved Recovery							4										4				4
Extensions and Discoveries	5		25		38		2				11		31				112				112
Production	(274	)	(229	)	(641	)	(95	)	(89	)	(146	)	(114	)	(16	)	(1,604	)	(13	)	(1,617	)
Sales of Minerals in Place									(16	)							(16	)			(16	)
Reserves at December 31, 2008	2,844		1,421		6,311		2,084		2,437		911		600		606		17,214		3,015		20,229
of which:
- developed	2,031		1,122		3,537		1,443		2,005		439		340		221		11,138		420		11,558
- undeveloped	813		299		2,774		641		432		472		260		385		6,076		2,595		8,671
Purchase of Minerals in Place							1						136				137				137
Revisions of Previous Estimates	97		149		(309	)	142		(204	)	52		43		(17	)	(47	)	18		(29	)
Improved Recovery			25														25				25
Extensions and Discoveries	1		26		479						2		7		4		519		80		599
Production	(238	)	(239	)	(587	)	(100	)	(94	)	(151	)	(155	)	(18	)	(1,582	)	(14	)	(1,596	)
Sales of Minerals in Place			(2	)									(2	)			(4	)	(1,511	)	(1,515	)
Reserves at December 31, 2009	2,704		1,380		5,894		2,127		2,139		814		629		575		16,262		1,588		17,850
of which:
- developed	2,001		1,231		3,486		1,463		1,859		539		506		565		11,650		234		11,884
- undeveloped	703		149		2,408		664		280		275		123		10		4,612		1,354		5,966

(a)	Including approximately, 754, 749, 746 and 769 billion of cubic feet of natural gas held in storage at December 31, 2006, 2007, 2008 and 2009, respectively.
(b)	Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007 and 2006.
(c)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).

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Eni Fact BookFinancial Data

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

Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(c) Total

2007
Revenues:
Sales to consolidated entities	3,171		3,273		3,000		4,439		296		44		229		91		14,543				14,543
Sales to third parties	163		755		4,793		693		833		961		1,112		187		9,497		176		9,673
Total revenues	3,334		4,028		7,793		5,132		1,129		1,005		1,341		278		24,040		176		24,216
Operations costs	(248	)	(584	)	(542	)	(499	)	(142	)	(39	)	(177	)	(50	)	(2,281	)	(27	)	(2,308	)
Production taxes	(188	)			(91	)	(473	)			(28	)					(780	)	(6	)	(786	)
Exploration expenses	(108	)	(196	)	(379	)	(297	)	(36	)	(168	)	(566	)	(27	)	(1,777	)	(42	)	(1,819	)
D.D.&A. and Provision for abandonment (d)	(499	)	(766	)	(768	)	(685	)	(76	)	(422	)	(511	)	(19	)	(3,746	)	(51	)	(3,797	)
Other income and (expenses)	(283	)	(83	)	(627	)	(285	)	(72	)	(134	)	(18	)	(65	)	(1,567	)	(18	)	(1,585	)
Pretax income from producing activities	2,008		2,399		5,386		2,893		803		214		69		117		13,889		32		13,921
Income taxes	(746	)	(1,447	)	(3,102	)	(1,820	)	(284	)	(93	)	(110	)	(10	)	(7,612	)	(49	)	(7,661	)
Results of operations from E&P activities (e)	1,262		952		2,284		1,073		519		121		(41	)	107		6,277		(17	)	6,260
2008
Revenues:
Sales to consolidated entities	3,956		3,892		2,622		5,013		360		39		323		66		16,271				16,271
Sales to third parties	126		160		7,286		1,471		1,025		1,335		1,599		218		13,220		265		13,485
Total revenues	4,082		4,052		9,908		6,484		1,385		1,374		1,922		284		29,491		265		29,756
Operations costs	(260	)	(521	)	(528	)	(609	)	(157	)	(68	)	(233	)	(35	)	(2,411	)	(34	)	(2,445	)
Production taxes	(195	)			(32	)	(616	)			(35	)					(878	)	(53	)	(931	)
Exploration expenses	(135	)	(228	)	(406	)	(548	)	(16	)	(232	)	(435	)	(58	)	(2,058	)	(48	)	(2,106	)
D.D.&A. and Provision for abandonment (d)	(551	)	(829	)	(1,120	)	(1,115	)	(79	)	(823	)	(837	)	(35	)	(5,389	)	(84	)	(5,473	)
Other income and (expenses)	(420	)	(56	)	(934	)	(268	)	(270	)	(259	)	(6	)	(41	)	(2,254	)	(15	)	(2,269	)
Pretax income from producing activities	2,521		2,418		6,888		3,328		863		(43	)	411		115		16,501		31		16,532
Income taxes	(924	)	(1,623	)	(4,170	)	(2,262	)	(302	)	(122	)	(214	)	(70	)	(9,687	)	(49	)	(9,736	)
Results of operations from E&P activities (e)	1,597		795		2,718		1,066		561		(165	)	197		45		6,814		(18	)	6,796
2009
Revenues:
Sales to consolidated entities	2,274		2,583		1,738		4,386		245		41		808		29		12,104				12,104
Sales to third parties			540		5,037		586		739		1,208		639		181		8,930		232		9,162
Total revenues	2,274		3,123		6,775		4,972		984		1,249		1,447		210		21,034		232		21,266
Operations costs	(271	)	(517	)	(553	)	(749	)	(153	)	(78	)	(273	)	(41	)	(2,635	)	(34	)	(2,669	)
Production taxes	(148	)			(20	)	(445	)			(34	)					(647	)	(44	)	(691	)
Exploration expenses	(40	)	(114	)	(319	)	(451	)	(20	)	(204	)	(341	)	(62	)	(1,551	)	(41	)	(1,592	)
D.D.&A. and Provision for abandonment (d)	(463	)	(921	)	(956	)	(1,502	)	(78	)	(535	)	(1,108	)	(186	)	(5,749	)	(76	)	(5,825	)
Other income and (expenses)	(125	)	(134	)	(471	)	(467	)	(186	)	(17	)	170		(47	)	(1,277	)	(41	)	(1,318	)
Pretax income from producing activities	1,227		1,437		4,456		1,358		547		381		(105	)	(126	)	9,175		(4	)	9,171
Income taxes	(467	)	(833	)	(3,010	)	(1,042	)	(180	)	(67	)	(2	)	23		(5,578	)	(40	)	(5,618	)
Results of operations from E&P activities (e) (f)	760		604		1,446		316		367		314		(107	)	(103	)	3,597		(44	)	3,553

(a)	Results of operations from oil and gas producing activities, represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expense or general corporate overhead and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are computed by applying the local income tax rates to the pre-tax income from producing activities. Eni is a part to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state-owned entities, with proceeds being remitted to the state in satisfaction of Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.
(b)	Eni’s results of operations of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007.
(c)	The amounts of equity-accounted entities as at December 31, 2009 include 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(d)	Includes asset impairments amounting to euro 91 million in 2007, euro 770 million in 2008 and euro 576 million in 2009.
(e)	The "Successful Effort Method" application would have led to an increase of result of operations of euro 438 million in 2007, euro 408 million in 2008 and euro 320 million in 2009 for the consolidated companies and of euro 26 million in 2007 and any variation in 2008 and euro 26 million in 2009 for joint-ventures and affiliates.
(f)	Amounts of 2009 do not include result of operation related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

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Eni Fact BookFinancial Data

Capitalized costs ^(a) (euro million)

Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(c)

December 31, 2008
Proved mineral interests	10,772		7,852		10,116		11,368		1,663		3,939		4,737		392		50,839		813
Unproved mineral interests	32		316		638		2,267		37		1,461		2,418		43		7,212		928
Support equipment and facilities	283		24		1,205		520		51		16		43		4		2,146		14
Incomplete wells and other	1,374		249		1,006		1,443		2,631		713		632		362		8,410		267
Gross Capitalized Costs	12,461		8,441		12,965		15,598		4,382		6,129		7,830		801		68,607		2,022
Accumulated depreciation, depletion and amortization	(7,943	)	(5,327	)	(6,318	)	(7,027	)	(560	)	(3,224	)	(3,638	)	(173	)	(34,210	)	(441	)
Net Capitalized Costs (d) (e)	4,518		3,114		6,647		8,571		3,822		2,905		4,192		628		34,397		1,581
December 31, 2009
Proved mineral interests	10,079		9,472		11,122		14,011		1,723		4,566		5,750		1,338		58,061		791
Unproved mineral interests	33		305		580		1,854		36		1,518		2,144		38		6,508		443
Support equipment and facilities	273		31		1,287		585		57		17		45		4		2,299		13
Incomplete wells and other	1,028		329		1,228		934		3,481		316		600		14		7,930		358
Gross Capitalized Costs	11,413		10,137		14,217		17,384		5,297		6,417		8,539		1,394		74,798		1,605
Accumulated depreciation, depletion and amortization	(7,557	)	(6,824	)	(7,044	)	(8,424	)	(620	)	(3,679	)	(4,673	)	(379	)	(39,200	)	(485	)
Net Capitalized Costs (d) (e) (f)	3,856		3,313		7,173		8,960		4,677		2,738		3,866		1,015		35,598		1,120

(a)	Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.
(b)	Eni’s results of operations of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007.
(c)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(d)	Includes asset impairments amounting to euro 91 million in 2007, euro 770 million in 2008 and euro 576 million in 2009.
(e)	The "Successful Effort Method" application would have led to an increase of result of operations of euro 438 million in 2007, euro 408 million in 2008 and euro 320 million in 2009 for the consolidated companies and of euro 26 million in 2007 and any variation in 2008 and euro 26 million in 2009 for joint-ventures and affiliates.
(f)	Amounts of 2009 do not include result of operation related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

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Eni Fact BookFinancial Data

Costs incurred ^(a) (euro million)

Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(c)

2007
Proved property acquisitions (e)			11	451			1,395		1,857	187
Unproved property acquisitions (e)				510			1,417		1,927	1,086
Exploration (e)	104	195	373	305	36	162	980	37	2,192	42
Development (d) (e)	320	557	1,047	1,425	744	247	734	165	5,239	156
Total cost incurred	424	752	1,431	2,691	780	409	4,526	202	11,215	1,471
2008
Proved property acquisitions (e)			626	413		256			1,295
Unproved property acquisitions (e)		33	384	655		647			1,719
Exploration (e)	135	227	403	600	16	345	440	48	2,214	48
Development (d) (e)	644	957	1,388	1,884	1,023	598	748	325	7,567	163
Total cost incurred	779	1,217	2,801	3,552	1,039	1,846	1,188	373	12,795	211
2009
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	41
Development (d)	742	727	1,401	2,121	1,086	423	858	462	7,820	206
Total cost incurred	782	841	2,070	2,474	1,106	676	1,274	514	9,737	247

(a)	Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities.
(b)	Eni’s incurred costs of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007.
(c)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(d)	Includes the abandonment costs of the assets for euro 173 million in 2007, euro 628 million in 2008 and euro 301 million in 2009.
(e)	Of which business combination:

Italy Rest of Europe North Africa West Africa Kazakhstan ^(b) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(c)

2007
Proved property acquisitions			451		1,395	1,846	187
Unproved property acquisitions			510		1,334	1,844	1,086
Exploration			59		474	533
Development			10		345	355	101
Total			1,030		3,548	4,578	1,374
2008
Proved property acquisitions			298	256		554
Unproved property acquisitions	33	384	560	647		1,624
Exploration		23	115	158		296
Development	52	132	4	233		421
Total	85	539	977	1,294		2,895

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Eni Fact BookFinancial Data

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 years ended December 31, 2007 and 2008 and the average prices during the year ended December 31, 2009 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 Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

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Eni Fact BookFinancial Data

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

Italy Rest of Europe North Africa West Africa Kazakhstan ^(a) Rest of Asia America Australia and Oceania Total consolidated subsidiaries Total equity- accounted entities ^(b) Total

At December 31, 2007
Future net cash inflows	47,243		30,390		73,456		48,283		42,710		4,855		11,180		3,544		261,661		7,135		268,796
Future production costs	(5,926	)	(6,759	)	(11,754	)	(9,875	)	(4,997	)	(476	)	(1,758	)	(459	)	(42,004	)	(1,249	)	(43,253	)
Future development and abandonment costs	(7,218	)	(2,653	)	(4,643	)	(3,013	)	(3,374	)	(306	)	(1,533	)	(428	)	(23,168	)	(1,721	)	(24,889	)
Future net inflow before income tax	34,099		20,978		57,059		35,395		34,339		4,073		7,889		2,657		196,489		4,165		200,654
Future income tax	(10,778	)	(14,388	)	(29,083	)	(23,083	)	(9,977	)	(1,109	)	(3,272	)	(1,003	)	(92,693	)	(2,009	)	(94,702	)
Future net cash flows	23,321		6,590		27,976		12,312		24,362		2,964		4,617		1,654		103,796		2,156		105,952
10% discount factor	(13,262	)	(1,757	)	(11,143	)	(3,953	)	(17,480	)	(718	)	(1,568	)	(913	)	(50,794	)	(1,265	)	(52,059	)
Standardized measure of discounted future net cash flows	10,059		4,833		16,833		8,359		6,882		2,246		3,049		741		53,002		891		53,893
At December 31, 2008
Future net cash inflows	46,458		16,963		62,785		22,344		21,648		5,072		5,257		2,937		183,464		4,782		188,246
Future production costs	(5,019	)	(3,467	)	(10,673	)	(6,715	)	(6,273	)	(707	)	(1,657	)	(405	)	(34,916	)	(1,104	)	(36,020	)
Future development and abandonment costs	(6,805	)	(2,317	)	(6,153	)	(3,868	)	(4,842	)	(738	)	(1,022	)	(258	)	(26,003	)	(1,845	)	(27,848	)
Future net inflow before income tax	34,634		11,179		45,959		11,761		10,533		3,627		2,578		2,274		122,545		1,833		124,378
Future income tax	(11,329	)	(7,697	)	(27,800	)	(5,599	)	(2,745	)	(768	)	(232	)	(861	)	(57,031	)	(1,032	)	(58,063	)
Future net cash flows	23,305		3,482		18,159		6,162		7,788		2,859		2,346		1,413		65,514		801		66,315
10% discount factor	(13,884	)	(1,042	)	(8,639	)	(2,155	)	(6,230	)	(672	)	(672	)	(768	)	(34,062	)	(763	)	(34,825	)
Standardized measure of discounted future net cash flows	9,421		2,440		9,520		4,007		1,558		2,187		1,674		645		31,452		38		31,490
At December 31, 2009
Future net cash inflows	26,243		22,057		59,413		33,676		30,273		5,680		7,088		2,973		187,403		3,718		191,121
Future production costs	(4,732	)	(6,215	)	(7,771	)	(9,737	)	(6,545	)	(1,427	)	(1,797	)	(529	)	(38,753	)	(1,251	)	(40,004	)
Future development and abandonment costs	(5,143	)	(5,375	)	(8,618	)	(5,134	)	(4,345	)	(1,409	)	(1,897	)	(214	)	(32,135	)	(1,168	)	(33,303	)
Future net inflow before income tax	16,368		10,467		43,024		18,805		19,383		2,844		3,394		2,230		116,515		1,299		117,814
Future income tax	(5,263	)	(6,621	)	(24,230	)	(9,894	)	(4,827	)	(636	)	(694	)	(563	)	(52,728	)	(432	)	(53,160	)
Future net cash flows	11,105		3,846		18,794		8,911		14,556		2,208		2,700		1,667		63,787		867		64,654
10% discount factor	(5,868	)	(1,455	)	(9,160	)	(3,102	)	(10,249	)	(520	)	(1,162	)	(771	)	(32,287	)	(610	)	(32,897	)
Standardized measure of discounted future net cash flows (c)	5,237		2,391		9,634		5,809		4,307		1,688		1,538		896		31,500		257		31,757

(a)	Eni’s proved reserves of the Kashagan field are determined based on Eni share of 16.81% as at December 2008 and 2009, and 18.52% as at December 2007 and 2006.
(b)	The amounts of equity-accounted entities as at December 31, 2009 includes 29.4% of the three Russian companies former Yukos as a result of the Gazprom call option on the 51% of the shares (2007 and 2008 are reported at 60%).
(c)	Amounts of 2009 do not include standardized measure of discounted future net cash flows related to the Italian gas storage activities, following restructuring of Eni regulated gas businesses in Italy now reported in Gas & Power segment.

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Eni Fact BookFinancial Data

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

Total consolidated subsidiaries Total equity- accounted entities Total

Value at December 31, 2006	43,227		354		43,581
Increase (decrease):
- sales, net of production costs	(20,979	)	(143	)	(21,122	)
- net changes in sales and transfer price, net of production costs	34,999		153		35,152
- extensions, discoveries and improved recovery, net of future production and development costs	3,982		46		4,028
- changes in estimated future development and abandonment costs	(4,000	)	(73	)	(4,073	)
- development costs incurred during the period that reduced future development costs	4,682		56		4,738
- revision of quantity estimates	(2,995	)	527		(2,468	)
- accretion discount	7,968		50		8,018
- net change in income taxes	(17,916	)	(1,027	)	(18,943	)
- purchase of reserves in-place	3,521		929		4,450
- changes in production rates (timing) and other	513		19		532
Net increase (decrease)	9,775		537		10,312
Value at December 31, 2007	53,002		891		53,893
Increase (decrease):
- sales, net of production costs	(26,202	)	(178	)	(26,380	)
- net changes in sales and transfer price, net of production costs	(39,699	)	(1,254	)	(40,953	)
- extensions, discoveries and improved recovery, net of future production and development costs	1,110		10		1,120
- changes in estimated future development and abandonment costs	(6,222	)	(129	)	(6,351	)
- development costs incurred during the period that reduced future development costs	6,584		145		6,729
- revision of quantity estimates	5,835		(61	)	5,774
- accretion discount	10,538		201		10,739
- net change in income taxes	21,359		657		22,016
- purchase of reserves in-place	476				476
- sale of reserves in-place	25				25
- changes in production rates (timing) and other	4,646		(244	)	4,402
Net increase (decrease)	(21,550	)	(853	)	(22,403	)
Value 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 price, 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
- revision of quantity estimates	4,686		(113	)	4,573
- accretion 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
Value at December 31, 2009	31,500		257		31,757

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Quarterly information

Main financial data ^(a) (euro million)

2007 2008 2009

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 (b)	21,901		19,746		20,171		25,386		87,204		28,292		27,096		28,144		24,550		108,082		23,741		18,267		19,142		22,077		83,227
Operating income:	4,964		4,335		4,322		5,118		18,739		6,177		5,793		6,239		308		18,517		3,967		2,405		3,217		2,466		12,055
Exploration & Production (c)	2,962		3,347		3,227		3,897		13,433		4,269		4,774		5,209		1,987		16,239		2,374		1,778		2,557		2,411		9,120
Gas & Power (c)	1,697		607		622		1,539		4,465		1,735		690		687		918		4,030		1,253		863		567		1,004		3,687
Refining & Marketing	(28	)	420		268		26		686		215		561		428		(2,192	)	(988	)	240		47		34		(423	)	(102	)
Petrochemicals	137		74		6		(117	)	100		(32	)	(231	)	(89	)	(493	)	(845	)	(167	)	(287	)	(60	)	(161	)	(675	)
Engineering & Construction	185		205		211		236		837		214		253		276		302		1,045		270		310		274		27		881
Other activities	(16	)	(215	)	(51	)	(162	)	(444	)	(47	)	(94	)	(52	)	(153	)	(346	)	(55	)	(122	)	(28	)	(177	)	(382	)
Corporate and financial companies	(78	)	26		(17	)	(243	)	(312	)	(75	)	(32	)	(274	)	(362	)	(743	)	(63	)	(124	)	(134	)	(153	)	(474	)
Unrealized profit intragroup elimination	105		(129	)	56		(58	)	(26	)	(102	)	(128	)	54		301		125		115		(60	)	7		(62	)
Net income	2,588		2,267		2,146		3,010		10,011		3,321		3,437		2,941		(874	)	8,825		1,904		832		1,240		391		4,367
Capital expenditures	2,013		2,244		2,679		3,657		10,593		3,118		3,641		3,112		4,691		14,562		3,147		3,697		2,957		3,894		13,695
Investments	10		4,925		3,776		1,198		9,909		1,784		165		127		2,229		4,305		2,039		175		63		46		2,323
Net borrowings at period end	3,852		9,122		11,430		16,327		16,327		15,591		16,565		17,823		18,376		18,376		16,528		18,355		20,540		23,055		23,055

(a)	Quarterly data are unaudited.
(b)	From January 1, 2009 Eni adopted IFRIC 13 "Customer Loyalty Programmes" that requires that the award points granted to clients within the related loyalty programs be accounted as a separate component of the basic transaction, evaluated at their fair value and recognized as revenues when effectively used. Prior period results have been restated accordingly.
(c)	From January 1, 2009, results of the gas storage business, accounted for in the Exploration & Production segment until December 31, 2008, are reported within the Gas & Power segment, in the regulated businesses results, following restructuring of Eni regulated gas businesses in Italy. As of that date, the results of the regulated businesses in Italy therefore include results of the Transport, Distribution, Regasification and Storage activities in Italy. Prior period have been restated accordingly.

Key market indicator ^(a)

2007 2008 2009

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)	57.75	68.76	74.87	88.70	72.52	96.90	121.38	114.78	54.91	96.99	44.40	58.79	68.28	74.57	61.51
Average EUR/USD exchange rate	1.310	1.348	1.375	1.449	1.371	1.500	1.562	1.504	1.317	1.471	1.302	1.362	1.431	1.478	1.393
Average price in euro of Brent dated crude oil (b)	44.08	51.01	54.45	61.21	52.90	64.60	77.71	76.32	41.69	65.93	34.1	43.16	47.71	50.45	44.16
Average European refining margins (c)	3.06	6.90	4.04	4.07	4.52	3.81	8.04	6.37	7.72	6.49	5.34	3.61	2.34	1.24	3.13
Average European refining margins Brent/Ural (c)	6.07	8.43	5.19	6.12	6.45	6.04	11.25	8.51	9.61	8.85	6.28	3.90	2.26	1.80	3.56
Euribor %	3.8	4.1	4.5	4.7	4.3	4.5	4.9	5.0	4.2	4.6	2.0	1.3	0.8	0.7	1.2

(a)	In USD/barrel. Source: Platt’s Oilgram.
(b)	Eni calculation.
(c)	In US dollars per barrel FOB Mediterranean Brent crude. From 1995 lead-free gasoline. Eni elaborations on Platt’s Oilgram data.

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Main operating data

2007 2008 2009

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

Production of oil	(kbbl/d)	1,030	1,026	975	1,048	1,020	1,012	998	1,015	1,079	1,026	1,013	986	957	1,073	1,007
Production of natural gas	(bcf)	115	116	111	125	117	128	126	122	126	126	125	121	117	132	124
Production of hydrocarbons	(kboe/d)	1,734	1,736	1,659	1,815	1,736	1,796	1,772	1,764	1,854	1,797	1,779	1,733	1,678	1,886	1,769
Italy		223	215	204	207	212	206	204	196	190	199	174	169	161	173	169
Rest of Europe		296	272	222	289	270	249	262	228	255	249	256	246	230	255	247
North Africa		566	599	568	641	594	626	652	666	635	645	595	567	567	565	573
West Africa		337	333	324	316	327	325	305	352	356	335	330	343	344	421	360
Kazakhstan		114	118	104	111	112	127	113	92	113	111	119	121	106	117	115
Rest of Asia		116	116	103	97	108	114	113	108	162	124	150	138	122	130	135
America		61	62	118	138	95	134	110	100	125	117	135	133	132	209	153
Australia and Oceania		21	21	16	16	18	15	13	22	18	17	20	16	16	16	17
Production sold	(mmboe)	150.1	152.2	147.0	162.1	611.4	157.0	156.9	154.4	163.2	631.5	154.2	154.2	147.6	166.8	622.8
Sales of natural gas to third parties	(bcm)	23.41	16.31	15.49	23.54	78.75	26.66	18.99	16.78	27.26	89.69	28.34	17.54	19.45	24.63	89.96
Own consumption of natural gas	(bcm)	1.39	1.48	1.62	1.59	6.08	1.62	1.33	1.42	1.26	5.63	1.51	1.25	1.55	1.50	5.81
Sales to third parties and own consumption	(bcm)	24.80	17.79	17.11	25.13	84.83	28.28	20.32	18.20	28.52	95.32	29.85	18.79	21.00	26.13	95.77
Sales of natural gas of Eni’s affiliates (net to Eni)	(bcm)	2.27	1.77	1.96	2.74	8.74	2.63	1.84	1.97	2.47	8.91	2.50	1.67	1.52	2.26	7.95
Total sales and own consumption of natural gas	(bcm)	27.07	19.56	19.07	27.87	93.57	30.91	22.16	20.17	30.99	104.23	32.35	20.46	22.52	28.39	103.72
Volumes transported on behalf of third parties in Italy	(bcm)	7.96	7.22	6.38	9.33	30.89	9.95	8.20	6.61	9.08	33.84	9.86	8.20	7.47	11.74	37.27
Electricity sales	(TWh)	7.38	8.86	8.67	8.28	33.19	8.16	7.21	7.62	6.94	29.93	7.78	7.57	9.19	9.42	33.96
Sales of refined products:	(mmtonnes)	12.34	12.02	11.90	13.89	50.15	11.60	11.96	15.01	12.11	50.68	10.97	11.16	11.34	12.12	45.59
Retail sales in Italy		1.98	2.19	2.25	2.20	8.62	2.06	2.18	2.28	2.29	8.81	2.10	2.31	2.36	2.26	9.03
Wholesale sales in Italy		2.61	2.66	2.85	2.97	11.09	2.56	2.80	2.90	2.89	11.15	2.41	2.25	2.43	2.47	9.56
Retail sales Rest of Europe		0.70	0.78	0.82	0.88	3.17	0.79	0.82	0.84	0.77	3.22	0.69	0.76	0.80	0.74	2.99
Wholesale sales outside Italy		0.87	0.84	1.00	1.02	3.73	1.04	1.16	1.17	1.13	4.50	1.00	0.97	1.04	1.06	4.07
Other sales		5.67	5.02	4.47	6.29	21.45	4.64	4.47	7.34	5.03	21.48	4.77	4.87	4.71	5.59	19.94
Iberian Peninsula		0.51	0.53	0.51	0.53	2.08	0.51	0.53	0.48		1.52

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	Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com
	eni spa Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital stock as of December 31, 2009: euro 4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1   Publications Financial Statement pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Sustainability Report (in Italian and English) Fact Book (in Italian and English) Eni in 2009 (in English) Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 Internet Home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com ADRs/Depositary Morgan Guaranty Trust Company of New York ADR Department 60 Wall Street (36th Floor) New York, New York 10260 Tel. 212-648-3164 ADRs/Transfer agent Morgan ADR Service Center 2 Heritage Drive North Quincy, MA 02171 Tel. 617-575-4328 Design: Opera Cover: In Area - Rome - Italy Layout and supervision: Korus - Rome - Italy Printing: Marchesi Grafiche Editoriali SpA - Rome - Italy Printed on environment friendly paper: Fedrigoni Symbol Freelife Satin and Freelife Vellum

Ordinary and Extraordinary Shareholders’ Meeting Resolutions

Eni S.p.A. Ordinary and Extraordinary Shareholders’ Meeting held on April 29, 2010 resolved to: approve Eni Financial Statements at December 31, 2009, which show a net income of euro 5,060,639,549.44; allocate euro 3,249,436,231.44 of Eni 2009 net income of euro 5,060,639,549.44 left after the payment of an interim dividend of euro 0.50 per share resolved by the Board of Directors on September 10, 2009 and paid as of September 24, 2009, as follows: to pay a dividend of euro 0.50 for each share outstanding on the ex-dividend date, Eni treasury shares on that date excluded. Therefore, in consideration of the payment of the 2009 interim dividend of euro 0.50 per share, the 2009 dividend per share proposed amounts at euro 1; to the Distributable Reserve the amount left after the allotment of the dividend; pay said dividend as from May 27, 2010, being the ex-dividend date May 24, 2010; appoint the auditing firm Reconta Ernst & Young S.p.A. as Independent Auditors of Eni S.p.A. financial statements for the period 2010-2018; approve the amendments to articles 1, 4, 12, 14, 15 and 16 of the By-laws proposed by the Board of Directors. Documents available to the public Eni’s Annual Report 2009 (Italian Edition) – including the financial statements of the parent company, approved by the Shareholders’ Meeting, the consolidated financial statements, the report of the directors, the certification pursuant to article 154-bis, paragraph 5, of Legislative Decree 58/98 – the reports of the external auditors, the

report of the statutory auditors pursuant to article 153 of Legislative Decree 58/98 and the Sustainability Report 2009 are available at Eni S.p.A. Registered Office and Borsa Italiana S.p.A. (the Italian Stock Exchange: www.borsaitaliana.it). The minutes of the Shareholders’ Meeting will be available under law provisions at Eni S.p.A. Registered Office and Borsa Italiana S.p.A. (the Italian Stock Exchange: www.borsaitaliana.it). The above-mentioned documents are available also on www.eni.com and may be requested by e-mail at segreteriasocietaria.azionisti@eni.com 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 dialling the proper international code (+). Payment of Year 2009 Final Dividend Eni S.p.A. Shareholders’ Meeting resolved to pay final dividends as from May 27, 2010, coupon No. 14, being the ex-dividend date May 24, 2010. Therefore, as of this last date, Eni shares will be traded without the right to the payment of 2009 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. (the Italian Securities Register Centre) and their subsequent dematerialisation. 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 JPMorgan Chase Bank, N.A.