Edgar Filing: ENI SPA

sj0513en6k

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 6-K

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

For the month of May 2013

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

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

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

Form 20-F x Form 40-F o

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

Yes o No x

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

TABLE OF CONTENTS

Fact Book 2012

Eni in 2012

Press Release dated May 10, 2013

Ordinary Shareholders’ Meeting Resolutions

Press Release dated May 28, 2013

Press Release dated May 30, 2013

SIGNATURES

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


Eni S.p.A.

	Name: Antonio Cristodoro
	Title:	Head of Corporate Secretary's Staff Office

Date: May 31, 2013

Table of Contents
Contents

I Fact Book 2012


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

4	Eni in 2012
5	Eni’s strategy
10	Eni business model
14	Exploration & Production
42	Gas & Power
51	Refining & Marketing
61	Chemicals
65	Engineering & Construction


Tables

71	Financial Data
85	Employees
86	Supplemental oil and gas information
105	Quarterly information I

Eni Fact Book Eni

Eni is an integrated company engaged in the energy chain.
Eni’s strong presence in the gas market, our operations in LNG, our skills in the power generation and refinery activities, strengthened by world class skills in engineering and project management, allow us to catch opportunities in the market and to realize integrated projects.
In 2012 adjusted net profit was euro 7.13 billion, up by 2.7% from a year ago. It was up by 7.6% when excluding Snam’s results included in the continuing operations¹. These results were driven by an excellent performance reported by the Exploration & Production Division on the back of a recovery in Libyan production.
Net cash generated by operating activities from continuing operations amounted to euro 12.36 billion and together with the robust proceeds from divestments enabled the Company to finance capital expenditure and other investments of euro 13.33 billion and to pay dividends to Eni’s shareholders and other minorities for euro 4.38 billion, while reducing net borrowings by euro 12.52 billion. Leverage decreased to 0.25 at December 31, 2012 from 0.46 at December 31, 2011.
The Board of Directors proposed to the Shareholders’ Meeting the distribution of a dividend of euro 1.08 per share representing a 4% increase from 2011.
In 2012, Eni continued its commitment in incident prevention also by means of training programs on safety and emergency prevention. For the seventh consecutive year the injury frequency rate relating to employees and contractors decreased by 12.3% and 21.1% respectively, compared to 2011.
In 2012, the Exploration & Production Division reported adjusted net profit amounting to euro 7.43 billion (up 8.2% from 2011) driven by improved operating performance. Oil and natural gas production for the full year was 1,701 kboe/day (up 7% from 2011) sustained by the recovery of activities in Libya,

the start-up/ramp-up of fields, particularly in Russia and Australia, and higher production in Iraq. Net proved reserves at December 31, 2012 was an eight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. The organic reserves replacement ratio was 147% with a reserves life index of 11.5 years (12.3 years in 2011). All sources reserves replacement ratio was 107%.
The Gas & Power Division reported adjusted net profit of euro 473 million, almost doubled from 2011 due to the benefits associated with the renegotiations of the supply contracts and the full recovery of Libyan supplies. Worldwide gas sales, net of Galp sales, maintained their levels supported by a strong presence in the Italian residential market and presence in strategic European markets of France and Germany/Austria in addition to increasing international sales of LNG.
In a scenario weighted down by a steep fall in fuel demand in Italy, the Refining & Marketing Division managed to reduce adjusted operating loss by euro 85 million from 2011 (down euro 179 million). This result reflects the better operating performances and improved efficiency and performance of refineries. Results posted by the Marketing activity were impacted by falling demand for fuel, high competitive pressure and increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends. The average market share in Italy was 31.2%, up 0.7 percentage points from 2011.
The Engineering & Construction sector reported adjusted net profit amounting to euro 1,109 million reflecting the robust operating performance recorded mainly in the Drilling businesses, while the Engineering & Construction business reported a decline.
The Chemical sector reported a significant increase in adjusted net loss (euro 395 million, down euro 189 million) from 2011, due to a weak trend in demand for commodities reflecting the economic downturn and a fall in unit margins.

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

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Eni Fact Book Eni

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

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

Business strategies and targets

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

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

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

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Eni Fact Book Eni

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

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

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

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

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

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Eni Fact Book Eni

Main data

Key financial data ^(a)
(euro million)

2003 ^(*)

2004

2005

2006

2007

2008

2009

2010

2011

2012


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

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

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

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

Shareholders’ equity including non-controlling interest		28,318		35,540		39,217		41,199		42,867		48,510		50,051		55,728		60,393		62,713
Net borrowings		13,543		10,443		10,475		6,767		16,327		18,376		23,055		26,119		28,032		15,511
Leverage		0.48		0.29		0.27		0.16		0.38		0.38		0.46		0.47		0.46		0.25
Net capital employed		41,861		45,983		49,692		47,966		59,194		66,886		73,106		81,847		88,425		78,224
	Exploration & Production	17,340		16,770		19,109		17,783		23,826		31,362		32,455		37,646		42,024		*42,445*
	Gas & Power	15,617		19,554		20,075		19,713		21,333		9,636		11,024		12,931		12,367		*11,135*
	Snam											11,918		13,730		14,415		15,393
	Refining & Marketing	5,089		5,081		5,993		5,631		7,675		7,379		8,105		8,321		9,188		*8,876*
	Chemicals	1,821		2,076		2,018		1,953		2,228		1,915		1,774		1,978		2,252		*2,569*
	Engineering & Construction	2,119		2,403		2,844		3,399		4,313		5,022		6,566		7,610		8,217		*10,020*
	Corporate financial companies and other activities	(125	)	277		2		(95	)	294		24		(192	)	(527	)	(393	)	*3,682*
	Impact of unrealized intragroup profit elimination			(178	)	(349	)	(418	)	(475	)	(370	)	(356	)	(527	)	(623	)	*(503*	)

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

Key market indicators

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012


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

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

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Eni Fact Book Eni

Selected operating data

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Corporate^(a)
Employees at period end	(number)	76,529	71,572	71,773	72,850	75,125	71,714	71,461	73,768	72,574	77,838
of which: - women		11,155	10,326	10,620	10,841	10,977	11,611	11,955	12,161	12,542	*12,860*
of which: - outside Italy		36,678	32,691	34,036	35,818	38,634	41,971	42,633	45,967	45,516	*51,034*
Female managers	(%)	10.9	12.5	12.4	13.5	14.1	16.3	17.3	18.0	18.5	18.9
Employee injury frequency rate	(number of injuries/million of worked hours)	3.79	3.99	2.74	2.45	1.93	1.22	0.84	0.80	0.65	0.57
Contractor injury frequency rate		4.12	7.84	2.59	1.54	1.45	1.09	0.97	0.71	0.57	0.45
Fatality index	(fatal injuries per one hundred million of worked hours)	5.51	5.64	3.38	2.31	2.97	2.75	1.20	4.77	1.94	1.10
Oil spills	(barrels)	857	7,813	6,908	6,151	6,731	4,749	6,259	4,269	7,295	3,856
Oil spills due to sabotage and terrorism		n.a.	n.a.	1,810	7,014	2,608	2,286	15,288	18,695	7,657	8,384
GHG emission	(mmtonnes CO₂eq)	52.27	58.34	61.85	60.72	67.25	59.59	55.49	58.26	49.12	52.49
R&D expenditures^(b)	(euro million)	238	257	204	222	208	211	233	218	190	211

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

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

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

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

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

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

Share data

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

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

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

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Eni Fact Book Eni

Share information

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012


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

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

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

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

Data on Eni share placement

1995

1996

1997

1998

2001


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

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

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Eni Fact Book Eni business model

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

operations in a transparent manner, respecting human rights and tackling with corruption; finally our clients to whom we offer competitive and up with the times commercial choices and high quality services.

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

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

- 10 -

Eni Fact Book Eni business model

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

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

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

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

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

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

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

Safety

2008

2009

2010

2011

2012


Injury frequency rate	(number of injuries/million of worked hours)	1.14	0.92	0.75	0.60	0.49
- employees		1.22	0.84	0.80	0.65	0.57
- contractors		1.09	0.97	0.71	0.57	0.45
Fatality index	(fatal injuries/one hundred million of worked hours)	2.75	1.20	4.77	1.94	1.10
- employees		2.55	0.89	6.66	1.19	0.87
- contractors		2.85	1.40	3.55	2.38	1.23
Safety expenditure and investments	(euro thousand)	407,930	487,660	260,434	320,117	370,559
Professional illnesses reported	(number)	82	123	184	135	71
Health and hygiene expenditure and investments	(euro thousand)	66,601	78,219	55,070	78,950	48,156

Spending for the territory

(euro million)

2008

2009

2010

2011

2012


Total spending for the territory	85.9	97.7	107.2	100.9	90.6
- of which project investments	69.4	70.4	75.4	69.3	63.1
- of which short-term investments and donations	0.5	0.9	4.4	0.9	3.4
- of which association memberships fees	1.5	1.5	1.6	1.6	1.8
- of which contributions to the Eni Foundation	-	5.0	5.0	3.0	-
- of which sponsorships for the territory	11.4	16.2	17.1	22.4	18.6
- of which contributions to the Eni Enrico Mattei Foundation	3.2	3.7	3.7	3.7	3.7

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Eni Fact Book Eni business model

Employment

2008

2009

2010

2011

2012

Employees as of December 31

(number)

71,714

71,461

73,768

72,574

77,838

- men

60,103

59,506

61,607

60,032

64,978

- women

11,611

11,955

12,161

12,542

12,860

Employees abroad by type

41,971

42,633

45,967

45,516

51,034

- locals

33,233

33,483

35,835

34,801

39,668

- Italian expatriates

2,769

2,771

3,123

3,208

3,867

- International expatriates (including TCN)

5,969

6,379

7,009

7,507

7,499

Senior Managers employed

1,471

1,437

1,454

1,468

1,474

- of which women

129

141

147

152

159

Managers/Supervisors employed

12,058

12,395

12,837

12,754

13,199

- of which women

2,075

2,258

2,421

2,477

2,615

Employees

33,483

33,931

34,599

36,019

38,497

- of which women

9,063

9,171

9,040

9,394

9,777

Workers employed

24,702

23,698

24,878

22,333

24,668

- of which women

344

385

553

519

309

Local employees abroad by professional category

33,233

33,483

35,835

34,801

39,668

- of which senior managers

245

224

228

223

- of which managers/supervisors

2,900

3,138

3,461

3,476

3,798

- of which employees

14,864

15,533

16,269

17,529

19,683

- of which workers

15,224

14,588

15,877

13,568

15,964

Training hours

(thousand hours)

2,888

2,930

2,949

3,127

3,132

Procurement by geographical area 2012		Africa	Americas	Asia	Italy	Rest of Europe	Oceania

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

Local procurement 2012 by Country

% procurement on local market	Countries

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

Relations with suppliers

2008

2009

2010

2011

2012


Procurement by macro-class	(euro million)	28,375	33,084	31,187	32,586	31,811
Supplier concentration top 20	(%)	23	24	18	20	15
Suppliers used	(number)	27,956	33,447	32,601	31,878	32,621
Qualification cycles carried out during the year		15,466	21,066	32,962	26,936	31,991
Suppliers subjected to qualification procedures including screening on human rights		5,772	7,798	10,096	11,471	12,471
% procurement from suppliers subjected to qualification procedures including screening on human rights	(%)	88	87	85	90	88

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Eni Fact Book Eni business model

Relations with customers

2008

2009

2010

2011

2012


R&M Customer satisfaction
Customer satisfaction index	(likert scale)	8.14	7.93	7.84	7.74	7.90
Clients involved in the survey	(number)	22,609	10,711	30,618	30,524	30,438
G&P Customer satisfaction
Customer satisfaction index	(%)	75.3	83.7	87.4	88.6	89.8 ^(b)
Average Panel (G&P)^(a)		84.9	87.0	87.4	90.8	90.6

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

Technological innovation

2008

2009

2010

2011

2012


R&D expenditure	(euro million)	338	287	275	246	263
- R&D expenditure net of general and administrative costs		211	233	218	190	211
Tangible value generated by R&D activities^(a)		n.a.	362	540	730	1,006
Personnel employed in R&D activities (full time equivalent)	(number)	1,123	1,019	1,019	925	975
Existing patents		8,040	7,751	7,998	8,884	8,931

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

Operating efficiency

2008

2009

2010

2011

2012


Direct GHG emissions	(tonnes CO₂eq)	59,589,334	55,494,551	58,259,157	49,121,224	52,493,340
- of which CO₂ from combustion and process	(tonnes)	36,475,270	35,788,121	37,948,625	35,319,845	36,365,220
- of which CO₂ equivalents from flaring	(tonnes CO₂eq)	16,535,835	13,839,353	13,834,988	9,553,894	9,461,518
- of which CO₂ equivalents from CH₄(methane)		4,187,532	3,684,874	4,135,523	3,214,469	4,470,307
- of which CO₂ equivalents from venting		2,390,697	2,182,202	2,340,021	1,033,017	2,196,295
CO₂eq emissions/100% net operated hydrocarbon production	(tons CO₂eq/toe)	0.254	0.235	0.235	0.206	0.225
CO₂eq emissions/kWh eq (EniPower)	(kg CO₂eq/kWh eq)	0.402	0.410	0.407	0.410	0.399
CO₂eq emissions/uEDC (R&M)	(tonnes CO₂eq/kbbl/SD)	1,297	1,240	1,284	1,229	1,141
NO_x (nitrogen oxide) emissions	(tonnes NO₂eq)	112,328	110,910	106,040	97,114	115,571
SO_x (sulphur oxide) emissions	(tonnes SO₂eq)	47,160	45,985	50,085	37,943	30,137
NMVOC (Non-Methane Volatile Organic Compounds) emissions	(tonnes)	80,856	75,318	68,490	46,228	48,702
TSP (Total Suspended Particulate) emissions		4,195	3,936	3,783	3,297	3,548
Energy used/net 100% operated hydrocarbon production	(GJ/toe)	1.418	1.676	1.855	1.958	2.049
Total water withdrawals	(mmcm)	3,023.32	2,839.97	2,786.78	2,577.22	2,357.56
Total production and/or process water extracted	(mmcm)	52.93	59.67	61.15	58.16	61.17 ^(a)
- of which re-injected		14.88	23.32	27.11	25.18	20.82
Total recycled and/or reused water	(mmcm)	460.93	490.22	544.63	521.76	521.46
Total number of oil spills^(b)	(number)	382	308	330	418	771
Total volume of oil spills ^(b)	(barrels)	7,024	21,547	22,964	14,952	12,472
- of which from sabotage and terrorism		2,286	15,288	18,695	7,657	8,616
- of which from accidents		4,749	6,259	4,269	7,295	3,856
Waste from production activities	(tonnes)	1,186,618	1,078,839	1,400,488	1,309,135	1,378,351
Hazardous waste from production activities		479,828	418,120	489,108	476,552	365,668
Non-hazardous waste from production activities		706,790	660,719	911,380	832,582	1,012,683
Waste from reclamation activities to be disposed of or recovered/recycled	(tonnes)	9,199,934	10,163,403	11,020,439	13,869,509	16,294,882
Environmental expenditure and investments	(euro thousand)	947,605	1,230,503	916,201	893,421	743,183

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

- 13 -

Eni Fact Book Exploration & Production

Exploration & Production

Key performance indicators

		2008	2009	2010	2011	2012

Employees injury frequency rate	(No. of accidents per million of worked hours)	0.84	0.49	0.72	0.41	0.28
Contractors injury frequency rate		0.93	0.59	0.48	0.41	0.36
Fatality index	(No. of fatalities per 100 million of worked hours)	3.54	1.77	7.90	1.83	0.81

Net sales from operations^(a)	(euro million)	33,042	23,801	29,497	29,121	35,881
Operating profit		16,239	9,120	13,866	15,887	18,451
Adjusted operating profit		17,166	9,489	13,898	16,075	18,518
Adjusted net profit		7,862	3,881	5,609	6,865	7,425
Capital expenditure		9,281	9,486	9,690	9,435	10,307
Adjusted ROACE	(%)	29.2	12.3	16.0	17.2	17.6

Profit per boe^(b)	($/boe)	16.00	8.14	11.91	16.98	15.95
Opex per boe^(b)		5.45	5.77	6.14	7.28	7.10
Cash flow per boe^(d)		32.25	23.70	25.52	31.65	32.77
Finding & Development cost ^{(c) (d)}		28.79	28.90	19.32	18.82	17.37
Average hydrocarbons realizations^(d)		68.13	46.90	55.60	72.26	73.39

Production of hydrocarbons^{(d) (e)}	(kboe/d)	1,797	1,769	1,815	1,581	1,701
Estimated net proved reserves of hydrocarbons^{(d) (e)}	(mmboe)	6,600	6,571	6,843	7,086	7,166
Reserves life index^(d)	(years)	10.0	10.2	10.3	12.3	11.5
Organic reserves replacement ratio net of updating the natural gas conversion factor^(d)	(%)	130	93	127	143	147

Employees at year end	(units)	10,236	10,271	10,276	10,425	11,304
of which: outside Italy		6,182	6,388	6,370	6,628	*7,371*
Oil spills	(bbl)	4,738	6,259	3,820	2,930	3,093
Oil spills from sabotage and terrorism		2,286	15,288	18,695	7,657	8,384
Produced water re-injected	(%)	28	39	44	43	49
Direct GHG emissions	(mmtonnes CO₂eq)	33.21	29.73	31.20	23.59	28.46
of which: from flaring		16.54	13.84	13.83	9.55	*9.46*
Community investment	(euro million)	65	67	72	62	59

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

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

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

- 14 -

Eni Fact Book Exploration & Production

Exploration activity

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

Sustainability and portfolio developments

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

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Eni Fact Book Exploration & Production

Activity areas

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

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

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

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

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

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

n Rest of Europe

Norway
Eni has been operating in Norway since 1965. Eni’s activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea over a developed and undeveloped acreage of 8,490 square kilometers (2,676 square kilometers net to Eni). Eni’s production in Norway amounted to 126 kboe/d in 2012.
In April 2012, Eni signed with Solveig Gas Norway AS an agreement for the sale of its 1.43% interest in the Gassled JV, a network of gas pipelines and terminals for natural gas transportation. The sale was closed at the end of 2012 with a consideration amount of approximately euro 130 million.
Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

Norwegian Sea
Production Eni currently holds interests in 10 production areas. The principal producing fields are Åsgård (Eni’s interest 14.82%), Kristin (Eni’s interest 8.25%), Heidrun (Eni’s interest 5.17%), Mikkel (Eni’s interest 14.9%), Tyrihans (Eni’s interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni’s interest 30%) which in 2012 accounted for 78% of Eni’s production in Norway.
The gas produced in the area is collected at the Åsgård facilities, carried by pipeline to the Karsto treatment plant and then delivered to the Dornum terminal in Germany. Liquids recovered in the area mainly through FPSO units are sold FOB.
Development Development activities progressed to put in production discovered reserves near the Åsgård field. In particular activities are underway at the Marulk field, which is started-up in April 2012 with a yearly production of approximately 12 kboe/d (approximately 2 kboe/d net to Eni).
Exploration Eni holds interests in 33 prospecting licenses ranging from 5% to 50%, 4 of these are operated.
During the year, Eni was awarded the PL091D exploration licenses with a 7.9% interest.

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

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

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

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

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

n North Africa

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

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

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

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

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

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

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

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

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

square kilometers net to Eni). Eni’s main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni’s interest 100%) and in the Western Desert, mainly the Melehia (Eni’s interest 56%) and the Ras Qattara (Eni’s interest 75%) concessions. Gas production mainly comes from the operated or participated concession of North Port Said (Eni’s interest 100%), El Temsah (Eni’s interest 50%), Baltim (Eni’s interest 50%) and Ras el Barr (Eni’s interest 50%, non operated), located offshore the Nile Delta. In 2012, production from these large concessions accounted for approximately 94% of Eni’s production in Egypt.
Exploration and production activities in Egypt are regulated by PSAs.

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

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

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

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

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

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

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

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

Libya
Eni started operations in Libya in 1959. In 2012, Eni’s oil and gas production averaged 258 kboe/d. Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area, over a developed and undeveloped acreage of 26,635 square kilometers (13,294 square kilometers net to Eni). Onshore contract areas are: (i) Area A consisting in the former concession 82 (Eni’s interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni’s interest 50%); (iii) Area E with El Feel (Elephant) field (Eni’s interest 33.3%); and (iv) Area F with Block 118 (Eni’s interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni’s interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni’s interest 50%).
In the exploration phase, Eni is operator of four onshore blocks in the Kufra area (186/1, 2, 3 and 4) and in the contract Areas A, B and D.
Exploration and production activities in Libya are regulated by six Exploration and Production Sharing contracts (EPSA). The licenses of Eni’s assets in Libya expire in 2042 and 2047 for oil and gas properties, respectively.
In the Offshore Area D, Eni was the first IOC to restart exploration activity after revolution, with the acquisition of about 2,600 square kilometers of 3D seismic survey from February to April 2012. In addition, the onshore exploration activity was resumed in December 2012 by drilling the A1-108/4 exploration well that will reach a total depth of approximately 4,420 meters. This is the first well of an onshore exploration campaign that will continue in 2013 marking a relevant step in the full recovery of Eni’s upstream activity in the Country.

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

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

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

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

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

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

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

n Sub-Saharan Africa

Angola
Eni has been present in Angola since 1980. In 2012, Eni’s production averaged 87 kboe/d. Eni’s activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 24,841 square kilometers (6,079 square kilometers net to Eni).
The main producing blocks with Eni’s participation are: (i) Block 0 in Cabinda (Eni’s interest 9.8%) in the North of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni’s interest ranging from 12% to 15%) in the offshore of the Congo Basin; (iii) Development Areas in the former Block 14 (Eni’s interest 20%) in the deep offshore west of Block 0; and (iv) Development Areas in the former Block 15 (Eni’s interest 20%) in the deep offshore of the Congo Basin.
Eni retains interests in other non-producing concessions, particularly the Lianzi Development Area (Block 14K/A IMI Unit Area; Eni’s interest 10%), Block 35/11 (Eni operator with a 35% interest) and in Block 3/05-A (Eni’s interest 12%), onshore Cabinda North (Eni’s interest 15%) and the Open Areas of Block 2 awarded to the Gas Project (Eni’s interest 20%).

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

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

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

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

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

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

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

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

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Eni Fact Book Exploration & Production

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

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

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

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

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Eni Fact Book Exploration & Production

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

Nigeria
Eni has been present in Nigeria since 1962. In 2012, Eni’s oil and gas production averaged 154 kboe/d over a developed and undeveloped acreage of 36,286 square kilometers (7,646 square kilometers net to Eni) located mainly in the onshore and offshore of the Niger Delta.
In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OPL 245 (Eni’s interest 50%), OML 125 (Eni’s interest 85%), holding interests in OML 118 (Eni’s interest 12.5%) and in OML 119 and 116 Service Contracts.

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

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Eni Fact Book Exploration & Production

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

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

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

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

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

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

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

The LNG business in Nigeria
Eni holds a 10.4% interest in the Nigeria LNG Ltd which runs the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. The seventh unit is being engineered as it is in the planning phase. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 bcf/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount of 2,825 mmcf/d (268 mmcf/d net to Eni corresponding to approximately 49 kboe/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.
Eni holds a 17% interest in Brass LNG Ltd Co for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal, 100-kilometer west of Bonny. This plant is expected to start operating in 2017 with a production capacity of 10 mmtonnes/y of LNG corresponding to 590 bcf/y (approximately 45 net to Eni) of feed gas on two trains for twenty years. Supply to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the onshore OMLs 60 and 61.

n Kazakhstan

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

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

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Eni Fact Book Exploration & Production

through an operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The North Caspian Operating Company (NCOC) BV, participated by the seven partners of the consortium has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium: Eni has retained the responsibility for the development of Phase 1 of the project (the so-called "Experimental Program") and, when sanctioned, the onshore part of Phase 2.
On May 23, 2012 the Consortium partners and the Authority of the Republic of Kazakhstan signed an agreement to amend the sanctioned development plan at the Experimental Program of the Kashagan field (Amendment 4) which included an update to the project schedule, a revision of investment estimates and a settlement agreement of all pending claims relating to recoverable costs and other tax matters. The amendment also included a commercial framework to supply a share of the natural gas produced from Kashagan to the domestic market and an agreement whereby the international partners of the Consortium shall finance the share of project cost to be borne by the Kazakh KMG partner, in excess to the amounts sanctioned in the original budget costs (Amendment 3).
In 2012 the Experimental Program progressed at the last phase of mechanical completion while commissioning and pre-start up activities achieved an advanced stage. Production plants are planned to be handed over to the production organization and tested. Start-up and commercial production is expected by the end of the first half of 2013, as agreed with the Republic of Kazakhstan.
The Phase 1 (Experimental Program) targets an initial production

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

Karachaganak
Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating Consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture.
On June 28, 2012, the international Contracting Companies of the Final Production Sharing Agreement (FPSA) of the giant Karachaganak gas-condensate field and the Republic of Kazakhstan closed a settlement agreement of all pending claims relating to the recovery of costs incurred to develop the field and certain tax matters. The contracting companies transferred 10% of their rights and interest in the project to Kazakhstan’s KazMunaiGas for $1 billion net cash consideration ($325 million being Eni’s share). From the effective date of June 28, 2012, Eni’s interest in the Karachaganak project has been reduced to 29.25% from the 32.5% previously held. The agreement also includes the allocation of an additional 2 mmtonnes/y capacity in the Caspian Pipeline.
Production In 2012, production of the Karachaganak field averaged 239 kbbl/d of liquids (61 net to Eni) and 788 mmcf/d of natural gas (approximately 222 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. Approximately 90% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 kbbl/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining volumes of non-stabilized liquid production and associated raw gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg.
Development Phase 3 of the Karachaganak project is currently under study. The project is aimed at further developing gas and condensates reserves by means of the installation, in stages, of gas treatment plants and re-injection facilities to increase gas sales and liquids production. The development plan is currently in the phase of technical and marketing definition to be presented to the relevant Authorities.
Eni continues its commitment to support local communities by means of the construction of schools and educational facilities, water and energy systems and the implementation of free health assistance for the villages located in the nearby area of Karachaganak.

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n Rest of Asia

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

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

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

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

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

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

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

n America

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

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

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

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Eni Fact Book Exploration & Production

Gulf of Mexico
Eni holds interests in 281 exploration and production blocks in the conventional and deep-offshore in the Gulf of Mexico, of which 172 are operated by Eni.
Production The main fields operated by Eni are Allegheny, Appaloosa and Morpeth (Eni’s interest 100%), Longhorn-Leo, Devils Towers and Triton (Eni’s interest 75%) as well as Pegasus (Eni’s interest 58%). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%) and Thunderhawk (Eni’s interest 25%) fields.
Development Development activities mainly concerned: (i) drilling activities at the Allegheny, Appaloosa and Devils Towers operated fields; (ii) production optimization of the Front Runner (Eni’s interest 37.5%), Europa, Popeye (Eni’s interest 50%) and Thunderhawk fields; (iii) the start-up of drilling programs at the Hadrian South (Eni’s interest 30%) and St. Malo (Eni’s interest 1.25%) fields.
Exploration Exploration outlining activity of the Heidelberg oil discovery (Eni’s interest 12.5%) in the Gulf of Mexico yielded positive results and increased recoverable resources up to approximately 200 mmbbl. Studies are underway for a fast track development.
In March 2013, Eni was awarded five offshore blocks, located in Mississippi Canyon and Desoto Canyon.

Texas
Production Development activity progressed at the Alliance area (Eni’s interest 27.5%), in the Fort Worth basin in Texas. This area, including gas shale reserves, was acquired following a strategic partnership between Eni and Quicksilver. In particular, 12 new wells entered in production and contributed to a total production of approximately 10 kboe/d net to Eni in the year.

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

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

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Eni Fact Book Exploration & Production

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

n Australia and Oceania

Australia
Eni has been present in Australia since 2001. In 2012, Eni’s production of oil and natural gas averaged 37 kboe/d. Activities are focused on conventional and deep offshore fields over a developed and undeveloped area of 24,318 square kilometers (13,796 square kilometers net to Eni).
Eni’s main producing fields are WA-33-L (Eni’s interest 100%), JPDA 03-13 (Eni’s interest 10.99%) and JPDA 06-105 (Eni operator with a 40% interest) blocks. In the appraisal/development phase Eni retains interest in the NT/P68 (Eni’s interest 50%) and NT/P48 (Eni’s interest 32.5%) areas. Eni holds interest in 9 exploration licenses.
Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.

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

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

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

- 31 -

Eni Fact Book Exploration & Production

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

(mmboe)

(at December 31)

Italy ^(b)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan ^(c)

Rest of Asia ^(d)

America

Australia and Oceania

Total

2008

Estimated net proved hydrocarbons reserves

681

525

1,939

1,154

1,336

579

254

132

6,600

Consolidated subsidiaries

681

525

1,922

1,146

1,336

265

235

132

6,242

Equity-accounted entities

314

358

Developed

465

417

1,242

831

647

212

140

4,016

Consolidated subsidiaries

465

417

1,229

827

647

168

133

3,948

Equity-accounted entities

Undeveloped

216

108

697

323

689

367

114

2,584

Consolidated subsidiaries

216

108

693

319

689

102

2,294

Equity-accounted entities

270

290

2009

Estimated net proved hydrocarbons reserves

703

590

1,937

1,163

1,221

545

279

133

6,571

Consolidated subsidiaries

703

590

1,922

1,141

1,221

236

263

133

6,209

Equity-accounted entities

309

362

Developed

490

432

1,278

804

614

183

181

122

4,104

Consolidated subsidiaries

490

432

1,266

799

614

139

168

122

4,030

Equity-accounted entities

Undeveloped

213

158

659

359

607

362

2,467

Consolidated subsidiaries

213

158

656

342

607

2,179

Equity-accounted entities

265

288

2010

Estimated net proved hydrocarbons reserves

724

601

2,119

1,161

1,126

612

373

127

6,843

Consolidated subsidiaries

724

601

2,096

1,133

1,126

295

230

127

6,332

Equity-accounted entities

317

143

511

Developed

554

405

1,237

817

543

182

167

117

4,022

Consolidated subsidiaries

554

405

1,215

812

543

139

141

117

3,926

Equity-accounted entities

Undeveloped

170

196

882

344

583

430

206

2,821

Consolidated subsidiaries

170

196

881

321

583

156

2,406

Equity-accounted entities

274

117

415

2011

Estimated net proved hydrocarbons reserves

707

630

2,052

1,104

950

886

624

133

7,086

Consolidated subsidiaries

707

630

2,031

1,021

950

230

238

133

5,940

Equity-accounted entities

656

386

1,146

Developed

540

374

1,194

746

482

134

188

112

3,770

Consolidated subsidiaries

540

374

1,175

742

482

129

162

112

3,716

Equity-accounted entities

Undeveloped

167

256

858

358

468

752

436

3,316

Consolidated subsidiaries

167

256

856

279

468

101

2,224

Equity-accounted entities

651

360

1,092

2012

Estimated net proved hydrocarbons reserves

524

591

1,935

1,129

1,041

852

966

128

7,166

Consolidated subsidiaries

524

591

1,915

1,048

1,041

184

236

128

5,667

Equity-accounted entities

668

730

1,499

Developed

406

349

1,100

716

458

190

107

3,516

Consolidated subsidiaries

406

349

1,080

716

458

108

170

107

3,394

Equity-accounted entities

122

Undeveloped

118

242

835

413

583

662

776

3,650

Consolidated subsidiaries

118

242

835

332

583

2,273

Equity-accounted entities

586

710

1,377

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

- 32 -

Eni Fact Book Exploration & Production

Estimated net proved liquids reserves by geographic area

(mmbbl)

(at December 31)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan ^(a)

Rest of Asia ^(b)

America

Australia and Oceania

Total

2008

Estimated net proved liquids reserves

186

277

837

791

911

157

150

3,335

Consolidated subsidiaries

186

277

823

783

911

106

131

3,243

Equity-accounted entities

Developed

111

222

624

580

298

2,036

Consolidated subsidiaries

111

222

613

576

298

2,009

Equity-accounted entities

Undeveloped

213

211

613

1,299

Consolidated subsidiaries

210

207

613

1,234

Equity-accounted entities

2009

Estimated net proved liquids reserves

233

351

908

777

849

144

169

3,463

Consolidated subsidiaries

233

351

895

770

849

153

3,377

Equity-accounted entities

Developed

141

218

669

548

291

2,035

Consolidated subsidiaries

141

218

659

544

291

2,001

Equity-accounted entities

Undeveloped

133

239

229

558

1,428

Consolidated subsidiaries

133

236

226

558

1,376

Equity-accounted entities

2010

Estimated net proved liquids reserves

248

349

997

756

788

183

273

3,623

Consolidated subsidiaries

248

349

978

750

788

139

134

3,415

Equity-accounted entities

139

208

Developed

183

207

674

537

251

2,003

Consolidated subsidiaries

183

207

656

533

251

1,951

Equity-accounted entities

Undeveloped

142

323

219

537

139

186

1,620

Consolidated subsidiaries

142

322

217

537

100

1,464

Equity-accounted entities

114

156

2011

Estimated net proved liquids reserves

259

372

934

692

653

216

283

3,434

Consolidated subsidiaries

259

372

917

670

653

106

132

3,134

Equity-accounted entities

110

151

300

Developed

184

195

638

487

215

117

1,895

Consolidated subsidiaries

184

195

622

483

215

1,850

Equity-accounted entities

Undeveloped

177

296

205

438

182

166

1,539

Consolidated subsidiaries

177

295

187

438

1,284

Equity-accounted entities

110

126

255

2012

Estimated net proved liquids reserves

227

351

921

688

670

196

273

3,350

Consolidated subsidiaries

227

351

904

672

670

154

3,084

Equity-accounted entities

114

119

266

Developed

165

180

601

456

203

128

1,806

Consolidated subsidiaries

165

180

584

456

203

109

1,762

Equity-accounted entities

Undeveloped

171

320

232

467

147

145

1,544

Consolidated subsidiaries

171

320

216

467

1,322

Equity-accounted entities

106

100

222

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

i- 33 -

Eni Fact Book Exploration & Production

Estimated net proved natural gas reserves by geographic area

(bcf)

(at December 31)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan ^(b)

Rest of Asia ^(c)

America

Australia and Oceania

Total

2008

Estimated net proved natural gas reserves

2,844

1,421

6,324

2,086

2,437

2,430

600

606

18,748

Consolidated subsidiaries

2,844

1,421

6,311

2,084

2,437

911

600

606

17,214

Equity-accounted entities

1,519

1,534

Developed

2,031

1,122

3,548

1,444

2,005

657

340

221

11,368

Consolidated subsidiaries

2,031

1,122

3,537

1,443

2,005

439

340

221

11,138

Equity-accounted entities

218

230

Undeveloped

813

299

2,776

642

432

1,773

260

385

7,380

Consolidated subsidiaries

813

299

2,774

641

432

472

260

385

6,076

Equity-accounted entities

1,301

1,304

2009

Estimated net proved natural gas reserves

2,704

1,380

5,908

2,212

2,139

2,301

631

575

17,850

Consolidated subsidiaries

2,704

1,380

5,894

2,127

2,139

814

629

575

16,262

Equity-accounted entities

1,487

1,588

Developed

2,001

1,231

3,498

1,468

1,859

756

506

565

11,884

Consolidated subsidiaries

2,001

1,231

3,486

1,463

1,859

539

506

565

11,650

Equity-accounted entities

217

234

Undeveloped

703

149

2,410

744

280

1,545

125

5,966

Consolidated subsidiaries

703

149

2,408

664

280

275

123

4,612

Equity-accounted entities

1,270

1,354

2010

Estimated net proved natural gas reserves

2,644

1,401

6,231

2,245

1,874

2,391

552

544

17,882

Consolidated subsidiaries

2,644

1,401

6,207

2,127

1,874

871

530

544

16,198

Equity-accounted entities

118

1,520

1,684

Developed

2,061

1,103

3,122

1,554

1,621

774

437

539

11,211

Consolidated subsidiaries

2,061

1,103

3,100

1,550

1,621

560

431

539

10,965

Equity-accounted entities

214

246

Undeveloped

583

298

3,109

691

253

1,617

115

6,671

Consolidated subsidiaries

583

298

3,107

577

253

311

5,233

Equity-accounted entities

114

1,306

1,438

2011

Estimated net proved natural gas reserves

2,491

1,427

6,210

2,287

1,648

3,718

1,897

604

20,282

Consolidated subsidiaries

2,491

1,425

6,190

1,949

1,648

685

590

604

15,582

Equity-accounted entities

338

3,033

1,307

4,700

Developed

1,977

995

3,087

1,441

1,480

552

393

491

10,416

Consolidated subsidiaries

1,977

995

3,070

1,437

1,480

528

385

491

10,363

Equity-accounted entities

Undeveloped

514

432

3,123

846

168

3,166

1,504

113

9,866

Consolidated subsidiaries

514

430

3,120

512

168

157

205

113

5,219

Equity-accounted entities

334

3,009

1,299

4,647

2012

Estimated net proved natural gas reserves

1,633

1,317

5,574

2,414

2,038

3,605

3,804

572

20,957

Consolidated subsidiaries

1,633

1,317

5,558

2,061

2,038

562

449

572

14,190

Equity-accounted entities

353

3,043

3,355

6,767

Developed

1,325

925

2,736

1,429

1,401

774

340

459

9,389

Consolidated subsidiaries

1,325

925

2,720

1,429

1,401

372

334

459

8,965

Equity-accounted entities

402

424

Undeveloped

308

392

2,838

985

637

2,831

3,464

113

11,568

Consolidated subsidiaries

308

392

2,838

632

637

190

115

113

5,225

Equity-accounted entities

353

2,641

3,349

6,343

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

- 34 -

Eni Fact Book Exploration & Production

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

(kboe/d)

2008

2009

2010

2011

2012


Italy	199	169	183	186	189

Rest of Europe	249	247	222	216	178
Croatia	12	17	8	5	5
Norway	129	126	123	131	126
United Kingdom	108	104	91	80	47

North Africa	645	573	602	438	586
Algeria	83	83	77	72	78
Egypt	240	230	232	236	235
Libya	306	244	273	112	258
Tunisia	16	16	20	18	15

Sub-Saharan Africa	335	360	400	370	345
Angola	126	130	118	102	87
Congo	87	102	110	108	104
Nigeria	122	128	172	160	154

Kazakhstan	111	115	108	106	102

Rest of Asia	124	135	131	112	129
China	8	8	7	8	9
India		1	8	4	2
Indonesia	20	21	19	18	18
Iran	28	35	21	6	3
Iraq			5	7	18
Pakistan	56	58	59	58	57
Russia					11
Turkmenistan	12	12	12	11	11

America	117	153	143	125	135
Brazil				1	2
Ecuador	16	14	11	7	25
Trinidad & Tobago	9	12	12	10	11
United States	87	119	109	98	88
Venezuela	5	8	11	9	9

Australia and Oceania	17	17	26	28	37
Australia	17	17	26	28	37
Total outside Italy	1,598	1,600	1,632	1,395	1,512

	1,797	1,769	1,815	1,581	1,701
*of which equity-accounted entities*	20	23	25	26	35
Angola	3	3	3	4	2
Brazil				1	2
Indonesia	6	6	6	6	6
Russia					11
Tunisia	6	6	5	6	5
Venezuela	5	8	11	9	9

Oil and natural gas production sold ^(a)

(mmboe)

2008

2009

2010

2011

2012


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

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

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

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

- 35 -

Eni Fact Book Exploration & Production

Liquids production by Country

(kbbl/d)

2008

2009

2010

2011

2012


Italy	68	56	61	64	63

Rest of Europe	140	133	121	120	95
Norway	83	78	74	80	74
United Kingdom	57	55	47	40	21

North Africa	338	292	301	209	271
Algeria	80	80	74	69	71
Egypt	98	91	96	91	88
Libya	147	108	116	36	101
Tunisia	13	13	15	13	11

Sub-Saharan Africa	289	312	321	278	247
Angola	121	125	113	95	80
Congo	84	97	98	87	82
Nigeria	84	90	110	96	85

Kazakhstan	69	70	65	64	61

Rest of Asia	49	57	48	34	44
China	6	7	6	7	8
India			1
Indonesia	2	2	2	2	2
Iran	28	35	21	6	3
Iraq			5	7	18
Pakistan	1	1	1	1	1
Russia					2
Turkmenistan	12	12	12	11	10

America	63	79	71	65	83
Brazil				1	2
Ecuador	16	14	11	7	25
United States	42	57	49	48	47
Venezuela	5	8	11	9	9

Australia and Oceania	10	8	9	11	18
Australia	10	8	9	11	18
Total outside Italy	958	951	936	781	819

	1,026	1,007	997	845	882
*of which equity-accounted entities*	14	17	19	19	20
Angola	3	3	3	3	2
Brazil				1	2
Indonesia	1	1	1	1	1
Russia					2
Tunisia	5	5	4	5	4
Venezuela	5	8	11	9	9

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

(kboe/d)

2008

2009

2010

2011

2012


Italy	195	165	178	181	184
Rest of Europe	242	239	214	209	171
North Africa	627	554	582	420	561
Sub-Saharan Africa	325	349	386	354	327
Kazakhstan	108	113	104	102	98
Rest of Asia	119	130	126	106	121
America	116	150	141	124	133
Australia and Oceania	16	16	26	27	36

	1,748	1,716	1,757	1,523	1,631
*of which equity-accounted entities*	19	21	23	23	33
North Africa	5	5	5	5	5
Sub-Saharan Africa	3	3	3	3	2
Rest of Asia	6	5	5	4	15
America	5	8	10	11	11

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

- 36 -

Eni Fact Book Exploration & Production

Natural gas production by Country ^(a)

(mmcf/d)

2008

2009

2010

2011

2012


Italy	749.9	652.6	673.2	674.3	695.1

Rest of Europe	626.7	655.5	559.2	537.9	458.9
Croatia	68.7	95.5	45.3	29.9	25.4
Norway	264.8	273.7	271.6	284.0	289.6
Ukraine					0.5
United Kingdom	293.2	286.3	242.3	224.0	143.4

North Africa	1,761.6	1,614.2	1,673.2	1,271.5	1,733.5
Algeria	18.5	19.7	20.2	19.0	40.1
Egypt	818.4	793.7	755.1	800.7	805.9
Libya	907.6	780.4	871.1	423.2	863.5
Tunisia	17.1	20.4	26.8	28.6	24.0

Sub-Saharan Africa	260.7	274.3	441.5	508.0	538.7
Angola	28.1	29.3	31.9	34.7	39.2
Congo	12.7	27.3	67.9	119.1	120.5
Nigeria	219.9	217.7	341.7	354.2	379.0

Kazakhstan	244.7	259.0	237.0	231.0	221.7

Rest of Asia	426.2	444.8	463.9	430.1	468.5
China	10.9	8.2	6.7	5.0	4.4
India		3.7	36.6	19.6	10.5
Indonesia	99.7	104.8	94.4	84.3	84.9
Pakistan	315.6	328.1	326.2	321.2	310.4
Russia					52.4
Turkmenistan					5.9

America	311.5	424.7	396.0	334.0	283.5
Trinidad & Tobago	54.6	67.0	63.6	56.7	58.5
United States	256.9	357.7	332.4	277.3	225.0

Australia and Oceania	42.2	48.6	95.7	97.8	100.8
Australia	42.2	48.6	95.7	97.8	100.8
Total outside Italy	3,673.6	3,721.1	3,866.5	3,410.3	3,805.6

	4,423.5	4,373.7	4,539.7	4,084.6	4,500.7
*of which equity-accounted entities*	*35.6*	*38.3*	*35.6*	*34.0*	*88.6*
Angola	0.6	0.7	0.8	1.9	4.4
Indonesia	30.5	32.1	28.9	25.7	26.0
Russia					52.4
Tunisia	4.5	5.5	5.9	6.4	5.3
Ukraine					0.5

Natural gas production available for sale^(b)

(mmcf/d)

2008

2009

2010

2011

2012


Italy	725	630	648	648	667
Rest of Europe	588	608	517	498	421
North Africa	1,661	1,503	1,559	1,169	1,592
Sub-Saharan Africa	204	213	365	422	444
Kazakhstan	227	241	221	212	202
Rest of Asia	396	417	436	398	423
America	304	416	385	323	273
Australia and Oceania	38	46	91	93	96

	4,143	4,074	4,222	3,763	4,118
*of which equity-accounted entities*	25	29	27	24	71
North Africa	1	3	3	4	3
Rest of Asia	24	26	24	20	68

- 37 -

Eni Fact Book Exploration & Production

Average realizations

2008

2009

2010

2011

2012

Consolidated subsidiaries

Equity- accounted entities

Consolidated subsidiaries

Equity- accounted entities

Consolidated subsidiaries

Equity- accounted entities

Consolidated subsidiaries

Equity- accounted entities

Consolidated subsidiaries

Equity- accounted entities

Liquids

($/bbl)

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

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

	7.99	11.91	5.62	6.81	6.01	8.73	6.44	13.89	7.14	6.16

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

	68.21	60.50	46.90	42.82	55.59	56.10	72.20	83.15	73.65	59.25

ENI’s GROUP	2008	2009	2010	2011	2012

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

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

Net developed and undeveloped acreage

(square kilometers)

2008

2009

2010

2011

2012

Europe

30,511

31,607

29,079

26,023

27,423

Italy

20,409

22,038

19,097

16,872

17,556

Rest of Europe

10,102

9,569

9,982

9,151

9,867

Africa

249,672

158,749

152,671

137,220

142,796

North Africa

31,088

46,011

44,277

30,532

21,390

Sub-Saharan Africa

218,584

112,738

108,394

106,688

121,406

Asia

93,710

125,641

112,745

55,284

58,042

Kazakhstan

880

869

Rest of Asia

92,830

124,761

111,865

54,404

57,173

America

12,043

11,523

11,187

10,209

9,075

Australia and Oceania

29,558

20,342

15,279

25,685

13,834

Total

415,494

347,862

320,961

254,421

251,170

- 38 -

Eni Fact Book Exploration & Production

Principal oil and natural gas interests at December 31, 2012

Commencement of operations

Number of interests

Gross developed ^(a) ^(b)acreage

Net developed ^{(a) (b)}acreage

Gross undeveloped ^(a)acreage

Net undeveloped ^(a)acreage

Type of fields/acreage

Number of producing fields

Number of other fields

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

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

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

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

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

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

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

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

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

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

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

- 39 -

Eni Fact Book Exploration & Production

Capital expenditure

(euro million)

2008

2009

2010

2011

2012


Acquisition of proved and unproved properties	836	697		754	43
North Africa	626	351		57	14
Sub-Saharan Africa	210	73		697	27
Rest of Asia		94
America		179			2

Exploration	1,918	1,228	1,012	1,210	1,850
Italy	135	40	34	38	32
Rest of Europe	227	113	114	100	151
North Africa	379	317	84	128	153
Sub-Saharan Africa	485	284	406	482	1,142
Kazakhstan	16	20	6	6	3
Rest of Asia	187	159	223	156	193
America	441	243	119	60	80
Australia and Oceania	48	52	26	240	96

Development	6,429	7,478	8,578	7,357	8,304
Italy	570	689	630	720	744
Rest of Europe	598	673	863	1,596	2,008
North Africa	1,246	1,381	2,584	1,380	1,299
Sub-Saharan Africa	1,717	2,105	1,818	1,521	1,931
Kazakhstan	968	1,083	1,030	897	719
Rest of Asia	355	406	311	361	641
America	655	706	1,187	831	953
Australia and Oceania	320	435	155	51	9

Other expenditure	98	83	100	114	110

	9,281	9,486	9,690	9,435	10,307

Reserves life index^(a)

(years)

2008

2009

2010

2011

2012


Italy	9.3	11.4	10.9	10.4	7.6
Rest of Europe	5.8	6.6	7.4	8.0	9.0
North Africa	8.2	9.3	9.6	12.8	9.0
Sub-Saharan Africa	9.5	8.9	7.9	8.2	8.9
Kazakhstan	32.9	29.0	28.7	24.5	28.1
Rest of Asia	12.8	11.1	12.8	21.7	18.1
America	5.9	5.0	7.2	13.6	19.7
Australia and Oceania	21.0	21.5	13.1	12.8	9.8

	10.0	10.2	10.3	12.3	11.5

Reserves replacement ratio ^(a)

2008

2009

2010

2011

2012

(%)

organic

all sources

organic

all sources

organic

all sources

organic

all sources

organic

all sources

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

	130	135	93	96	127	125	143	142	147	107

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

- 40 -

Eni Fact Book Exploration & Production

Exploratory wells activity

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

		2010		2011		2012		2012

(units)

Productive

Dry^(b)

Productive

Dry^(b)

Productive

Dry^(b)

Gross

Net

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

Development wells activity

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

		2010		2011		2012		2012

(units)

Productive

Dry^(b)

Productive

Dry^(b)

Productive

Dry^(b)

Gross

Net

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

Productive oil and gas wells ^(c)

		2012

		Oil wells		Natural gas wells

(units)		Gross		Net		Gross		Net

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

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

- 41 -

Eni Fact Book Gas & Power

Gas & Power

Key performance indicators ^(*)

				2008		2009		2010		2011		2012

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

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

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

Employees at year end	(units)	5,312	5,147	5,072	4,795		4,752
Direct GHG emissions	(mmtonnes CO₂eq)	12.18	12.40	13.41	12.77		12.70
Customer satisfaction index (PSC) ^(d)	(%)	75.3	83.7	87.4	88.6		89.8
Water consumption/withdrawals per kWh eq produced	(cm/kW eq)	0.015	0.015	0.013	0.014		0.012

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

Performance of the year

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

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

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

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

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

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

- 42 -

Eni Fact Book Gas & Power

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

I Electricity sales of 42.58 TWh increased by 2.30 TWh from 2011, up 5.7%.

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

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

1. Marketing

1.1 Natural gas

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

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

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Eni Fact Book Gas & Power

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

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

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

Sales and market shares on the Italian gas market

(bcm)

2011

2012

Volumes sold

Market share (%)

Volumes sold

Market share (%)

% Ch. 2012
vs 2011


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

(a) Source: Italian Ministry of Economic Development.

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Eni Fact Book Gas & Power

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

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

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

Gas sales by market

(bcm)

2008

2009

2010

2011

2012

ITALY

52.87

40.04

34.29

34.68

34.78

Wholesalers

7.52

5.92

4.84

5.16

4.65

Gas release

3.28

1.30

0.68

Italian gas exchange and spot markets

1.89

2.37

4.65

5.24

7.52

Industries

9.59

7.58

6.41

7.21

6.93

Medium-sized enterprises and services

1.05

1.08

1.09

0.88

0.81

Power generation

17.69

9.68

4.04

4.31

2.55

Residential

6.22

6.30

6.39

5.67

5.89

Own consumption

5.63

5.81

6.19

6.21

6.43

INTERNATIONAL SALES

51.36

63.68

62.77

62.08

60.54

Rest of Europe

43.03

55.45

54.52

52.98

51.02

Importers in Italy

11.25

10.48

8.44

3.24

2.73

European markets

31.78

44.97

46.08

49.74

48.29

Iberian Peninsula

7.44

6.81

7.11

7.48

6.29

Germany/Austria

5.29

5.36

5.67

6.47

7.78

Benelux

4.77

15.72

15.64

13.84

10.31

Hungary

2.82

2.58

2.36

2.24

2.02

UK/Northern Europe

3.21

4.31

4.45

4.21

4.75

Turkey

4.93

4.79

3.95

6.86

7.22

France

2.66

4.91

6.09

7.01

8.36

Other

0.66

0.49

0.81

1.63

1.56

Extra European markets

2.33

2.06

2.60

6.24

6.79

E&P in Europe and in the Gulf of Mexico

6.00

6.17

5.65

2.86

2.73

WORLDWIDE GAS SALES

104.23

103.72

97.06

96.76

95.32

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Eni Fact Book Gas & Power

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

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

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

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

Spain
Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and Unión Fenosa Gas (UFG) (Eni’s interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2012, UFG gas sales in Europe amounted to 4.82 bcm (2.41 bcm Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) re-gasification plants (42.5% and 18.9%, respectively). In 2012, Eni sales in Spain amounted to 5.24 bcm representing a slight decrease from a year ago. In 2012, total sales in the region amounted to 6.29 bcm, a decrease of 1.19 bcm, or 15.9% from a year ago.

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

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

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

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Eni Fact Book Gas & Power

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

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

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

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

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

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

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

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

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Eni Fact Book Gas & Power

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

Eni owns capacity entitlements in an extensive network of international high pressure pipelines enabling the Company to import natural gas produced in Russia, Algeria, the North Sea, including the Netherlands and Norway, and Libya to Italy. The Company participates to both entities which operate the pipelines and entities which manage transport rights. A description of the main international pipelines currently participated or operated by Eni is provided below:
- the TTPC pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline. In 2009 the pipeline was upgraded by increasing compression capacity in order to enable transportation of an additional 6.5 bcm/y;
- the TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;
- the GreenStream pipeline, jointly-owned with the Libyan National Oil Company, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y (expandable to 11 bcm/y) and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system;
- Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 bcm/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

- 48 -

Eni Fact Book Gas & Power

Supply of natural gas

(bcm)

2008

2009

2010

2011

2012


Italy	8.00		6.86		7.29		7.22		7.55

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

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

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

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

Gas sales by entity

(bcm)

2008

2009

2010

2011

2012

Sales of consolidated companies

89.32

89.60

82.00

84.37

84.67

Italy (including own consumption)

52.82

40.04

34.23

34.60

34.66

Rest of Europe

35.61

48.65

46.74

45.16

44.94

Outside Europe

0.89

0.91

1.03

4.61

5.07

Sales of Eni’s affiliates (net to Eni)

8.91

7.95

9.41

9.53

7.92

Italy

0.05

0.06

0.08

0.12

Rest of Europe

7.42

6.80

7.78

7.82

6.08

Outside Europe

1.44

1.15

1.57

1.63

1.72

E&P in Europe and in the Gulf of Mexico

6.00

6.17

5.65

2.86

2.73

Worldwide gas sales

104.23

103.72

97.06

96.76

95.32

LNG sales

(bcm)

2008

2009

2010

2011

2012


G&P sales	8.4	9.8	11.2	11.8	10.5

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

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

Total LNG sales	12.0	12.9	15.0	15.7	14.6

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Eni Fact Book Gas & Power

Electricity sales

(TWh)

2008

2009

2010

2011

2012

Free market^(a)

23.37

25.07

27.84

27.25

31.84

Italian Exchange for electricity

3.82

4.70

7.13

8.67

6.1

Industrial plants

2.71

2.92

3.21

3.23

3.3

Other^{(a) (b)}

0.03

1.27

1.36

1.13

1.34

Power sales

29.93

33.96

39.54

40.28

42.58

Power generation

23.33

24.09

25.63

25.23

25.67

Trading of electricity ^(b)

6.60

9.87

13.91

15.05

16.91

(a) Network losses have been restated from the item "Other" to "Free Market".
(b) Include positive and negative imbalances.

EniPower power stations

Installed capacity as of December 31, 2012^(a)

Full installed capacity (2016) ^(b)

Effective/planned start-up

Tecnology

Fuel


Power stations	(MW)	(GW)
Brindisi	1,321	1.3	2006	CCGT	Gas
Ferrera Erbognone	1,030	1.0	2004	CCGT	Gas/syngas
Livorno	199	0.2	2000	Power Station	Gas/fuel oil
Mantova	836	0.9	2005	CCGT	Gas
Ravenna	972	1.0	2004	CCGT	Gas
Taranto	75	0.1	2000	Power Station	Gas/fuel oil
Ferrara	841	0.8	2008	CCGT	Gas
Bolgiano	30	0.1	2012	Power Station	Gas
Photovoltaic sites	4		2011-2015	Photovoltaic	Photovoltaic

	5,308	5.4

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

Power generation

2008

2009

2010

2011

2012


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

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

Installed generation capacity	(GW)	4.9	5.3	5.3	5.3	5.3

Transport infrastructure

OUTSIDE ITALY	Lines (units)	Length of main line (km)	Diameter (inch)	Transport capacity^(a) (bcm/y)	Transport capacity ^(b) (bcm/y)	Compression stations (No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370	740	48	34.0	33.2	5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of km 155	775	20/26	33.5	33.5
GreenStream (Mellitah-Gela)	1 line of km 520	520	32	8.0	8.0	1
Blue Stream (Beregovaya-Samsun)	2 lines of km 387	774	24	16.0	16.0	1

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

Capital expenditure

(euro million)

2008

2009

2010

2011

2012


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

- 50 -

Eni Fact Book Refining & Marketing

Refining & Marketing

Key performance indicators

				2008		2009		2010		2011		2012

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

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

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

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

Employees at year end	(units)	8,327		8,166		8,022		7,591		7,125
Direct GHG emissions	(mmtonnes CO₂eq)	7.74		7.29		7.76		7.23		6.03
SO_x (sulphur oxide) emissions	(ktonnes SO₂eq)	23.18		21.98		28.05		23.07		16.99
NO_x (nitrogen oxide) emissions	(ktonnes NO₂eq)	7.38		7.35		7.96		6.74		5.87
Water consumption rate (refineries)/refinery throughputs	(cm/tonnes)	36.29		35.99		28.36		30.98		25.33
Biofuels marketed	(mmtonnes)	9.90		18.15		17.79		13.26		14.83
Customer satisfaction index	(likert scale)	8.14		7.93		7.84		7.74		7.90

(a) Before elimination of intragroup sales.

Performance of the year

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

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

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

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

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

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

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Eni Fact Book Refining & Marketing

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

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

Activities

1. Refining

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

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

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

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Eni Fact Book Refining & Marketing

Eni refining system in 2012

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

Wholly-owned refineries		685	685	574	64	69	42	37	29	89	46	61	73
Italy
Sannazzaro	100	223	223	190	59	34	12		29	29		75	88
Gela	100	129	129	100	142	35		37			46	33	42
Taranto	100	120	120	120	72		30			38		66	66
Livorno	100	106	106	84	11							76	96
Porto Marghera	100	107	107	80	20					22		44	59
Partially owned refineries^(a)		874	245	193	51	167	25		99	27		79	100
Italy
Milazzo	50	248	124	80	76	45	25		32			73	113
Germany
Vohburg/Neustadt (Bayernoil)	20	215	43	41	36	49			43			92	96
Schwedt	8.33	231	19	19	42	49				27		101	104
Czech Republic
Kralupy and Litvinov (Ceská Rafinerska)	32.4	180	58	53	30	24			24			75	83
TOTAL		1,559	930	767	61	236	67	37	128	116	46	72	80

(a) Capacity of conversion plant is 100%.

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

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

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

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

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

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Eni Fact Book Refining & Marketing

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

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

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

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

2. Logistics

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

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

3. Marketing

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

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Eni Fact Book Refining & Marketing

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

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

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

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

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

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

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

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

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

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

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

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Eni Fact Book Refining & Marketing

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

4. Wholesale Business

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

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

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

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

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

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Eni Fact Book Refining & Marketing

Supply of oil

(mmtonnes)

2008

2009

2010

2011

2012


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

	29.71		32.75		30.14		27.64		26.92

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

	28.20		34.65		38.11		31.38		35.29

Total crude oil purchases	57.91		67.40		68.25		59.02		62.21

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

TOTAL PURCHASES	78.72		84.30		86.58		79.13		87.26

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

	76.68		81.70		82.97		77.12		84.88

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

Refinery capacity

2008

2009

2010

2011

2012

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

(a) Eni’s share.

Availability of refined products

(mmtonnes)

2008

2009

2010

2011

2012


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

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

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

Sales of products	28.92		26.68		27.01		26.01		23.79

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

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

Sales of products	21.76		18.91		19.79		19.01		24.54

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

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

TOTAL SALES	76.68		81.70		82.97		77.12		84.89

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Eni Fact Book Refining & Marketing

Production and sales

(mmtonnes)

2008

2009

2010

2011

2012


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

Total products	33.97	32.70	32.87	30.18	28.43

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

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

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

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

Total sales	50.68	45.59	46.80	45.02	48.33

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Eni Fact Book Refining & Marketing

Sales in Italy and outside Italy by market

(mmtonnes)

2008

2009

2010

2011

2012


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

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

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

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

Total sales	49.16	45.59	46.80	45.02	48.33

Retail and wholesale sales of refined products

(mmtonnes)

2008

2009

2010

2011

2012


Italy	19.96	18.59	18.08	17.72	16.45

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

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

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

Total	27.68	25.65	25.48	25.00	23.87

Number of service stations

(units)

2008

2009

2010

2011

2012


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

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

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

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

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Eni Fact Book Refining & Marketing

Average throughput

(kliters/No. of service stations)

2008

2009

2010

2011

2012


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

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

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

Market shares in Italy

(%)

2008

2009

2010

2011

2012


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

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

Domestic market share	31.0	29.3	29.8	29.3	30.3

Retail market shares outside Italy

(%)

2008

2009

2010

2011

2012


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

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

Capital expenditure

(euro million)

2008

2009

2010

2011

2012

Italy

850

581

633

803

781

Outside Italy

115

965

635

711

866

842

Refining, supply and logistic

630

436

446

629

622

Italy

630

436

444

626

618

Outside Italy

Marketing

298

172

246

228

220

Italy

183

118

170

168

163

Outside Italy

115

Other

965

635

711

866

842

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Eni Fact Book Chemicals

Chemicals

Key performance indicators

				2008		2009		2010		2011		2012

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

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

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

Employees at year end	(units)	6,274		6,068		5,972		5,804		5,668
Direct GHG emissions	(mmtonnes CO₂eq)	4.90		4.63		4.69		4.12		3.69
NMVOC (Non-Methane Volatile Organic Compound) emissions	(ktonnes)	3.61		3.83		4.71		4.18		4.40
SO_x emissions (sulphur oxide)	(ktonnes SO₂eq)	5.12		4.59		3.30		3.17		2.19
NO_x emissions (nitrogen oxide)	(ktonnes NO₂eq)	5.27		4.78		4.87		4.14		3.43
Recycled/reused water	(%)	79.6		81.6		82.7		81.8		81.5

(a) Before elimination of intragroup sales.

Performance of the year

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

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

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

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

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

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

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

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

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Eni Fact Book Chemicals

to the construction of a biomass power station. Versalis will manufacture materials for consumer and medical specialty markets with hypoallergenic qualities that are expected to generate higher margins. The partnership will leverage Yulex’s core competencies including crop science and bio-rubber extraction technologies, to boost Versalis’ bio-based portfolio.
The investment will include an ambitious research project to develop technologies targeting the tire industry.
With its market leading position in the elastomer industry Versalis plans to expand its leading-edge technologies in

the synthetic rubber business by including guayule rubber as a supplementary business opportunity and an increased commercial offering. In June 2012, a Memorandum of Understanding has been signed with Genomatica and Novamont to establish a technological joint venture in Italy governing a four-year research project aimed at developing a new technology for the production of butadiene from renewable feedstocks. This joint venture will also hold exclusive right for the industrial application of the research results, including licensing it to third parties.

Activities

Eni through Versalis performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies, advanced production facilities, as well as a large and efficient retail network present in 18 European Countries.
Versalis’ portfolio of proprietary technologies covers the whole field of basic petrochemicals and polymers: phenol and its derivatives, polyethylene, styrenes and elastomers as well as catalysts and specialty products.
As a producer of intermediates, all types of polyethylene and a wide range of elastomers/lattices and of the complete line of styrenic products, Versalis continues in the development of its proprietary technologies supported by the experience it gained in production and R&D. This approach favored the optimization of the design of equipment and plants, of their performance, of proprietary catalysts and other products that allowed it to achieve excellence

in all technologies in the specific business areas in order to compete in markets worldwide. A key role is played by the most innovative proprietary catalysts, such as those based on zeolites developed by Versalis as building blocks of some of its most advanced technologies and available worldwide.
The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibers and polystyrene. In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

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Eni Fact Book Chemicals

Business areas

Intermediates

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

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

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

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

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

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

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Eni Fact Book Chemicals

Product availability

(ktonnes)

2008

2009

2010

2011

2012


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

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

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

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

Revenues by geographic area

(euro million)

2008

2009

2010

2011

2012


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

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

Revenues by product

(euro million)

2008

2009

2010

2011

2012


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

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

Capital expenditure

(euro million)

2008

2009

2010

2011

2012


	212	145	251	216	172

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

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Eni Fact Book Engineering & Construction

Engineering & Construction

Key performance indicators

				2008		2009		2010		2011		2012

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

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

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

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

Direct GHG emissions	(mmtonnes CO₂eq)	1.36	1.28	1.11	1.32	1.54

(a) Before elimination of intragroup sales.

Performance of the year

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

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

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

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

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

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

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

Engineering & Construction Offshore

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

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

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Eni Fact Book Engineering & Construction

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

Engineering & Construction Onshore

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

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

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Eni Fact Book Engineering & Construction

Offshore drilling

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

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

Onshore drilling

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

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Eni Fact Book Engineering & Construction

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Eni Fact Book Engineering & Construction

Main operating data

2008

2009

2010

2011

2012


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

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

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

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

Drilling vessels

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

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

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Eni Fact Book Engineering & Construction

Construction vessels

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

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

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

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Eni Fact Book Financial Data

Profit and loss account

(euro million)

2008

2009

2010

2011

2012


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

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

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

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

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

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

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

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

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

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

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

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

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Eni Fact Book Financial Data

Summarized Group Balance Sheet

(euro million)

Dec. 31, 2008

Dec. 31, 2009

Dec. 31, 2010

Dec. 31, 2011

Dec. 31, 2012


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

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

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

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

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

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

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

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Eni Fact Book Financial Data

Summarized Group Cash Flow Statement

(euro million)

2008

2009

2010

2011

2012


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

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

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

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

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

Changes in net borrowings

(euro million)

2008

2009

2010

2011

2012


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

Net sales from operations

(euro million)

2008

2009

2010

2011

2012


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

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

Net sales to customers

(euro million)

2008

2009

2010

2011

2012


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

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Eni Fact Book Financial Data

Net sales by geographic area of destination

(euro million)

2008

2009

2010

2011

2012


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

Purchases, services and other

(euro million)

2008

2009

2010

2011

2012


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

Principal accountant fees and services

(euro thousand)

2008

2009

2010

2011

2012


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

Payroll and related costs

(euro million)

2008

2009

2010

2011

2012


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

Depreciation, depletion, amortization and impairments

(euro million)

2008

2009

2010

2011

2012


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

Operating profit by Division

(euro million)

2008

2009

2010

2011

2012


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

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Eni Fact Book Financial Data

NON-GAAP measures

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

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

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

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

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

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

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

- 75 -

Eni Fact Book Financial Data

2008

(euro million)

		`Other activities`^(a)		`Discontinued operations`

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

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

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

- 76 -

Eni Fact Book Financial Data

2009

(euro million)

		`Other activities`^(a)		`Discontinued operations`

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

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

- 77 -

Eni Fact Book Financial Data

2010

(euro million)

		`Other activities`^(a)		`Discontinued operations`

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

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

- 78 -

Eni Fact Book Financial Data

2011

(euro million)

		`Other activities`^(a)		`Discontinued operations`

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

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

- 79 -

Eni Fact Book Financial Data

2012

(euro million)

		`Other activities`^(a)		`Discontinued operations`

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

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

- 80 -

Eni Fact Book Financial Data

Breakdown of special items ^(a)

(euro million)

2008

2009

2010

2011

2012


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

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

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

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

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

(a) Including discontinued operations.

Adjusted operating profit by Division

(euro million)

2008

2009

2010

2011

2012


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

- 81 -

Eni Fact Book Financial Data

Adjusted net profit by Division

(euro million)

2008

2009

2010

2011

2012


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

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

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

Finance income (expense)

(euro million)

2008

2009

2010

2011

2012


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

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

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

Income (expense on) from investments

(euro million)

2008

2009

2010

2011

2012


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

- 82 -

Eni Fact Book Financial Data

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

(euro million)

2008

2009

2010

2011

2012


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

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

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

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

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

Capital expenditure by Division

(euro million)

2008

2009

2010

2011

2012


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

Capital expenditure by geographic area of origin

(euro million)

2008

2009

2010

2011

2012


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

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

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

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

- 83 -

Eni Fact Book Financial Data

Net borrowings

(euro million)

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

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

- 84 -

Eni Fact Book Employees

Employees

Employees at year end^(a)

(units)

2008

2009

2010

2011

2012


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

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

- 85 -

Eni Fact Book Supplemental oil and gas information

Supplemental oil and gas information

Oil and natural gas reserves

Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - oil&gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2012, the average price for the marker Brent crude oil was $111 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation¹ of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report.
In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current cost of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price

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

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

- 86 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved hydrocarbons reserves

(mmboe)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010

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

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

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

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

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

Reserves at December 31, 2010					23		28				317		143				511

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

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

- 87 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved hydrocarbons reserves

(mmboe)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2011

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

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

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

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

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

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

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

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

- 88 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved hydrocarbons reserves

(mmboe)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2012

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

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

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

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

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

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

Reserves at December 31, 2012	524		591		1,935		1,129		1,041		852		966		128		7,166
Developed	406		349		1,100		716		458		190		190		107		3,516
consolidated subsidiaries	406		349		1,080		716		458		108		170		107		3,394
equity-accounted entities					20						82		20				122
Undeveloped	118		242		835		413		583		662		776		21		3,650
consolidated subsidiaries	118		242		835		332		583		76		66		21		2,273
equity-accounted entities							81				586		710				1,377

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

- 89 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved liquids reserves

(mmbbl)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010

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

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

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

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

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

Reserves at December 31, 2010					19		6				44		139				208

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

- 90 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved liquids reserves

(mmbbl)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2011

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

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

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

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

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

Reserves at December 31, 2011					17		22				110		151				300

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

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Eni Fact Book Supplemental oil and gas information

Movements in net proved liquids reserves

(mmbbl)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2012

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

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

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

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

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

Reserves at December 31, 2012					17		16				114		119				266

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

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Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves

(bcf)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010

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

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

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

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

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

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

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

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

- 93 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves

(bcf)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2011

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

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

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

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

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

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

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

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

- 94 -

Eni Fact Book Supplemental oil and gas information

Movements in net proved natural gas reserves

(bcf)

Italy ^(a)

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2012

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

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

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

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

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

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

Reserves at December 31, 2012	1,633		1,317		5,574		2,414		2,038		3,605		3,804		572		20,957
Developed	1,325		925		2,736		1,429		1,401		774		340		459		9,389
consolidated subsidiaries	1,325		925		2,720		1,429		1,401		372		334		459		8,965
equity-accounted entities					16						402		6				424
Undeveloped	308		392		2,838		985		637		2,831		3,464		113		11,568
consolidated subsidiaries	308		392		2,838		632		637		190		115		113		5,225
equity-accounted entities							353				2,641		3,349				6,343

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

- 95 -

Eni Fact Book Supplemental oil and gas information

Results of operations from oil and gas producing activities ^(a)

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010

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

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

- 96 -

Eni Fact Book Supplemental oil and gas information

Results of operations from oil and gas producing activities

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2011

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

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

- 97 -

Eni Fact Book Supplemental oil and gas information

Results of operations from oil and gas producing activities

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2012

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

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

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Eni Fact Book Supplemental oil and gas information

Capitalized cost ^(a)

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

December 31, 2011

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

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

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

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

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

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

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

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

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

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

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

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Eni Fact Book Supplemental oil and gas information

Cost incurred ^(a)

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

2010

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

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

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

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

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Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows

Estimated future cash inflows represent the revenues that would be received from production and are determined by applying year-end the average prices during the years ended.
Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered.
The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor.
Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future

development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates.
The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - oil&gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

- 101 -

Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

December 31, 2010

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

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

December 31, 2011

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

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

- 102 -

Eni Fact Book Supplemental oil and gas information

Standardized measure of discounted future net cash flows

(euro million)

Italy

Rest of Europe

North Africa

Sub-Saharan Africa

Kazakhstan

Rest of Asia

America

Australia and Oceania

Total

December 31, 2012

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

- 103 -

Eni Fact Book Supplemental oil and gas information

Changes in standardized measure of discounted future net cash flows

(euro million)

		Consolidated subsidiaries		Equity-accounted entities		Total

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

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

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

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

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

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

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

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

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

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

- 104 -

Eni Fact Book Quarterly information

Quarterly information

Main financial data ^{(a)
(b)}

		2010		2011		2012

(euro million)

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

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

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

Key market indicators

		2010		2011		2012

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

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

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

- 105 -

Eni Fact Book Quarterly information

Main operating data

		2010		2011		2012

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

I Q

II Q

III Q

IV Q

Liquids production

(kbbl/d)

1,011

980

948

1,049

997

899

793

896

845

867

856

891

912

882

Natural gas production

(mmcf/d)

4,615

4,319

4,203

5,021

4,540

4,356

3,867

3,773

4,345

4,085

4,480

4,394

4,545

4,584

4,501

Hydrocarbons production

(kboe/d)

1,842

1,758

1,705

1,954

1,815

1,684

1,489

1,473

1,678

1,581

1,683

1,647

1,718

1,747

1,701

Italy

182

185

182

183

186

172

193

191

186

188

186

187

195

189

Rest of Europe

243

208

200

236

222

224

221

203

217

216

206

172

162

172

178

North Africa

589

583

549

688

602

505

384

367

497

438

570

569

593

610

586

Sub-Saharan Africa

402

388

407

403

400

375

356

364

381

369

335

332

387

324

345

Kazakhstan

121

107

117

108

117

106

105

106

111

106

102

Rest of Asia

122

123

125

155

131

120

104

103

121

112

111

127

128

149

129

America

159

139

128

145

143

131

122

121

128

126

119

135

166

135

Australia and Oceania

Production sold

(mmboe)

158.6

154.1

151.7

173.6

638.0

145.7

129.1

130.0

143.7

548.5

149.2

144.6

150.5

154.4

598.7

Sales of natural gas to third parties

(bcm)

26.51

15.62

14.95

24.38

81.46

27.87

17.33

14.59

21.23

81.02

26.12

16.38

16.56

21.91

80.97

Own consumption of natural gas

1.54

1.53

1.56

6.19

1.65

1.53

1.41

1.62

6.21

1.77

1.57

1.58

1.51

6.43

Sales to third parties and own consumption

28.05

17.15

16.51

25.94

87.65

29.52

18.86

16.00

22.85

87.23

27.89

17.95

18.14

23.42

87.40

Sales of natural gas of Eni's affiliates (net to Eni)

2.46

2.04

2.09

2.82

9.41

2.81

2.14

1.96

2.62

9.53

2.72

2.20

1.34

1.66

7.92

Total sales and own consumption of natural gas

30.51

19.19

18.60

28.76

97.06

32.33

21.00

17.96

25.47

96.76

30.61

20.15

19.48

25.08

95.32

Electricity sales

(TWh)

9.00

9.61

10.70

10.23

39.54

9.68

9.66

9.55

11.39

40.28

12.29

9.62

10.54

10.13

42.58

Sales of refined products

(mmtonnes)

10.87

11.77

12.01

12.15

46.80

10.34

11.03

13.16

10.49

45.02

10.01

12.73

13.25

12.34

48.33

Retail sales in Italy

2.01

2.17

2.28

2.17

8.63

1.94

2.14

2.23

2.05

8.36

1.81

1.98

2.24

1.80

7.83

Wholesale sales in Italy

2.04

2.33

2.50

2.58

9.45

2.19

2.22

2.47

2.48

9.36

2.06

2.18

2.20

2.18

8.62

Retail sales Rest of Europe

0.67

0.77

0.91

0.75

3.10

0.70

0.76

0.80

0.75

3.01

0.72

0.76

0.81

0.75

3.04

Wholesale sales Rest
of Europe

0.86

0.97

1.06

0.99

3.88

0.81

0.97

1.08

0.98

3.84

0.89

1.03

1.05

0.99

3.96

Wholesale sales outside
Europe

0.09

0.11

0.42

0.10

0.11

0.43

0.10

0.11

0.10

0.11

0.42

Other markets

5.20

5.42

5.15

5.55

21.32

4.60

4.83

6.47

4.12

20.02

4.43

6.67

6.85

6.49

24.46

- 106 -

Table of Contents
Contents


			Contents

		2	Our activities
		4	Eni at a glance
		6	The competitive environment
		8	Our strategy

			Business review

		10	n Exploration & Production
		15	n Gas & Power
"Eni in 2012" report comprises an extract of the description of the business, the management’s discussion and analysis of financial condition and results of operations and certain other Company information from Eni’s Annual Report for the year ended December 31, 2012. It does not contain sufficient information to allow as full an understanding of financial results, operating performance and business developments of Eni as "Eni 2012 Annual Report". It is not deemed to be filed or submitted with any Italian or US market or other regulatory authorities. You may obtain a copy of "Eni in 2012" and "Eni 2012 Annual Report" on request, free of charge (see the request form on Eni’s web site – eni.com – under the section "Publications"). "Eni in 2012" and "Eni 2012 Annual Report" may be downloaded from Eni’s web site under the section "Publications". Financial data presented in this report is based on consolidated financial statements prepared in accordance with the IFRS endorsed by the EU. For definitions of certain financial and operating terms see "Frequently used terms" section, on page 43. This report contains certain forward-looking statements particularly those regarding capital expenditures, development and management of oil and gas resources, dividends, buy-back, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sale growth, new markets and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future.	Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and regulations; development and use of new technologies; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. As Eni shares, in the form of ADRs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F has been filed with the US Securities and Exchange Commission in accordance with the US Securities Exchange Act of 1934. Hard copies may be obtained free of charge (see the request form on Eni’s web site – eni.com – under the section "Publications"). Eni discloses on its Annual Report on Form 20-F significant ways in which its corporate governance practices differ from those mandated for US companies under NYSE listing standards. The term "shareholder’" in this report means, unless the context otherwise requires, investors in the equity capital of Eni SpA, both direct and/or indirect. Eni shares are traded on the Italian Stock Exchange (Mercato Telematico Azionario) and on the New York Stock Exchange (NYSE) under the ticker symbol "E".	20	n Refining & Marketing
		25	n Chemicals
		27	n Engineering & Construction

			Financial review

		30	Group results for the year
		30	Trading environment
		30	2012 results
		32	Outlook for 2013
		33	Financial risk factors
		35	Financial information
		43	n Frequently used terms

		46	Directors and officers
		50	Investor information

Eni in 2012 Our activities

- 2 -

Eni in 2012 Our activities

- 3 -

Eni in 2012 Eni at a glance

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

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

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

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

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

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

- 4 -

Eni in 2012 Eni at a glance

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

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

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

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

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

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

- 5 -

Eni in 2012 The competitive environment

- 6 -

Eni in 2012 The competitive environment

- 7 -

Eni in 2012 Our strategy

Our strategy

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

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

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

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

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

and innovative segments.
In 2012 following the divestment of a significant interest in Snam and deconsolidation of the investee’s net borrowings as well as the transaction involving Eni’s interest in Galp, the Group achieved a substantial improvement in its leverage at 2012 year end down to 0.25 thanks to euro 19 billion of disposals. This renewed and strengthened balance sheet will help the Company mitigate its greater exposure to the Exploration & Production business. The increased weight of upstream activities in Eni’s portfolio will yield higher returns but also greater risks and volatility compared to the Italian regulated businesses that were divested in 2012. For these reasons, management will remain strongly focused on preserving the Company’s financial structure as well as managing the upstream risks in the foreseeable future. We intend to maintain our leverage within a target range of 0.1-0.3 at our long-term Brent price scenario of $90 a barrel flat in the next four years. This range will allow us to absorb temporary fluctuations in oil prices, the market environment and business results.
Over the next four years, we plan that net cash generated by operating activities will enable Eni to finance a large capital expenditure program amounting to euro 56.8 billion to fuel production growth. In addition we are committed to raise further euro 10 billion from completing the disposal of our residual interests in Snam and Galp and other portfolio transactions.
Given the Company’s changed business profile and improved balance sheet, management plans to distribute cash to shareholders by means of a revised dividend policy and share repurchases. The new dividend policy contemplates a progressive, growing dividend at a rate which is expected to be determined year-to-year taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at gas long-term supply contracts in the Gas & Power segment and the

delivery of efficiency gains in the downstream businesses.
The other leg of our long-term strategy will be a continuing focus on managing the upstream risks. We intend to mitigate the political risk by expanding the geographic reach of our activities and deploying the Eni cooperation model with host Countries based on the commitment to maximize the value delivered to local communities and invest in long-term initiatives that benefit our local partners (access to energy, education and health). The risk of "project delivery" will require the in-source of critical engineering and project management activities as well as careful monitoring of supply-chain programming. Finally, the operational risk relating to drilling activities will be managed by applying Eni’s rigorous procedures throughout the engineering and execution stages, leveraging on proprietary drilling technologies, internal skills and know-how, increased control of operations and specific technologies aimed at minimizing blow-out risks and responding quickly and effectively in case of emergencies.

- 8 -

Eni in 2012 Business review / Exploration & Production

Key performance indicators

		2010	2011	2012

Employees injury frequency rate	(No. of accidents per million of worked hours)	0.72	0.41	0.28
Contractors injury frequency rate		0.48	0.41	0.36
Fatality index	(No. of fatalities per 100 million of worked hours)	7.90	1.83	0.81

Net sales from operations^(a)	(euro million)	29,497	29,121	35,881
Operating profit		13,866	15,887	18,451
Adjusted operating profit		13,898	16,075	18,518
Adjusted net profit		5,609	6,865	7,425
Capital expenditure		9,690	9,435	10,307
Adjusted ROACE	(%)	16.0	17.2	17.6

Profit per boe^(b)	($/boe)	11.91	16.98	15.95
Opex per boe^(b)		6.14	7.28	7.10
Cash flow per boe^(d)		25.52	31.65	32.77
Finding & Development cost per boe ^{(c) (d)}		19.32	18.82	17.37
Average hydrocarbons realizations^(d)		55.60	72.26	73.39

Production of hydrocarbons^(d)	(kboe/d)	1,815	1,581	1,701
Estimated net proved reserves of hydrocarbons^(d)	(mmboe)	6,843	7,086	7,166
Reserves life index^(d)	(years)	10.3	12.3	11.5
Organic reserves replacement ratio^(d)	(%)	127	143	147

Employees at year end	(units)	10,276	10,425	11,304
of which: outside Italy		6,370	6,628	*7,371*
Oil spills	(bbl)	3,820	2,930	3,093
Oil spills from sabotage and terrorism		18,695	7,657	8,384
Produced water re-injected	(%)	44	43	49
Direct GHG emissions	(mmtonnes CO₂eq)	31.20	23.59	28.46
of which: from flaring		13.83	9.55	*9.46*
Community investment	(euro million)	72	62	59

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

2012 Highlights

Performance of the year
> In 2012 employees and contractors injury frequency rate declined by 31.7% and 12.2% compared to the previous year.
> Total greenhouse gas emissions increased by 20.6% due to the recovery of activities in Libya. Greenhouse gas emissions from flaring were in line with 2011 (down 0.9%).
> In 2012 the E&P Division reported a record performance with an adjusted net profit amounting to euro 7,425 million (up 8.2% from 2011) driven by an ongoing production recovery in Libya.

> Eni reported oil and natural gas production for the full year of 1,701 kboe/day (up 7% from 2011) sustained by the recovery of activities in Libya, the start-up/ramp-up of fields, particularly in Russia and Australia, and higher production in Iraq.
> Estimated net proved reserves at December 31, 2012 was an eight-year record at 7.17 bboe based on a reference Brent price of $111 per barrel. The organic reserves replacement ratio was 147% with a reserves life index of 11.5 years (12.3

years in 2011).
> Oil spills increased in the full year (up 5.6% from accidents and up 9.5% from sabotage and terrorism) due to force majeure and security issues in Nigeria.
> Capital expenditure amounted to euro 10,307 million (up 9.2% from 2011) to fuel the growth of major projects in Norway, the United States, Congo, Italy, Kazakhstan, Angola and Algeria.
> In 2012 overall R&D expenditure of the Exploration & Production Division

- 10 -

Eni in 2012 Business review / Exploration & Production

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

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

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

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

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

Strategies

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

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

& Production Division have remained basically unchanged in the years, as follows:

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

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

- 11 -

Eni in 2012 Business review / Exploration & Production

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

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

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

Maintain strong production growth

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

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

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

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

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

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

- 12 -

Eni in 2012 Business review / Exploration & Production

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

Exploration

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

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

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

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

Develop new
projects to fuel
future growth

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

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Eni in 2012 Business review / Exploration & Production

A description of our hubs is provided below.

> Oil & gas major hubs

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

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

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

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

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

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

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

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

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

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Eni in 2012 Business review / Gas & Power

Key performance indicators ^(*)

				2010		2011		2012

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

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

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

Employees at period end	(units)	5,072	4,795		4,752
Direct GHG emissions	(mmtonnes CO₂eq)	13.41	12.77		12.70
Customer satisfaction score (CSC) ^(d)	(%)	87.4	88.6		89.8
Water consumption/withdrawals per kWh eq produced	(cm/kW eq)	0.013	0.014		0.012

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

2012 Highlights

Performance of the year
> In 2012, Eni’s continuous commitment and the resources dedicated to safety allowed to improve significantly the accident frequency rate. In particular a positive trend was confirmed for employees (down 24.6% from 2011), while the rate for contractors returned to levels lower than in 2010, improving by 30% from 2011.
> In 2012, the water consumption rate of EniPower’s plants declined both in general (down 11.2% from 2011) and per kWh produced (down 13.8%).
> In 2012, adjusted net profit was euro 473 million, almost doubling the 2011 results. This reflected a better performance of the Marketing business in a context of weak demand and mounting competitive pressures. Declining selling prices were more

than offset by the benefits associated with the renegotiations of the supply contracts, certain of which with effects retroactive to 2011, and an improved supply mix following the full recovery of Libyan supplies.
> Worldwide gas sales decreased by 1.5% to 95.32 bcm due to lower European demand and competitive pressures. Sales in Italy were in line with 2011, while they declined slightly in European markets, in particular in Benelux due to competitive pressure and in the Iberian Peninsula due to the divestment of Galp.
> Electricity sales of 42.58 TWh increased by 2.30 TWh from 2011, up 5.7%.
> Capital expenditure of euro 225 million concerned essentially flexibility and upgrading of combined cycle power stations (euro 131 million) and initiatives in gas marketing (euro 81 million).

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

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

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Eni in 2012 Business review / Gas & Power

Strategies

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

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

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

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

Gas Market trends

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

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

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

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

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

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Eni in 2012 Business review / Gas & Power

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

trading capabilities would drive significant upside potential.

Gas sales:
2012 and outlook

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

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

Gas sales by market (bcm)

	2010	2011	2012

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

INTERNATIONAL SALES	62.77	62.08	60.54

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

Extra European markets	2.60	6.24	6.79

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

WORLDWIDE GAS SALES	97.06	96.76	95.32

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

Marketing strategy:
planned actions

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

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

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

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

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Eni in 2012 Business review / Gas & Power

In order to increase exposure to the retail segment, management plans to expand its customer base in Italy and outside Italy, by almost 3 million clients in the next four years to reach a total of 14 million customers by 2016, strengthening Eni’s position in this segment. Particularly in the retail market in Italy, Eni’s marketing action will focus on the combined commercial offer "luce, gas, carburanti" (electricity, gas and fuels), high standards of service, and the adoption of lean marketing procedures to facilitate customers’ tasks and optimization of commercial channels (such as agencies, remote selling, energy stores) with a strong focus on web channels. Supply In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market, Eni has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets. These contracts have been ensuring approximately 80 bcm/y of gas availability from 2010 (including the Eni Gas & Power NV portfolio of supplies and excluding Eni’s other subsidiaries and affiliates) with a residual life of approximately 16 years and a pricing mechanism that indexes the cost of gas to the price of crude oil and its derivatives (gasoil, fuel oil, etc.). In 2012, Eni’s consolidated subsidiaries supplied 86.74 bcm of natural gas, representing an increase of 3.36 bcm, or 4% from 2011. Gas volumes supplied outside Italy (79.19 bcm from consolidated companies), imported in Italy or
	sold outside Italy, represented approximately 91% of total supplies, an increase of 3.03 BCM, or 4%, from 2011, mainly reflecting higher volumes	purchased from Libya (up 4.23 BCM), almost tripled from 2011 when the GreenStream gas pipeline had been shutdown.

	LNG Eni is present in all phases of the LNG business: gas feeding, liquefaction, shipping, re-	gasification and sale through operated activities or interests in joint ventures and associates. Eni’s presence in the business is synergic with to the Company’s plans to develop its large gas

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Eni in 2012 Business review / Gas & Power

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

Power generation

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

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

International transport

Follows a description of the main international pipelines currently participated or operated by Eni.
• TTPC The pipeline, 740-kilometer long, made up of two lines that are each 370-kilometer long with a transport capacity of 33.2 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Mediterranean coast where it links with the TMPC pipeline.
• TMPC The pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the underwater Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system.
• GreenStream The pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at Eni operated fields Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y expandible to 11 bcm/y and crosses underwater in the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system.
• Eni holds a 50% interest in the Blue Stream underwater pipeline (water depth greater than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 bcm/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market.

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Eni in 2012 Business review / Refining & Marketing

Key performance indicators

				2010		2011		2012

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

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

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

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

Employees at period end	(units)	8,022		7,591		7,125
Direct GHG emissions	(mmtonnes CO₂eq)	7.76		7.23		6.03
SO_x emissions (sulphur oxide)	(ktonnes SO₂eq)	28.05		23.07		16.99
NO_x emissions (nitrogen oxide)	(ktonnes NO₂eq)	7.96		6.74		5.87
Water consumption rate (refineries)/refinery throughputs	(cm/tonnes)	28.36		30.98		25.33
Biofuels marketed	(mmtonnes)	17.79		13.26		14.83
Customer satisfaction index	(likert scale)	7.84		7.74		7.90

(a) Before elimination of intragroup sales.

2012 Highlights

Performance of the year
> The injury frequency rates decreased from 2011 (down 45% for employees and 27.7% for contractors).
> In 2012 the trend in GHG, NO_x and SO_x, emissions continued to decline, benefiting from energy saving measures and increasing use of natural gas to replace fuel oil.
> The 2012 scenario was weighted down by a steep fall in fuel demand in Italy and continued deteriorating fundamentals in the refining activity. Against this backdrop, Eni’s Refining & Marketing Division managed to reduce adjusted operating loss by euro 85 million from 2011 (down euro 179 million) due to better operating performances and improved efficiency at

our operated refineries. Results posted by the Marketing activity were impacted by falling demand, high competitive pressure and increased expenses associated with certain marketing initiatives including a special discount on prices at the pump during the summer week-ends.
> In 2012 refining throughputs were 30.01 mmtonnes, down 6.1% from 2011. In Italy, processed volumes decreased (down 7.8%) due to the anticipation of scheduled standstills in order to mitigate the negative impact of the trading environment mainly at the Taranto and Gela refineries. Outside Italy, Eni’s refining throughputs increased by 3.2% in particular in the Czech Republic.

> Retail sales in Italy of 7.83 mmtonnes decreased by 6.3% from 2011. This decline was driven by sharply lower consumption of gasoil and gasoline in Italy (down 8.3% from 2011) and increased competitive pressure. In 2012 Eni’s average retail market share was 31.2% increasing by 0.7 percentage points from 2011 benefiting from the commercial initiatives made in the third quarter of 2012.
> Retail sales in the rest of Europe of 3.04 mmtonnes improved slightly from 2011 (up 1%). Volume additions in Austria and Switzerland, reflecting successful commercial initiatives were offset by lower sales in Eastern Europe due to declining demand.

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Eni in 2012 Business review / Refining & Marketing

Strategies

Eni’s Refining & Marketing segment engages in the supply of crude oil, refining and marketing of refined products, trading and shipping of crude oil and refined products primarily in Italy and in Central-Eastern Europe. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company’s operations are fully integrated through refining, supply, trading, logistics and marketing so as to maximize cost efficiencies and effectiveness of operations.
Our Refining & Marketing business has delivered poor results in recent years driven by a weak trading environment. High purchase costs for crude feedstock and oil-linked energy expenses have squeezed refining margins as product prices have lagged behind cost increases due to sluggish demand and excess capacity. At the same time our complex processes have been suffering from narrowing spreads between sour and sweet crudes.
Over the next four years of the industrial plan, management does not expect any

meaningful improvement in the trading environment. The ongoing economic downturn is anticipated to weigh on a recovery in demand and in refining margins. On the supply side, we see that capacity rationalization is progressing as 11 refineries have shut down in Europe eliminating 1.4 mmboe/d of processing capacity and we believe that a further 15 refineries could potentially close in coming years. However, we assume that the trading environment will not get any benefits from the current rationalization process at least over the short to the medium-term. Retail and wholesale marketing activities of refined products will be affected by sluggish demand and product oversupply that is expected to trigger pricing competition.
Our priority in the Refining & Marketing segment remains to restore profitability and improve the cash generation against the backdrop of weak industry fundamentals. Our strategic guidelines are:
• to intensify cost reduction initiatives, energy saving and optimization of plant operations, in order to drive margin expansions;

• to make selective capital expenditure projects;
• to enhance profitability at our marketing operations through a number of initiatives for improving service quality and client retention and non-oil profit contribution;
• to grow selectively in target European markets and divest marginal assets.
In the four year period, management plans to implement selective capital projects for upgrading refinery complexity and modernizing the retail network for a total amount of euro 2.4 billion. Approximately euro 1.7 billion is expected to be employed to convert the Venice plant into a bio-refinery, upgrade the Company’s best refineries and improving plant efficiency and reliability. Retail activities will attract some 25% of the planned expenditure which will be mainly directed to upgrade and modernize our service stations in Italy and in selected European Countries, and to complete the network rebranding.
Based on these actions, management expects the Refining & Marketing Division to break-even by 2014, assuming the same trading environment as in 2012.

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Eni in 2012 Business review / Refining & Marketing

Refining

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

> Our assets

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

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

heavy residues topping or vacuum residues. In order to achieve full compliance with the tightest environmental standards, in the power station there is SNO_x plant to remove suphur dioxide, nitrogen oxides and particulates from flue gases. An underway refurbishment of the Gela power plant, substantially renewing pet-coke boilers, will increase profitability maximizing synergies from refining and power generation.

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

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

Logistics

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

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Eni in 2012 Business review / Refining & Marketing

Marketing

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

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

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

Co-marketing
During the summer months of 2012, Eni launched a number of co-marketing promotions implemented with important partners, such as Coop, Vodafone and Despar, mainly targeting Italian households. This has been achieved by offering

significant discounts on primary goods and services. Eni has made an important step to get closer to its customers and will continue to do so also during the second half of 2013 with other co-marketing activities with major national and international brands.

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Eni in 2012 Business review / Refining & Marketing

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

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

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

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

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

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

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Eni in 2012 Business review / Chemicals

Key performance indicators

				2010		2011		2012

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

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

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

Employees at year end	(units)	5,972		5,804		5,668
Direct GHG emissions	(mmtonnes CO₂eq)	4.69		4.12		3.69
NMVOC (Non-Methane Volatile Organic Compound) emissions	(ktonnes)	4.71		4.18		4.40
SO_x emissions (sulphur oxide)	(ktonnes SO₂eq)	3.30		3.17		2.19
NO_x emissions (nitrogen oxide)	(ktonnes NO₂eq)	4.87		4.14		3.43
Recycled/reused water	(%)	82.7		81.8		81.5

(a) Before elimination of intragroup sales.

2012 Highlights

Performance of the year
> In 2012 the employees and contractors injury frequency rates continued to follow the positive trends of previous years (down 48.3% and 63.9%, respectively).
> In 2012 emissions of greenhouse gases, NO_xand SO_x decreased due to energy saving.
> In 2012 the sector reported sharply higher operating losses at euro 395 million (down euro 189 million from 2011), due to weak trends in demand reflecting the economic downturn and falling unit margins.
> Sales of petrochemical products were 3,953 ktonnes, down 87 ktonnes, or 2.1% from 2011, due to declining consumption.
> Petrochemical production volumes were 6,090 ktonnes, decreasing by 155 ktonnes, down 2.48%, due a steep decline in demand for petrochemical products in all businesses, in particular the steepest decline was reported in polyethylene.

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

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

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

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

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Eni in 2012 Business review / Chemicals

Strategies

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

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

Business areas

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

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

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

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

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

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

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

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

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Eni in 2012 Business review / Engineering & Construction

Key performance indicators

				2010		2011		2012

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

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

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

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

(a) Before elimination of intragroup sales.

2012 Highlights

Performance of the year
> The percentage of manager positions covered by local personnel is higher than 40% of total managerial positions, except for France and Italy, reflecting however fluctuations due to he opening of new yards and short-term projects.
> The overall amount of procurement was euro 9,584 million, of which euro 7,802 million related to operating projects, 51.8% of which was procured with local suppliers.
> In 2012 the employees injury frequency rate worsened from 2011 (by 22.7%) while it improved for contractors by 19%. Saipem continues to strive to mitigate and reduce

accidents and injuries to its employees and contractors by means of training and awareness campaigns, such as the "Working at height", the dedicated HSE training portal and training courses for crane operators.
> Safety and environment expenditure increased by 24% from 2011 (from euro 83 million to euro 103 million).
> In 2012 the Engineering & Construction sector reported adjusted net profit amounting to euro 1,109 million, in line with 2011 (up 1%). This result reflects the good operating performance recorded mainly in the Drilling businesses deriving from the full operations of Scarabeo 9 and to greater profitability

from the Saipem 10000 vessel, almost totally offset by the decline in performance of the Engineering & Construction business due to falling demand for oilfield services and lower margins at certain works related to the general downturn especially in the second half of the year.
> Capital expenditure amounted to euro 1,011 million (euro 1,090 million in 2011) and mainly regarded the upgrading of the drilling and construction fleet.
> In 2012 overall expenditure in R&D amounted approximately to euro 15 million in line with 2011. A total of 13 new patent applications were filed.

Strategies

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

markets Saipem boasts a strong competitive position, particularly in executing large, complex EPC contracts for the construction of offshore and onshore facilities and systems to develop hydrocarbons reserves as well as LNG, refining and petrochemicals plants, pipeline laying and offshore and onshore drilling services. The Company

owes its market position to technological and operational skills which we believe are acknowledged in the marketplace due to its capabilities to operate in frontier areas and complex ecosystems, efficiently and effectively managing large projects, engineering competencies and availability of technologically-advanced vessels and rigs

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Eni in 2012 Business review / Engineering & Construction

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

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

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

kilometers inland in the Russian Republic of Kalmyk.

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

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

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

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

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

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

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

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

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Eni in 2012 Group results for the year

Group results for the year

Trading
environment

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

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

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

2012 results

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

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

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

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Eni in 2012 Group results for the year

Results for the year (euro million)

2010

2011

2012

Change

% Ch.

6,252

Net profit attributable to Eni’s shareholders - continuing operations

6,902

4,198

(2,704

)

(39.2

)

(610

)

Exclusion of inventory holding (gains) losses

(724

)

(23

)

1,128

Exclusion of special items

760

2,953

of which:

(246

)

- non-recurring items

1,374

- other special items

691

2,953

6,770

Adjusted net profit attributable to Eni’s shareholders - continuing operations ^(a)

6,938

7,128

190

2.7

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

Special charges in operating profit from continuing operations of euro 4,744 million mainly related to:
(i) impairment losses of euro 4,029 million relating to goodwill and other tangible and intangible assets in the gas marketing and the refining businesses. In performing the impairment review, management assumed a reduced profitability outlook in those businesses driven by a deteriorating European macroeconomic environment, volatility in commodity prices and margins, and rising competitive pressures. Other impairment losses were incurred at a number of oil&gas properties in the Exploration & Production Division reflecting downward reserve revisions and a changed pricing environment, as well as marginal lines of business in the Chemical segment due to lack of profitability perspectives;

(ii) extraordinary expenses and risk provisions of euro 945 million incurred in connection with price revisions at long-term gas purchase contracts which were presented as special items given the contractual time span for price revisions expired in previous periods and relating to gas volumes purchased in previous reporting periods, including the one related to the settlement of an arbitration proceeding with GasTerra;
(iii) a gain on the divestment of a 10% interest in the Karachaganak project to the Kazakh partner KazMunaiGas as part of the settlement agreement (euro 343 million).

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

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

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

Adjusted net profit by Division (euro million)

2010

2011

2012

Change

% Ch.

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

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

> Capital expenditure
In 2012, capital expenditure of continuing operations amounted to euro 12,761 million, mainly relating to:
• development activities deployed mainly in Norway, the United States, Congo,

Italy, Kazakhstan, Angola and Algeria, and exploratory activities of which 98% was spent outside Italy, primarily in Mozambique, Liberia, Ghana, Indonesia, Nigeria, Angola and Australia;
• upgrading of the Engineering & Construction

fleet of vessels and rigs (euro 1,011 million);
• projects designed to improve the conversion rate and flexibility of refineries (euro 622 million), in particular at the Sannazzaro refinery, as well as upgrading and rebranding of the refined product retail network (euro 220 million).

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Eni in 2012 Group results for the year

Capital expenditure by Division (euro million)

2010

2011

2012

Change

% Ch.

9,690		Exploration & Production	9,435		10,307	872		9.2
265		Gas & Power	192		225	33		17.2
711		Refining & Marketing	866		842	(24	)	(2.8	)
251		Chemicals	216		172	(44	)	(20.4	)
1,552		Engineering & Construction	1,090		1,011	(79	)	(7.2	)
22		Other activities	10		14	4		..
109		Corporate and financial companies	128		152	24		18.8
(150	)	Impact of unrealized intragroup profit elimination	(28	)	38	66
12,450		Capital expenditure - continuing operations	11,909		12,761	852		7.2
1,420		Capital expenditure - discontinued operations	1,529		756	(773	)	(50.6	)
13,870		Capital expenditure	13,438		13,517	79		0.6

> Sources and uses of cash
The Company’s cash requirements for capital expenditure, dividends to shareholders, and working capital were financed by a combination of funds generated from operations, borrowings and divestments.

Net cash provided by operating activities of continuing operations (euro 12,356 million) and proceeds from disposals of euro 6,014 million funded cash outflows relating to capital expenditure totaling euro 12,761 million and investments (euro 569 million) relating to the acquisition of Nuon in Belgium and joint venture projects, as well as dividend payments amounting to euro 4,379 million (of which euro 1,956 million relating to the 2012 interim dividend and euro 1,884 million to the balance dividend for fiscal year 2011 to Eni’s shareholders and the remaining part related to other dividend payments to non-controlling interests). Disposals of assets mainly regarded the divestment of a 30% interest less one share in Snam to Cassa Depositi e Prestiti (euro 3,517 million), two tranches of the interest in Galp for an overall amount of euro 963 million (a 5% interest sold to Amorim BV and a 4% sold through an accelerated book-building procedure), a 10% interest in the Karachaganak field (approximately euro 500 million) and other non-strategic assets in the Exploration & Production Division (euro 695 million). The proceeds on the divestment of a 5% interest in Snam before loss of control to institutional investors (euro 612 million) were recognized as an equity transaction.

> Capital structure and ratios
Following the divestment of a significant interest in Snam and deconsolidation of the investee’s net borrowings as well as the transaction involving Eni’s interest in Galp, the Group achieved a substantial improvement in its leverage at 2012 year end down to 0.25. Management believes

that this improved financial position is consistent with the Company’s new business profile, which features greater exposure to the Exploration & Production segment. For planning purposes, management projected the Company’s expected cash flows assuming a scenario of Brent prices at 90 $/bbl for the years 2013-2016 to assess the financial compatibility of its capital expenditure programs and dividend policy with internal targets of ratio of total equity to net borrowing. Under that assumption, in 2013, the ratio of net borrowings to total equity is projected to be substantially in line with the level achieved at the end of 2012, due to cash flows from operations and portfolio management. Going forward, management currently expects to maintain this ratio within a target range of 0.1-0.3. This range will allow us to absorb temporary fluctuations in oil prices, the market environment and business results. The projected future cash flows from operations are estimated to fully fund capital expenditure plans. Furthermore management expects to deliver more than euro 10 billion of additional cash flows from asset disposal, mainly the divestment of the residual interest of Eni in Snam and Galp, the announced divestment of the 28.57% interest in Eni East Africa and other marginal assets in the Exploration & Production segment. Our cash flow projections are based on our Brent scenario of 90 $/bbl flat in the next four years. We note that Brent price in the period January 1 to March 28, 2013 was 112.60 $/bbl on average. We estimated that our cash flow from operations may improve by around euro 120 million for each dollar increase in Brent prices on a yearly basis.

> Returning cash to shareholders
Management plans to pay a dividend of euro 1.08 a share for fiscal year 2012 subject to approval from the General Shareholders’ Meeting scheduled for May 10, 2013. Of this, euro 0.54 per share was paid in September 2012

as an interim dividend with the balance of euro 0.54 per share expected to be paid in late May 2013. The dividend for fiscal year 2012 represents an increase of 4% compared to the 2011 dividend.
Management has adopted a new dividend policy which contemplates a progressive, growing dividend at a rate which is expected to be determined year-to-year taking into account Eni’s underlying earnings and cash flow growth as well as capital expenditure requirements and the targeted financial structure. Management will also evaluate the achievement of the targeted production levels in the Exploration & Production segment, the status of renegotiations at long-term gas supply contracts in the Gas & Power segment and the delivery on efficiency gains in the downstream businesses.
Management also plans to return cash to shareholders by means of a new flexible buy-back program, which has been authorized by the Shareholders’ Meeting for a total amount of euro 6 billion. The buy-back will be activated at management’s sole discretion and when a number of conditions are met. These include, but are not limited to, a level of leverage which management assesses to be sound enough given market conditions and well within our target range limit of 0.3, and full funding of capital expenditure requirements and dividends throughout the plan period. In 2013, management would consider the activation of the buyback program, provided oil prices remain at current levels and Eni makes good progress on its business and cash flow targets.

Outlook for 2013

Management expects an uncertain macroeconomic outlook in 2013, particularly in the Euro-zone where businesses and households are cautious about investments

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Eni in 2012 Group results for the year

and consumption decisions. We expect that a number of factors will support the price of crude oil including ongoing geopolitical risks as well as an improved balance between world demand and supplies of crude oil. For investment evaluation purposes and short-term financial projections, Eni assumes a full-year average price of $90 a barrel for the Brent crude benchmark. Management expects continuing weak conditions in the European gas, refining and marketing of fuels and chemical sectors. Demand for energy commodities is anticipated to remain sluggish due to the ongoing economic stagnation; unit margins are exposed to competitive pressures and the risk of new increases in the costs of oil-based raw materials in an extremely volatile environment. In this scenario, the recovery of profitability in the Gas & Power, Refining & Marketing and Chemical segments will depend greatly on management actions to optimize operations and improve the cost position.
Management expects that year-on-year comparability of results from continuing operations in 2013 will be affected by the fact that in 2012 Snam margins on intra-group transactions relating to the supply of gas transport and other services have been eliminated upon consolidation, while in 2013 those transactions will be accounted as third-party transactions, thus affecting the Group operating costs and profits.

Financial risk factors

> Market risk and sensitivity
> to market environment
Market risk is the possibility that the exposure to fluctuations in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the euro/$ exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil and gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity. The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and chemical operations depends upon the speed

at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the euro/$ exchange rate as commodities are generally priced internationally in US dollars or linked to dollar denominated products as in the case of gas prices. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa.
As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, trading activities and risk management and optimization activities as well as, from time to time, to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil and gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives. Due to a changed competitive environment in the European gas market and also considering the development of highly liquid spot markets for gas and volatile gas margins, management has implemented through 2011 new risk management policies and instruments to safeguard the value of the Company’s assets in the gas value chain and to seek to profit from market and trading opportunities. As part of its risk management strategy, the Company actively manages exposure to the commodity risk by entering into commodity derivatives transactions on both financial and physical trading venues targeting different objectives.
(i) On one hand, management enters commodity derivative transactions to hedge the risk of variability in future cash flows on already contracted or highly probable future sales exposed to commodity risk depending on the circumstance that costs of supplies may be indexed to different market and oil benchmarks compared to the indexing of selling prices. Management has been implementing tight correlation between such commodity derivatives transactions and underlying physical contracts in order to account for those derivatives in accordance with hedging accounting in compliance with IAS 39, where possible; and (ii) on the other hand, management

enters purchase/sale commodity contracts for speculative purposes in order to alter the risk profile associated with a portfolio of assets (purchase contracts, transport entitlements, storage capacity) or leverage any price differences in the marketplace, seeking to increase margins on existing assets in case of favorable trends in the commodity pricing environment or seeking a potential profit based on expectations of future trends in prices. These contracts may lead to gains as well as losses, which, in each case, may be significant. Those derivatives will be accounted through profit and loss, resulting in higher volatility in the gas business operating profit. These trading activities are executed within limits set by internal policies and guidelines that define the maximum tolerable level of market risk. Furthermore the Company intends to optimize the value of its assets (gas supply contracts, storage sites, transportation rights, customer base, and market position) by effectively managing the flexibilities associated with them. This can be achieved through strategies of asset-backed trading where the underlying items are represented by the Company’s assets. We believe that the risk associated with asset backed trading activities is mitigated by the natural hedge granted by the assets availability. In 2012, Eni’s risk management activities helped reduce the Group exposure to the commodity risk. Furthermore trading activities including asset-backed activities reported a positive contribution to the Group results of operations. We are planning to expand those trading activities both in the Gas & Power and the Refining & Marketing businesses. In fact, in 2012 the Company started a reorganization to integrate the supply activities of the Gas & Power and Refining & Marketing segments together with our trading, risk management and the wholesale activities of gas and LNG. This integration will allow us to capture opportunities from market trends and synergies in commodity risk management.

> Liquidity and counterparty risks
Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term finance requirements and to settle obligations.
Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing

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Eni in 2012 Group results for the year

expenses to meet its obligations or, under the worst conditions, the inability of the Company to continue as a going concern. As part of its financial planning process, Eni manages the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt. The Group capital structure is set according to the Company’s industrial targets and within the limits established by the Company’s Board of Directors who are responsible for prescribing the maximum ratio of debt to total equity and minimum ratio of medium and long-term debt to total debt as well as fixed rate medium and long-term debt to total medium and long-term debt. In spite of ongoing tough credit market conditions resulting in higher spreads to borrowers, the Company has succeeded in maintaining access to a wide range of funding at competitive rates through the capital markets and banks.

The actions implemented as part of Eni’s 2012 financial planning have enabled the Group to maintain access to the credit market particularly via the issue of commercial paper also targeting to increase the flexibility of funding facilities. The minimization of liquidity risks is a strategic driver of the next four-year financial plan. In particular in 2012, Eni issued three bonds addressed to institutional investors for a total amount of euro 1.82 billion, all at fixed rate with maturity of approximately 8 years. In November, as part of the divestment process of its interest in Galp, Eni also issued a convertible bond with underlying Galp shares equal to 8% of the share capital of the investee for a total amount of euro 1.03 billion at fixed rate with a maturity of three years.
Eni’s financial policies are designed to achieve the following targets: (i) ensuring adequate funds to cover short-term obligations and reimbursement of long-term debt due; (ii) maintaining an adequate level of financial flexibility to support Eni’s development plans; (iii) attaining a balance between duration and composition of the finance debt; and (iv) maintaining a cash reserve following the great flow of liquidity achieved from the divestments of 2012, particularly the disposal of Snam. The cash reserve will be commeasured in order to: (i) reduce the refinancing with maturity of one

year, allowing the Company to be financially independent also in case of negative trends in the trading environment; (ii) increase the level of liquidity to face possible extraordinary needs; and (iii) increase the flexibility of the Company’s financial structure considering lingering uncertainties in the credit markets, in a similar way as the policies adopted by the peer group companies and with a view of improving the Company’s financial rating assessment. Cash stock will be available only for short-term operations with a very low risk profile.

At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing requirements.
At December 31, 2012, Eni maintained short-term committed and uncommitted unused borrowing facilities of euro 12,173 million, of which euro 1,241 million were committed, and long-term committed borrowing facilities of euro 6,928 million which were completely undrawn at the balance sheet date. These facilities bore interest rates that reflected prevailing market conditions. Fees charged for unused facilities were immaterial.

Eni has in place a program for the issuance of Euro Medium Term Notes up to euro 15 billion, of which about euro 12.3 billion were drawn as of December 31, 2012. The Group has credit ratings of A and A-1, respectively, for long and short-term debt assigned by Standard & Poor’s and A3 and P-2 assigned by Moody’s; the outlook is negative in both ratings.
Eni’s credit ratings are potentially exposed to the risk of further downgrading of the sovereign credit rating of Italy in addition to a possible deterioration in the global macroeconomic outlook, particularly the risks of a break-up of the Euro-zone. On the basis of the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the notes or other debt instruments issued by the Company could be downgraded. Eni, through the constant monitoring of the international economic environment and continuing dialogue with financial investors and rating agencies, believes to be ready to perceive emerging critical issues screened by the financial community and to be able to react quickly to any changes in the financial and

the global macroeconomic environment and implement the necessary actions to mitigate such risks, coherently with Company strategies.

Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differently credit risk depending on whether credit risk arises from exposure to financial counterparties or to customers relating to outstanding receivables. Individual business units and Eni’s corporate financial and accounting units are responsible for managing credit risk arising in the normal course of business.
The Group has established formal credit systems and processes to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. Also credit litigation and receivable collection activities are assessed. Eni’s corporate units define directions and methods for quantifying and controlling customer’s reliability. With regard to risk arising from financial counterparties, Eni has established guidelines prior to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profile of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group central finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group Companies and Divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored to check exposures against limits assigned to each counterpart on a daily basis. Exceptional market conditions have forced the Group to adopt contingency plans and under certain circumstances to suspend eligibility to be a Group financial counterparty. Actions implemented also have been intended to limit concentrations of credit risk by maximizing counterparty diversification and turnover.

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Eni in 2012 Financial information

Financial information

Summary
of significant
accounting policies
and practices

Eni prepares its consolidated financial statements in accordance with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Union. Differences in certain respects between IFRS as endorsed by the EU and IFRS as issued by IASB are on matters that do not relate to Eni. On this basis, Eni’s financial statements are fully in compliance with IFRS as issued by IASB.
In 2012, in accordance with the guidelines of IFRS 5, the results of Snam SpA and its subsidiaries (Snam) have been reported as discontinued operations due to Eni’s plan to divest the business. Eni lost control over the entity in October 2012, as part of a transaction to divest approximately 30% of the share capital of Snam to an Italian entity, Cassa Depositi e Prestiti which is a related party of Eni as both entities are under the common control of the Italian Ministry for Economy and Finance. The divestment took place in accordance to Law No. 27 of March 24, 2012, which mandated the ownership unbundling of Snam from Eni. Prior year data have been reclassified in accordance with guidelines of IFRS 5. The residual interest of Eni in Snam equal to 20.2% of the share capital of the investee as of the balance sheet date was accounted as financial instrument because Eni is forbidden from exercising the underlying voting rights by applicable laws and therefore cannot influence the financial and operating policy decisions of the investee. Furthermore, under applicable rules, Eni is mandated to divest any residual interest in the entity.

The consolidated financial statements of Eni include the accounts of the parent company Eni SpA and of all Italian and foreign significant subsidiaries in which Eni directly or indirectly

holds the majority of voting rights or is otherwise able to exercise control as in the case of "de facto" controlled entities. Control comprises the power to govern the financial and operating policies of the investee so as to obtain benefits from its activities. Immaterial subsidiaries, jointly controlled entities, and other entities in which the Group is in a position to exercise a significant influence through participation in the financial and operating policy decisions of the investee are generally accounted for under the equity method.

Revenues from sales of crude oil, natural gas, petroleum and petrochemical products are recognized when the products are delivered and title passes to the customer. Revenue recognition in the Engineering & Construction Division is based on the stage of completion of contracts as measured on the cost-to-cost basis applied to contractual revenues.

Eni enters into various derivative financial transactions to manage exposures to certain market risks, including foreign currency exchange rate risks, interest rate risks and commodity risks. Such derivative financial instruments are assets and liabilities recognized at fair value starting on the date on which a derivative contract is entered into and are subsequently re-measured at fair value. Derivatives are designated as hedges when the hedging relationship between the hedged item or transaction and the hedging instrument is highly effective and formally documented. Changes in the fair value of cash flow hedges, hedging exposure to variability in cash flows, are recognized in equity, except for the ineffective portion which is recognized in profit or loss; subsequently amounts taken to equity are transferred to the profit and loss account when the hedged transaction affects profit or loss. Changes in fair value of derivatives held for trading purposes, including derivatives for which the hedging relationship is not formally documented or is ineffective, are recognized in profit or loss.

Inventories of crude oil, natural gas and oil products are stated at the lower of purchase

or production cost and net realizable value. Cost is determined by applying the weighted-average cost method. Contract work in progress is recorded on the basis of contractual considerations by reference to the stage of completion of a contract measured on a cost-to-cost basis.

Property, plant and equipment is stated at cost less any accumulated depreciation, depletion and amortization charges and impairment losses. Depreciation, depletion and amortization of oil and gas properties (capitalized costs incurred to obtain access to proved reserves and to provide facilities for extracting, gathering and storing oil and gas) is calculated based on the Unit-Of-Production (UOP) method on proved reserves or proved developed reserves. Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life.

Exploration costs (costs associated with exploratory activities for oil and gas including geological and geophysical exploration costs and exploratory drilling well expenditures) are capitalized and fully amortized as incurred.

Intangible assets are initially stated at cost. Intangible assets having a defined useful life are amortized systematically, based on the straight-line method. Goodwill and intangibles lacking a defined useful life are not amortized but are reviewed periodically for impairment.

Impairment of tangible and intangible assets Eni assesses its property, plant and equipment and intangible assets, including goodwill, for impairment whenever events or changes in circumstances indicate that the carrying values of the assets may not be recoverable. Indications of impairment include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. The recoverability of an asset or group of assets is assessed by comparing the carrying value with the recoverable amount

- 35 -

Eni in 2012 Financial information

represented by the higher of fair value less costs to sell and value in use. In assessing value in use, the Group makes an estimate of the future cash flows expected to be derived from the use of the asset on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset, giving more importance to independent assumptions. Oil, natural gas and petroleum products prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace for the first four years of the estimate and management’s long-term planning assumptions thereafter. Future cash flows are discounted at a rate that reflects current market valuation of the time value of money and those specific risks of the asset that are not reflected in the estimation of future cash flows. The Group uses a discount rate that is calculated as the weighted average cost of capital to the Group (WACC), adjusted to reflect specific Country risks of each asset.

Asset retirement obligations, that may be incurred for the dismantling and removal of assets and the reclamation of sites, are evaluated estimating the costs to be incurred when the asset is retired. Future estimated costs are discounted if the effect of the time value of money is material. The initial estimate is reviewed periodically to reflect changes in circumstances and other factors surrounding the estimate, including the discount rates. The Company recognizes material provisions for asset retirement

in the upstream business. No significant asset retirement obligations associated with any legal obligations to retire refining, marketing and transportation (downstream) and chemical long-lived assets are generally recognized, as indeterminate settlement dates for the asset retirement prevent estimation of the fair value of the associated asset retirement obligation.

Provisions, including environmental liabilities, are recognized when the Group has a current (legal or constructive) obligation as a result of a past event, when it is probable that an outflow of resources embodying economic benefit will be required to settle the obligation, and when the obligation can be reliably estimated. The initial estimate to settle the obligation is discounted when the effect of the time value of money is material. The estimate is reviewed periodically to take account of changes in costs expected to be incurred to settle the obligation and other factors, including changes in the discount rates.

Eni is a party to a number of legal proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions, Eni’s management believes that ongoing litigations will not have a material adverse effect on Eni’s financial position and results of operations. However, there can be no assurance that in the future Eni will not incur material charges in connection with pending litigations as new information becomes available and new developments may occur. For further information about

pending litigations, see Note 34 - Legal proceedings - to the consolidated financial statements of 2012 included in Eni’s Annual Report.

The preparation of consolidated financial statements requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Estimates made are based on complex or subjective judgments, past experience, other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of consolidated financial statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, asset retirement obligations, business combinations, pensions and other post-retirement benefits, recognition of environmental liabilities and recognition of revenues in the engineering and construction business. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used.

For further information regarding accounting policies and practices, see Note 3 - Summary of significant accounting policies – and Note 5 - Use of accounting estimates – to the consolidated financial statements of 2012 included in Eni’s Annual Report.

- 36 -

Eni in 2012 Financial information

Profit and loss account (euro million)

		2010			2011			2012

REVENUES
Net sales from operations	96,617		107,690		127,220
Other income and revenues	967		926		1,546
	97,584		108,616		128,766
OPERATING EXPENSES
Purchases, services and other	68,774		78,795		95,363
- of which non-recurring charge (income)	(246	)	69
Payroll and related costs	4,428		4,404		4,658
OTHER OPERATING (EXPENSE) INCOME	131		171		(158	)
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS	9,031		8,785		13,561
OPERATING PROFIT	15,482		16,803		15,026
FINANCE INCOME (EXPENSE)
Finance income	6,109		6,376		7,218
Finance expense	(6,727	)	(7,410	)	(8,274	)
Derivative financial instruments	(131	)	(112	)	(251	)
	(749	)	(1,146	)	(1,307	)
INCOME (EXPENSE) FROM INVESTMENTS
Share of profit (loss) of equity-accounted investments	493		500		278
Other gain (loss) from investments	619		1,623		2,603
	1,112		2,123		2,881
PROFIT BEFORE INCOME TAXES	15,845		17,780		16,600
Income taxes	(8,581	)	(9,903	)	(11,659	)
Net profit for the year - Continuing operations	7,264		7,877		4,941
Net profit (loss) for the year - Discontinued operations	119		(74	)	3,732
Net profit for the year	7,383		7,803		8,673
Attributable to:
Eni
- continuing operations	6,252		6,902		4,198
- discontinued operations	66		(42	)	3,590
	6,318		6,860		7,788
Non-controlling interest
- continuing operations	1,012		975		743
- discontinued operations	53		(32	)	142
	1,065		943		885

- 37 -

Eni in 2012 Financial information

Balance sheet (euro million)

		Dec. 31, 2011			Dec. 31, 2012

ASSETS
Current assets
Cash and cash equivalents	1,500		7,765
Other financial assets available for sale	262		235
Trade and other receivables	24,595		28,621
Inventories	7,575		8,496
Current tax assets	549		771
Other current tax assets	1,388		1,230
Other current assets	2,326		1,624
Total current assets	38,195		48,742
Non-current assets
Property, plant and equipment	73,578		63,466
Inventory - compulsory stock	2,433		2,538
Intangible assets	10,950		4,487
Equity-accounted investments	5,843		4,265
Other investments	399		5,085
Other financial assets	1,578		1,229
Deferred tax assets	5,514		4,913
Other non-current receivables	4,225		4,400
Total non-current assets	104,520		90,383
Assets held for sale	230		516
TOTAL ASSETS	142,945		139,641
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	4,459		2,223
Current portion of long-term debt	2,036		2,961
Trade and other payables	22,912		23,581
Income taxes payables	2,092		1,622
Other taxes payables	1,896		2,162
Other current liabilities	2,237		1,437
Total current liabilities	35,632		33,986
Non-current liabilities
Long-term debt	23,102		19,279
Provisions for contingencies	12,735		13,603
Provisions for employee benefits	1,039		982
Deferred tax liabilities	7,120		6,740
Other non-current liabilities	2,900		1,977
Total non-current liabilities	46,896		42,581
Liabilities directly associated with assets held for sale	24		361
TOTAL LIABILITIES	82,552		76,928
SHAREHOLDERS’ EQUITY
Non-controlling interest	4,921		3,514
Eni shareholders’ equity
Share capital	4,005		4,005
Reserves related to cash flow hedging derivatives net of tax effect	49		(16	)
Other reserves	53,195		49,579
Treasury shares	(6,753	)	(201	)
Interim dividend	(1,884	)	(1,956	)
Net profit	6,860		7,788
Total Eni shareholders’ equity	55,472		59,199
TOTAL SHAREHOLDERS’ EQUITY	60,393		62,713
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	142,945		139,641

- 38 -

Eni in 2012 Financial information

Statements of cash flow (euro million)

		2010			2011			2012

Net profit of the year - Continuing operations	7,264		7,877		4,941
Adjustments to reconcile net profit to net cash provided by operating activities:
Depreciation and amortization	8,343		7,755		9,538
Impairments of tangible and intangible assets, net	688		1,030		4,023
Share of (profit) loss of equity-accounted investments	(493	)	(500	)	(278	)
Gain on disposal of assets, net	(558	)	(1,176	)	(875	)
Dividend income	(264	)	(659	)	(431	)
Interest income	(95	)	(99	)	(108	)
Interest expense	607		773		803
Income taxes	8,581		9,903		11,659
Other changes	(39	)	331		(1,945	)
Changes in working capital:
- inventories	(1,141	)	(1,400	)	*(1,395*	)
- trade receivables	(1,923	)	218		*(3,184*	)
- trade payables	2,811		34		*2,029*
- provisions for contingencies	575		109		*338*
- other assets and liabilities	(1,480	)	(657	)	*(1,161*	)
Cash flow from changes in working capital	(1,158	)	(1,696	)	(3,373	)
Net change in the provisions for employee benefits	22		(10	)	16
Dividends received	766		955		988
Interest received	124		99		91
Interest paid	(630	)	(927	)	(825	)
Income taxes paid, net of tax receivables received	(9,018	)	(9,893	)	(11,868	)
Net cash provided by operating activities - Continuing operations	14,140		13,763		12,356
Net cash provided by operating activities - Discontinued operations	554		619		15
Net cash provided by operating activities	14,694		14,382		12,371
Investing activities:
- tangible assets	(12,308	)	(11,658	)	*(11,222*	)
- intangible assets	(1,562	)	(1,780	)	*(2,295*	)
- consolidated subsidiaries and businesses	(143	)	(115	)	*(178*	)
- investments	(267	)	(245	)	*(391*	)
- securities	(50	)	(62	)	*(17*	)
- financing receivables	(866	)	(715	)	*(1,634*	)
- change in payables and receivables in relation to investing activities and capitalized depreciation	261		379		54
Cash flow from investing activities	(14,935	)	(14,196	)	(15,683	)
Disposals:
- tangible assets	272		154		*1,229*
- intangible assets	57		41		61
- consolidated subsidiaries and businesses	215		1,006		*3,521*
- investments	569		711		*1,203*
- securities	14		128		52
- financing receivables	841		695		*1,578*
- change in payables and receivables in relation to disposals	2		243		*(252*	)
Cash flow from disposals	1,970		2,978		*7,392*
Net cash used in investing activities	(12,965	)	(11,218	)	(8,291	)
Proceeds from long-term debt	2,953		4,474		10,484
Repayments of long-term debt	(3,327	)	(889	)	(3,784	)
Increase (decrease) in short-term debt	2,646		(2,481	)	(753	)
	2,272		1,104		5,947
Net capital contributions by non-controlling interest			26
Sale of treasury shares			3
Net acquisition of treasury shares different from Eni SpA	37		17		29
Acquisition of additional interests in consolidated subsidiaries			(126	)	604
Dividends paid to Eni’s shareholders	(3,622	)	(3,695	)	(3,840	)
Dividends paid to non-controlling interest	(514	)	(552	)	(539	)
Net cash used in financing activities	(1,827	)	(3,223	)	2,201
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)			(7	)	(4	)
Effect of exchange rate changes on cash and cash equivalents and other changes	39		17		(12	)
Net cash flow of the year	(59	)	(49	)	6,265
Cash and cash equivalents - beginning of the year	1,608		1,549		1,500
Cash and cash equivalents - end of the year	1,549		1,500		7,765

- 39 -

Eni in 2012 Financial information

Non-GAAP measures

> Reconciliation of reported operating profit and reported net profit to results on an adjusted basis
Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses, special items and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates which impact industrial margins

and translation of commercial payables and receivables. Accordingly also currency translation effects recorded through profit and loss are reported within business segments’ adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (38% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models. The following

is a description of items that are excluded from the calculation of adjusted results.

Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting.

2012 (euro million)

		`OTHER ACTIVITIES` ^(a)		`DISCONTINUED OPERATIONS`

Exploration & Production Gas & Power ^(a) Refining & Marketing Chemicals Engineering & Construction Corporate and financial companies Snam Other activities Impact of unrealized intragroup profit elimination GROUP Snam Consolidation adjustments Total CONTINUING OPERATIONS

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

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

- 40 -

Eni in 2012 Financial information

divestments even though they occurred in past periods or are likely to occur in future ones; or (iii) exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency. Those items are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the exchange rate market. As provided for in Decision No. 15519 of July 27, 2006, of the Italian market regulator

(Consob), non recurring material income or charges are to be clearly reported in the management’s discussion and financial tables. Also, special items include gains and losses on re-measurement at fair value of certain non hedging commodity derivatives, including the ineffective portion of cash flow hedges and certain derivatives financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production Division.

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

2011 (euro million)

		`OTHER ACTIVITIES` ^(a)		`DISCONTINUED OPERATIONS`

Exploration & Production Gas & Power ^(a) Refining & Marketing Chemicals Engineering & Construction Corporate and financial companies Snam Other activities Impact of unrealized intragroup profit elimination GROUP Snam Consolidation adjustments Total CONTINUING OPERATIONS

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

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

- 41 -

Eni in 2012 Financial information

2010 (euro million)

		`OTHER ACTIVITIES` ^(a)		`DISCONTINUED OPERATIONS`

Exploration & Production Gas & Power ^(a) Refining & Marketing Chemicals Engineering & Construction Corporate and financial companies Snam Other activities Impact of unrealized intragroup profit elimination GROUP Snam Consolidation adjustments Total CONTINUING OPERATIONS

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

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

- 42 -

Eni in 2012 Financial information

For a reconciliation of Summarized Group Balance Sheet and Summarized Group Cash Flow Statement with the corresponding statutory tables see Eni’s 2012 Annual Report, "Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes" pages 86-88.

> Summarized Group Balance Sheet
The Summarized Group Balance Sheet aggregates the amount of assets and liabilities derived from the statutory balance sheet in accordance with functional criteria which consider the enterprise conventionally divided into the three fundamental areas

focusing on resource investments, operations and financing. Management believes that this Summarized Group Balance Sheet is useful information in assisting investors to assess Eni’s capital structure and to analyze its sources of funds and investments in fixed assets and working capital. Management

uses the Summarized Group Balance Sheet to calculate key ratios such as the proportion of net borrowings to shareholders’ equity (leverage) intended to evaluate whether Eni’s financing structure is sound and well-balanced.

Summarized Group Balance Sheet (euro million)

		Dec. 31, 2011			Dec. 31, 2012

Fixed assets
Property, plant and equipment	73,578		63,466
Inventories - Compulsory stock	2,433		2,538
Intangible assets	10,950		4,487
Equity-accounted investments and other investments	6,242		9,350
Receivables and securities held for operating purposes	1,740		1,457
Net payables related to capital expenditure	(1,576	)	(1,142	)
	93,367		80,156

Net working capital
Inventories	7,575		8,496
Trade receivables	17,709		19,966
Trade payables	(13,436	)	(14,993	)
Tax payables and provisions for net deferred tax liabilities	(3,503	)	(3,318	)
Provisions	(12,735	)	(13,603	)
Other current assets and liabilities	281		2,347
	(4,109	)	(1,105	)

Provisions for employee post-retirement benefits	(1,039	)	(982	)
Assets held for sale including related liabilities	206		155

CAPITAL EMPLOYED NET	88,425		78,224

- Eni shareholders’ equity	55,472		59,199
- Non-controlling interest	4,921		3,514
Shareholders’ equity	60,393		62,713
Net borrowings	28,032		15,511

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	88,425		78,224

> Net borrowings and leverage
Eni evaluates its financial condition by reference to net borrowings, which is calculated as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due

to Eni’s financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities.
Leverage is a measure used by management to assess the Company’s level of indebtedness. It is calculated as a ratio of net borrowings

which is calculated by excluding cash and cash equivalents and certain very liquid assets from financial debt to shareholders’ equity, including non-controlling interest. Management periodically reviews leverage in order to assess the soundness and efficiency of the Group Balance Sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards.

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Eni in 2012 Financial information

Net borrowings and leverage (euro million)

		Dec. 31, 2011			Dec. 31, 2012

Total debt	29,597		24,463
- Short-term debt	6,495		*5,184*
- Long-term debt	23,102		*19,279*
Cash and cash equivalents	(1,500	)	(7,765	)
Securities held for non-operating purposes	(37	)	(34	)
Financing receivables for non-operating purposes	(28	)	(1,153	)
Net borrowings	28,032		15,511
Shareholders’ equity including non-controlling interest	60,393		62,713
Leverage	0.46		0.25

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

Summarized Group Cash Flow Statement (euro million)

		2010			2011			2012

Net profit - continuing operations	7,264		7,877		4,941
Adjustments to reconcile net profit to net cash provided by operating activities:
- depreciation, depletion and amortization and other non-monetary items	8,521		8,606		11,354
- net gains on disposal of assets	(558	)	(1,176	)	(875	)
- dividends, interest, taxes and other changes	8,829		9,918		11,923
Changes in working capital related to operations	(1,158	)	(1,696	)	(3,373	)
Dividends received, taxes paid, interest (paid) received during the period	(8,758	)	(9,766	)	(11,614	)
Net cash provided by operating activities - continuing operations	14,140		13,763		12,356
Net cash provided by operating activities - discontinued operations	554		619		15
Net cash provided by operating activities	14,694		14,382		12,371
Capital expenditure - continuing operations	(12,450	)	(11,909	)	(12,761	)
Capital expenditure - discontinued operations	(1,420	)	(1,529	)	(756	)
Capital expenditure	(13,870	)	(13,438	)	(13,517	)
Investments and purchase of consolidated subsidiaries and businesses	(410	)	(360	)	(569	)
Disposals	1,113		1,912		6,014
Other cash flow related to capital expenditure, investments and disposals	228		627		(136	)
Free cash flow	1,755		3,123		4,163
Borrowings (repayment) of debt related to financing activities	(26	)	41		(83	)
Changes in short and long-term financial debt	2,272		1,104		5,947
Dividends paid and changes in non-controlling interests and reserves	(4,099	)	(4,327	)	(3,746	)
Effect of changes in consolidation area and exchange differences	39		10		(16	)
NET CASH FLOW	(59	)	(49	)	6,265

Change in net borrowings (euro million)

		2010			2011			2012

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

> Pro-forma adjusted EBITDA
EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization charges) on an adjusted basis is calculated by adding amortization and depreciation charges to

adjusted operating profit, which is also modified to take into account the impact associated with certain derivatives instruments as detailed below. This performance indicator includes the adjusted EBITDA of Eni’s wholly owned

subsidiaries and Eni’s share of adjusted EBITDA generated by certain associates which are accounted for under the equity method for IFRS purposes. In order to calculate the EBITDA pro-forma adjusted, the adjusted operating profit

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Eni in 2012 Financial information

of the Marketing business has been modified to take into account the impact of the settlement of certain commodity and exchange rate derivatives that do not meet the formal criteria to be classified as hedges under the IFRS. These are entered into by the Company in view of certain amounts of gas and electricity that the Company expects to supply at fixed prices during future periods. The impact of those derivatives has been allocated to the EBITDA pro-forma adjusted relating to the reporting periods during which those supplies at fixed prices are recognized. Management believes that the EBITDA pro-forma adjusted is an important alternative measure to assess the performance of Eni’s Gas & Power Division, taking into account evidence that this Division is comparable to European utilities in the gas and power generation sector. This measure is provided in order to assist investors and financial analysts in assessing the divisional performance of Eni Gas & Power, as compared to its European peers, as EBITDA is widely used as the main performance indicator for utilities. The EBITDA pro-forma adjusted is a non-GAAP measure under IFRS.

> Production sharing agreements (PSA)
Contract in use in non OECD Countries, regulating relationships between States and oil companies with regard to the exploration and production of hydrocarbons. The mining concession is assigned to the national oil company jointly with the foreign oil company who has exclusive right to perform exploration, development and production activities and can enter agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "Cost Oil" is used to recover costs borne by the contractor, "Profit Oil" is divided between contractor and national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions may vary from one Country to the other.

> Possible reserves
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

> Probable reserves
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

> Proved reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

> Recoverable reserves
Amounts of hydrocarbons included in different categories of reserves (proved, probable and possible), without considering their different degree of uncertainty.

> Reserves
Quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and

all permits and financing required to implement the project. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods.

> Reserve replacement ratio
Measure of the reserves produced replaced by proved reserves. Indicates the company’s ability to add new reserves through exploration and purchase of property. A rate higher than 100% indicates that more reserves were added than produced in the period. The ratio should be averaged on a three-year period in order to reduce the distortion deriving from the purchase of proved property, the revision of previous estimates, enhanced recovery, improvement in recovery rates and changes in the value of reserves – in PSAs – due to changes in international oil prices. Management also calculates this ratio by excluding the effect of the purchase of proved property in order to better assess the underlying performance of the Company’s operations.

> Average reserve life index
Ratio between the amount of reserves at the end of the year and total production for the year.

> Resource base
Oil and gas volumes contained in a reservoir as ascertained based on available engineering and geological data (sum of proved, probable and possible reserves) plus volumes not yet discovered but that are expected to be eventually recovered from the reservoir net of a risk factor (risked exploration resources).

> Take-or-pay
Clause included in natural gas supply contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of gas set in the contract whether or not the gas is collected by the purchaser. The purchaser has the option of collecting the gas paid for and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.

> Conversion
Refinery process allowing the transformation of heavy fractions into lighter fractions. Conversion processes are cracking, visbreaking, coking, the gasification of refinery residues, etc. The ratio of overall treatment capacity of these plants and that of primary crude fractioning plants is the conversion rate of a refinery. Flexible refineries have higher rates and higher profitability.

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Eni in 2012 Directors and officers

Was born in 1964 and has been Chairman of the Board of Eni since May 2011. He is also Vice Chairman of GE Capital Interbanca SpA; a member of the Board of Directors and of the Audit Committee of Exor SpA; a member of the European Advisory Board of Blackstone and a member of the Massachusetts Institute of Technology E.I. External Advisory Board. He is also a member of the Italian Corporate Governance Committee, of the executive committees of Confindustria (where he chairs the Foreign Investment Committee), Assonime (Association of Italian Joint Stock Companies), Aspen Institute Italia; a member of the Board of Directors of FEEM-Eni Enrico Mattei Foundation, of the Italian Institute of Technology and of the LUISS Business School Advisory Board. He is co-Chair of the B20 Task Force on Improving Transparency and Anti-Corruption and director of the World Economic Forum Partnering Against Corruption Initiative. He holds a degree in Engineering from the Polytechnic of Turin. In 1989 he started his career as entrepreneur at Recchi SpA, a general contractor active in 25 Countries in the construction of high-tech public infrastructure. Since 1994 he has served as Executive Chairman of Recchi America Inc., the US branch of Recchi Group. In 1999 he joined General Electric, where he held several management positions in Europe and in the United States. He served as Director of GE Capital Structure Finance Group; Managing Director for Industrial M&A and Business Development for GE EMEA; President & CEO of GE Italy. Until May 2011 he was President & CEO of GE South Europe. Mr. Recchi was a member of the Organizing Committee for the Rome Candidacy for the 2020 Olympic Games, of the Board of Permasteelisa SpA, of the Advisory Board of Invest Industrial (private equity) and visiting professor in Structured Finance at Turin University.

Has been Chief Executive Officer of Eni since June 2005. He is currently a Non-Executive Director of Assicurazioni Generali, Non-Executive Deputy Chairman of the London Stock Exchange Group and a Non- Executive Director of Veolia Environnement. He also sits on the Board of Overseers of Columbia

Business School and of Fondazione Teatro alla Scala. After receiving a degree in economics and business from Luigi Bocconi University in Milan in 1969, he worked for three years at Chevron, before obtaining an MBA from Columbia University, New York, and continuing his career at McKinsey. In 1973 he joined Saint Gobain, where he held a series of management positions in Italy and abroad, until his appointment as head of the glass division in Paris in 1984. From 1985 to 1996 he was Deputy Chairman and CEO of Techint. In 1996 he moved to the UK and served as CEO of Pilkington until May 2002.
From May 2002 to May 2005 he served as Chief Executive Officer and General Manager of Enel. From 2005 to July 2006 he was Chairman of Alliance Unichem. In May 2004 he was decorated as Cavaliere del Lavoro of the Italian Republic. In November 2007 he was decorated as an Officier of the French Légion d’Honneur.

Was born in 1941 and has been a Director of Eni since May 2011. He graduated from the University of Turin with a degree in Economics and Business. He is a certified public auditor. He is currently Chairman of the Board of Statutory Auditors of RAI SpA, Natuzzi SpA, Difesa Servizi SpA, Rainet SpA and Director of Arcese Trasporti SpA. He has taught courses in Finance, Administration and Control at the Isvor Fiat SpA training institute. In 1968 he was hired by Impresit as Chief Accountant, where he managed the finance department of the local branch in Jordan. He joined the Fiat Group in 1969 where over the years he held a series positions of increasing responsibility in the area of finance, administration and control. From 1979 to 1990 he was in charge of Financial Reporting at the Fiat Group and was also responsible for controlling the transport companies of the Fiat Group operating public transport concessions (Sapav, Sadem, Sita) and oversaw their subsequent sale. In 1990 he was appointed Joint Manager of Finance and Control of the Fiat Group, before becoming, in 1998, Chief Administration Officer (CAO). From 2000 to 2004, he was Chief Executive Officer and Deputy Chairman of Business Solutions, a new sector created by Fiat to provide business services. In 1993 he was the Italian Representative to the European Commission for the fiscal harmonization of the Member States. In 1992 he was decorated as Cavaliere Ordine al Merito of the Italian Republic and, in 1995, an Ufficiale Ordine al Merito of the Italian Republic.

Was born in 1948 and has been a Director of Eni since May 2011. He is currently a founding partner of Tokos Srl, a securities investment consulting firm, and Chairman of Società Metropolitana Acque Torino SpA, and a Director of Ersel SIM SpA, Millbo SpA and Sicme Motori Srl. He began his career at SAIAG SpA, in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined the GFT Group, where he was head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of the GFT Group (1984-1988), Head of Finance and Control of the GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Central Manager and, subsequently, Director of Ersel SIM SpA, a position he held until June 2000. In 2000 he became Central Manager of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of the Coin Group. In 2006 he became Central Corporate Manager at Lavazza SpA, serving as a member of the Board of Directors from 2008 to June 2011.

Was born in 1969 and has been a Director of Eni since June 2008. He is a lawyer specializing in criminal and administrative law, and has been admitted to argue before the Supreme Court and the higher Courts. He has been Chairman of the Board of Directors of Finpiemonte partecipazioni SpA since August 2010. He serves as a consultant to government agencies and business organizations on business, corporate, administrative and local government law. He was Mayor of Baveno (Verbania) from April 1995 to June 2004 and Chairman of the Assembly of Mayors of Con.Ser.Vco from September 1995 to June 1999. Until June 2004 he was a member of the

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

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Eni in 2012 Directors and officers

Assembly of Mayors of the Asl 14 health authority, the steering committee of the Verbania health district, the Assembly of Mayors of the Valle Ossola waste water consortium, the Assembly of Mayors of the Verbania social services consortium. From April 2005 to January 2008 he was a member of the Stresa (VB) city council. From October 2001 to April 2004 he was a Director of CIM SpA of Novara (merchandise interport centre) and from December 2002 to December 2005 a Director and executive committee member of Finpiemonte SpA. From June 2005 to June 2008 he was a Director of Consip SpA. He was Vice President and Provincial Councillor in charge of the budget, financial reporting, property, legal affairs and productive activities of the Province of Verbano-Cusio-Ossola from June 2009 to October 2011. He was Director of the Provincial Board of the Province of Verbano-Cusio-Ossola from October 2011 to November 2012.

Has been a Director of Eni since May 2011. He was born in Pescara in 1949 and graduated with a degree in law from "Gabriele D’Annunzio" University of Chieti and Pescara. He has been a member of the Board of Directors of the Ravenna Festival since 2007 and he has been Chairman of Italimmobili Srl since 2011. In 1976 he was hired by Banca Nazionale del Lavoro (BNL) where he held a series of positions: Head of the "Lending Advisory" of BNL in Busto Arsizio (1982), Deputy Manager for the industrial division at the BNL branch in Ravenna (1983-1987), Area Chief of BNL in Venice (1987-1989) and Joint Manager of the central office of BNL in Rome (1989-1990). In 1990 he was appointed Commercial Manager at Banca Popolare and in 1994 he transferred, holding the same position, to Cassa di Risparmio di Ravenna Group (Carisp Ravenna and Banca di Imola). From 2001 to 2006 he was Chief Secretary to the Under-Secretary of Defence, where he was mainly involved in the Defence Ministry’s contacts with industry and international relations. From 2008 to 2011 he was Chief Secretary of the Minister of Defence. From 2003 to 2006 he was a Director of Fintecna SpA and from 2005 to 2008 a Director of Finmeccanica SpA.

Was born in 1957 and has been Director of Eni since May 2011. He received a degree in Business Administration from Università Luigi Bocconi of Milan. He is currently Chairman of Banca Monte dei Paschi di Siena, of Appeal Strategy & Finance Srl and member of the Supervisory Board of Sberbank. He is also member of the Board of Directors of the Bocconi University in Milan. He began his career

in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development projects at Bain, Cuneo e Associati firm (now Bain & Co). In 1991 he left the consulting field to join RAS, Riunione Adriatica di Sicurtà, where he was given responsibility, as General Manager, for the banking and parabanking sectors.
He was also in charge of expanding the revenues of that group’s bank and of the other group companies operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager, with responsibility for Programming and Control, becoming General Manager in 1995. In 1997 he was appointed Chief Executive Officer of Credito Italiano and subsequently of Unicredit, a position he held until September 2010. On an international level he was Chairman of the European Banking Federation in Bruxelles and Chairman of the Internal Monetary Conference Washington. In May 2004 he was decorated as a Cavaliere del Lavoro.

Was born in 1945 and has been a Director of Eni since May 2002. He graduated from the Università Luigi Bocconi of Milan with a degree in Economics and Business. He is also Chairman of Confimprese, Deputy Chairman of Sesto Immobiliare SpA and Director of Mondadori SpA. After graduating, he joined Chase Manhattan Bank. In 1974 he was appointed manager of Saifi Finanziaria (Fiat Group) and from 1976 to 1991 he was a partner at Egon Zehnder. In this period he was appointed Director of Lancôme Italia and of companies belonging to the RCS Corriere della Sera Group and the Versace Group. From 1995 to 2007 he was Chairman and Chief Executive Officer of McDonald’s Italia. He was also Chairman of Sambonet SpA and Kenwood Italia SpA, a founding partner of Eric Salmon & Partners, Chairman of the American Chamber of Commerce, General Director of Italian Heritage and Antiquities in the Ministry of Cultural Heritage and Activities and Chairman of Convention Bureau Italia SpA. He was decorated as a Cavaliere del Lavoro in June 2002.

Was born in 1940 and has been a Director of Eni since June 2008. He is currently Vice Chairman of Banca CR Firenze SpA (Cassa di Risparmio di Firenze SpA). He is also a Director and member of the Executive Committee of Rimorchiatori Riuniti SpA. He started working in 1959 in a stock brokerage in Milan. From 1965 to 1982, he worked at Banco

di Napoli as deputy manager of the stock market and securities department. He held a series of management positions in the asset management field, notably as manager of securities funds at Eurogest from 1982 to 1984, and General Manager of Interbancaria Gestioni from 1984 to 1987. After moving to the Prime group (1987 to 2000), he was Chief Executive Officer of the parent company for an extended period of time. He was Director of ERSEL SIM, member of the steering council of Assogestioni and of the Committee for the Corporate Governance of listed companies formed by Borsa Italiana. He was a Director of Enel from October 2000 to June 2008.

BOARD COMMITTEES
Control and Risk Committee:
Alessandro Lorenzi - Chairman, Carlo Cesare Gatto, Paolo Marchioni and Francesco Taranto
Compensation Committee:
Mario Resca - Chairman, Carlo Cesare Gatto, Roberto Petri and Alessandro Profumo
Nomination Committee:
Giuseppe Recchi - Chairman, Alessandro Lorenzi, Alessandro Profumo and Mario Resca
Oil - Gas Energy Committee:
Alessandro Profumo - Chairman, Alessandro Lorenzi, Paolo Marchioni, Roberto Petri, Mario Resca and Francesco Taranto

BOARD OF STATUTORY AUDITORS
Ugo Marinelli - Chairman, Roberto Ferranti, Paolo Fumagalli, Renato Righetti, Giorgio Silva, Francesco Bilotti and Maurizio Lauri

EXTERNAL AUDITORS
Reconta Ernst & Young SpA

GROUP OFFICERS
Paolo Scaroni
Chief Executive Officer and General Manager
Claudio Descalzi
Exploration & Production Chief Operating Officer
Umberto Vergine ^(a)Gas & Power Chief Operating Officer
Angelo Fanelli
Refining & Marketing Chief Operating Officer
Massimo Mondazzi
Chief Financial Officer
Salvatore Sardo
Chief Corporate Operations Officer
Stefano Lucchini
Senior Executive Vice President for International Relations and Communication
Massimo Mantovani
Senior Executive Vice President for General Counsel Legal Affairs
Roberto Ulissi
Senior Executive Vice President for Corporate Affairs and Governance
Marco Petracchini
Senior Executive Vice President for Internal Audit
Marco Alverà
Senior Executive Vice President for Trading
Salvatore Meli
Executive Vice President for Research and Technological Innovation
Leonardo Bellodi
Executive Vice President for Government Affairs
Stefano Leofreddi
Senior Vice President for Integrated Risk Management
Raffaella Leone
Executive Assistant to the Chief Executive Officer

(a) In charge until December 4, 2012; since December 5, 2012 Paolo Scaroni has been Gas & Power Chief Operating Officer ad interim.

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Eni in 2012 Directors and officers

> Remuneration¹The Eni Remuneration Policy is defined consistently with the recommendations of the Borsa Italiana Code as transposed in the Eni Code. It is approved by the Board of Directors following a proposal by the Compensation Committee, made up of non-executive, independent Directors, and is		defined in accordance with the governance model adopted by the Company and with the recommendations of the Corporate Governance Code. This Policy aims to align the interests of management with the prime objective of creating sustainable value for shareholders over the medium-long term, in accordance		with the guidelines defined in the Strategic Plan of the Company. The table describes the main elements of the approved 2013 Guidelines for the remuneration of the Chief Executive Officer and General Manager (CEO/GM), of the Chief Operating Officers of Eni’s Divisions and other Managers with strategic responsibilities (MSR).

Remuneration Policy 2013

Component	Aims and characteristics	Implementation condition	Values
Fixed remuneration	Reflects the skills, experiences and contribution related to the assigned role	Setting of the remuneration levels through benchmarks consistent with Eni and with the responsibilities of the specific roles	CEO/GM euro 1,430,000 annually (unchanged since 2005) MSR: remuneration determined on the basis of the level of the specific role with possible adjustments in relation to competitive placement targets (average market values)
Annual variable incentives	Promotes the achievement of annual budget objectives All the managers participate in the Plan Target incentives assigned are differentiated based on different roles Incentives paid on the basis of results achieved in the previous year	CEO/GM Objectives: - Implementation of strategic, financial and sustainability guidelines (30%) - Operational Performance of Divisions (30%) - Adjusted EBIT (30%) - Efficiency program (10%) MSR objectives: business and individual objectives determined based on those of the CEO/GM and on the responsibilities assigned Performance scale for each objective 70÷130 points^(*); minimum threshold for the incentive equal to a total performance of 85 points	CEO/GM: on-target bonus of 110% of the fixed remuneration (min. 87.5% and max. 155%) MSR: on-target incentives up to a maximum 60% of the fixed remuneration
Deferred Monetary Incentive (2012-2014 Plan)	Promotes the business profitability growth in the long-term All managers who have reached the annual objectives participate in the Plan Target incentives assigned are differentiated based on specific roles	EBITDA performance measured against the EBITDA value as per the Plan Amount assigned on the basis of the EBITDA results achieved in the previous year evaluated in accordance with the performance scale 70÷130 ^()Amount paid as a variable percentage between zero and 170% of the amount assigned, on the basis of the average results achieved in the vesting period, evaluated in accordance with the performance scale 70÷170 ^()Vesting period: three years	CEO/GM: on-target incentive assigned of 55% of the fixed remuneration (min. 38.5% and max. 71.5%) MSR: on-target incentives assigned up to a maximum 40% of the fixed remuneration
Long-Term Monetary Incentive (2012-2014 Plan)	Promotes a business long-term profitability growth superior of that of the peers Managers who are critical for the business participate in Plan Target incentives assigned are differentiated based on specific roles	Performance measured in terms of the variation of the Adjusted Net Profit + DD&A, compared to the ones reported by the main Oil Majors in the Eni Peer group (Exxon, Shell, Chevron, BP, Total, Conoco) Incentive paid as a variable percentage between zero and 130% of the assigned amount, based on the average annual placement achieved in the vesting period: 1° Place 130% 2° Place 115% 3° Place 100% 4° Place 85% ——————————————————————————————————— 5° Place 70% 6° Place 0% 7° Place 0% Vesting period: three years	CEO/GM: on-target incentive assigned to target on the basis of the annual value of the previous stock option plan MSR: on-target incentives assigned up to a maximum 50% of the fixed remuneration
Benefits	The remuneration package is integrated with social security and insurance-related benefits, according to a "total reward" approach	Conditions defined by the national collective labor agreement and complementary company level agreements applicable to senior managers	- Supplementary pension plan - Supplementary health plan - Insurance coverages - Company car

(*) Performance rated below the minimum threshold (70 points) is considered equal to zero.

Pursuant to Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications, the following table below reports individual remuneration paid in 2012 to each Member of the Board of Directors, Statutory Auditors, and Chief Operating Officers. The overall amount earned by other Managers with strategic responsibilities is reported too.
In compliance with the rule, the table provides details on:
• "Fixed remuneration" which includes, following the criteria of competence, fixed remuneration and fixed salary from employment due for the year, gross of social security and tax expenses to be paid by the employee; it excludes lump-sum expense reimbursements and attendance fees, as they are not envisaged;
• "Committees membership remuneration" which reports, following the criteria of

competence, the compensation due to the Directors for participation in the Committees established by the Board;
• "Variable non-equity remuneration - Bonuses and other incentives" which reports the incentives paid during the year due to the vesting of the relative rights following the assessment and approval of the relative performance results by the relevant company bodies, in accordance with that specified, in greater detail, in the Table "Monetary incentive plans for Directors, Chief Operating Officers, and other Managers with strategic responsibilities"; the column "Profit sharing", does not include any figures, as no form of profit-sharing is envisaged;
• "Non-monetary benefits" which reports, in accordance with competence and taxability criteria, the value of fringe benefits awarded;

• "Other remuneration" reports, in accordance with the criteria of competence, any other remuneration deriving from other services provided;
• "Total" which reports the sum of the amounts of all the previous items;
• "Fair value of equity remuneration" which reports the fair value of competence of the year related to the existing stock option plans, estimated in accordance with international accounting standards which assign the relevant cost in the vesting period;
• "Severance indemnities for end of office or termination of employment" which reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of financial year considered or in relation to the end of the office and/or employment.

(1) For detailed information on Eni’s remuneration policy and compensation see the “Remuneration Report 2013” available on Eni’s website under the sections “Governance” and “Investor relations”.

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Eni in 2012 Directors and officers

Remuneration paid to Directors, Statutory Auditors, Chief Operating Officers, and other Managers with strategic responsibilities

(euro thousand)		`Variable non-equity remuneration`

Name Office Term of office Office expiry ^(*) Fixed remuneration Committee membership remuneration Bonuses and other incentives Profit sharing Non-monetary benefits Other remuneration Total 2012 Fair Value of equity remuneration Severance indemnity for end of office or termination of employment

Board of Directors
Giuseppe Recchi	Chairman	01.01 - 31.12	04.2014	765		245	4		1,014
Paolo Scaroni	CEO and General Manager	01.01 - 31.12	04.2014	1,430		4,952	15		6,397
Carlo Cesare Gatto	Director	01.01 - 31.12	04.2014	115	50				165
Alessandro Lorenzi	Director	01.01 - 31.12	04.2014	115	59				174
Paolo Marchioni	Director	01.01 - 31.12	04.2014	115	50				165
Roberto Petri	Director	01.01 - 31.12	04.2014	115	36				151
Alessandro Profumo	Director	01.01 - 31.12	04.2014	115	45				160
Mario Resca	Director	01.01 - 31.12	04.2014	115	45				160
Francesco Taranto	Director	01.01 - 31.12	04.2014	115	50				165
Board of Statutory Auditors				435					435
Chief Operating Officers
Claudio Descalzi	E&P Division	01.01 - 31.12	04.2014	773		1,171	13	599	2,556
Domenico Dispenza	G&P Division	01.01 - 31.12	04.2014	372		335	10		717
Angelo Fanelli	R&M Division	01.01 - 31.12	04.2014	559		533	14		1,106
Other Managers with strategic responsibilities ^(**)				5,432		6,597	133	145	12,307	2,917
				10,571	335	13,833	189	744	25,672	2,917

(*) The term of office expires with the Shareholders’ Meeting approving the financial statements for the year ending December 31, 2013.
(**) Managers who were permanent members of the Company Management Committee during the course of the year and with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, and those who report directly to the Chief Executive Officer (thirteen managers).

The following table sets out long-term variable components.

		Bonuses of the year		Bonuses of previous years		Other bonuses

Name

Office

(euro thousand)

paid/
payable

deferred

deferral period

no longer payable

paid/
payable ^(a)

still deferred

Giuseppe Recchi	Chairman	245
Paolo Scaroni	CEO and General Manager	2,110	3,150	896	2,842	6,522
Claudio Descalzi	Chief Operating Officer E&P Division	579	743		442	1,294	150
Umberto Vergine	Chief Operating Officer G&P Division ^(b)	191	387		144	447
Angelo Fanelli	Chief Operating Officer R&M Division	369	481		164	925
Other Managers with strategic responsibilities ^(c)		3,281	2,916	1,114	2,866	5,216	450
		6,775	7,677	2,010	6,458	14,404	600

(a) Payment relative to deferred monetary incentive awarded in 2009.
(b) Chief Operating Officer G&P Division until December 4, 2012.
(c) Managers who were permanent members of the Company Management Committee, during the course of the year together with the Chief Executive Officer and Chief Operating Officers of Eni’s Divisions, and those who report directly to the Chief Executive Officer (thirteen managers).

> Overall remuneration of key management personnel Remuneration of persons responsible of key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, Chief Operating Officers and other managers with strategic responsibilities in charge at December 31, 2012, amounted to euro 33 million, as described in the table below:
(euro million)	2012
Fees and salaries	21
Post employment benefits	1
Other long-term benefits	11
Indemnity upon termination of the office	0
	33

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Eni in 2012 Investor information

Investor information

> Eni share performance in 2012
In accordance with Article 5 of the By-laws, the Company’s share capital amounts to euro 4,005,358,876.00, fully-paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value.
As of December 31, 2012, the decrease of No. 371,266,546 shares held in treasury compared to December 31, 2011 (No. 382,654,833 shares) was due to the cancellation of No. 371,173,546 shares, as

resolved by the Extraordinary and Ordinary Shareholders’ Meeting held on July 16, 2012 and to the sale of No. 93,000 shares following 2004 stock option plans. In the last session of 2012, the Eni share price, quoted on the Italian Stock Exchange, was euro 18.34, up 14.6 percentage points from the price quoted at the end of 2011 (euro 16.01). The Italian Stock Exchange is the primary market where the Eni share is traded. During the year the FTSE/MIB index, the basket including the 40 most

important shares listed on the Italian Stock Exchange, increased by 7.8 percentage points. At the end of 2012, the Eni ADR listed on the NYSE was $49.14, up 19.07% compared to the price registered in the last session of 2011 ($41.27).
One ADR is equal to two Eni ordinary shares. In the same period the S&P 500 index increased by 13.2 percentage points. Eni market capitalization at the end of 2012 was euro 66.4 billion (euro 58 billion at the end of

Share information

		2010	2011	2012

Market quotations for common stock on the Mercato Telematico Azionario (MTA)
High	(euro)	18.56	18.42	18.70
Low		14.61	12.17	15.25
Average daily close		16.39	15.95	17.18
Year-end close		16.34	16.01	18.34

Market quotations for ADR on the New York Stock Exchange
High	(US$)	53.89	53.74	49.44
Low		35.37	32.98	36.85
Average daily close		43.56	44.41	44.24
Year-end close		43.74	41.27	49.14

Average daily traded volumes	(million of shares)	20.69	22.85	15.63
Value of traded volumes	(euro million)	336	355	267

- 50 -

Eni in 2012 Investor information

2011), confirming Eni as the first company for market capitalization listed on the Italian Stock Exchange. Shares traded during the year

totaled almost 3.9 billion, with a daily average of shares traded of 15.6 million (22.9 million in 2011).

The total trade value of Eni shares amounted to approximately euro 68 billion (euro 92 billion in 2011), equal to a daily average of euro 267 million.

Share data

		2010	2011	2012

Net profit - continuing operations
- per share^(a)	(euro)	1.72	1.90	*1.16*
- per ADR^{(a) (b)}	(US$)	4.59	5.29	*2.98*
Adjusted net profit - continuing operations
- per share^(a)	(euro)	1.87	1.92	*1.97*
- per ADR^{(a) (b)}	(US$)	4.96	5.35	*5.06*

Leverage		0.47	0.46	*0.25*
Coverage		22.2	15.4	*11.7*
Current ratio		1.00	1.10	*1.40*
Debt coverage		56.3	51.3	*80.5*

Dividends pertaining to the year	(euro per share)	1.00	1.04	1.08
Pay-out	(%)	57	55	50
Dividend yield ^(c)	(%)	6.1	6.6	5.9
TSR		(2.2)	5.1	22.0

(a) Fully diluted. Ratio of net profit and average number of shares outstanding in the year. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by ECB for the year presented.
(b) One American Depositary Receipt (ADR) is equal two Eni ordinary shares.
(c) Ratio of dividend for the period and the average price of Eni shares as recorded in December.

Dividends

Management intends to propose to the Annual Shareholders’ Meeting scheduled on May 10, 2013, the distribution of a dividend of euro 1.08 per share for fiscal year 2012, of which euro 0.54 was already paid as interim dividend in September 2012. Total cash outlay for the 2012 dividend is expected at approximately euro 3.9 billion (including euro 1.96 billion already paid in September 2012) in case the Annual Shareholders’ Meeting approves the annual dividend.
In future years, management expects to continue paying interim dividends for each

fiscal year, with the balance to the full-year dividend to be paid in each following year.

Eni intends to continue paying interim dividends in the future. Holders of ADRs receive their dividends in US dollars. The rate of exchange used to determine the amount in dollars is equal to the official rate recorded on the date of dividend payment in Italy (May 23, 2013).
On ADR payment date, Bank of New York Mellon pays the dividend less the amount of any withholding tax under Italian law

(currently 27%) to all Depository Trust Company Participants, representing payment of Eni SpA’s gross dividend. By submitting to Bank of New York Mellon certain required documents with respect to each dividend payment, US holders of ADRs will enable the Italian Depositary bank and Bank of New York Mellon as ADR Depositary to pay the dividend at the reduced withholding tax rate of 15%. US shareholders can obtain relevant documents as well as a complete instruction packet to benefit from this tax relief by contacting Bank of New York Mellon at 1.201.680.6825.

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Eni in 2012 Investor information

Publications

1	Annual Report 2012 a comprehensive report on Eni’s activities and financial and sustainability results for the year.		set of operating and financial statistics.	in the section Publications (eni.com/sites/ENI_en_IT/documentation/documentation.page?type=bilrap&leftbox=documentazione&doc_from=hpeni_left). Shareholders may receive a hard copy of Eni’s publications, free of charge, by filling in the request form found in the section Publications or through an email request addressed to segreteriasocietaria.azionisti@eni.com or to investor.relations@eni.com. Any other information relevant to shareholders and investors can be found at Eni’s website under the "Investor Relations" section.
		4	Remuneration Report 2013 a report on Eni’s compensation and remuneration policies pursuant to rule 123-ter of Legislative Decree No. 58/1998.
2	Annual Report on Form 20-F 2012 a comprehensive report on Eni’s activities and results to comply with the reporting requirements of the US Securities Exchange Act of 1934 and filed with the US Securities and Exchange Commission.
		5	Corporate Governance Report 2012 a report on the Corporate Governance system adopted by Eni pursuant to rule 123-bis of Legislative Decree No. 58/1998.


3	Fact Book 2012 a report on Eni’s businesses, strategies, objectives and development projects, including a full
		These and other Eni publications are available on Eni’s internet site eni.com,
Financial calendar

The dates of the Board of Directors’ meetings to be held during 2013 in order to approve/review the Company’s quarterly and semi-annual, and annual preliminary results are the following:	Results for the first quarter of 2013	April 24, 2013
	Results for the second quarter and the first half of 2013 and proposal of interim dividend for the financial year 2013	July 31, 2013
	Results for the third quarter of 2013	October 29, 2013
	Preliminary full-year results for the year ending December 31, 2013 and dividend proposal for the financial year 2013	February 2014

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Eni Shareholders approve 2012 Financial Statements
at Annual Meeting

2012 net profit euro 9.07 billion
Total dividend per share for 2012 of euro 1.08
Remuneration Report approved
Authorization to the Board of Directors to acquire treasury shares

Rome, May 10, 2013 - The Ordinary General Meeting of Eni’s shareholders which was held today, resolved the following:

to approve Eni SpA’s Financial Statements at December 31, 2012, which reported a net profit amounting to 9,078,358,525.02 euro;
to allocate net profit for the period of 9,078,358,525.02 euro, of which 7,122,048,121.80 euro remain following the distribution of the 2012 interim dividend of 0.54 euro per share, approved by the Board of Directors on September 20, 2012, as follows:
- an amount of 2,603,272,923.40 euro to the reserve required by Article 6, paragraph 1, letter a) of Legislative Decree No. 38 of February 28, 2005;
- an amount of 3,391,234,297.34 euro to the optional reserve;
- the remaining profit and where necessary, using the available reserve, allocated to shareholders in the form of a dividend of 0.54 euro per share owned and outstanding at the ex-dividend date, thus completing payment of the dividend for the financial year 2012. The total dividend per share for financial year 2012 therefore amounts to 1.08 euro per share;
the payment of the balance of the 2012 dividend amounting to 0.54 euro, payable starting from May 23, 2013, with an ex-dividend date of May 20, 2013 and a record date of May 22, 2013;
in favor of the first section of the Remuneration report regarding the company’s policy on the remuneration of board directors, general managers and executives with strategic responsibilities and the procedures used to adopt and implement this policy;
to cancel, for the portion not yet implemented as of the date of the Shareholders’ Meeting, the authorization for the Board of Directors to acquire treasury shares as resolved at the Shareholders’ Meeting of July 16, 2012;
to authorize the Board of Directors to purchase on the Mercato Telematico Azionario - in one or more transactions and in any case within 18 months from the date of the resolution - up to a maximum number of 363,000,000 ordinary Eni shares, for a price of no less than euro 1.102 and not more than the official price reported by the Borsa Italiana for the shares on the trading day prior to each individual transaction, plus 5%, and in any case up to a total amount of euro 6,000,000,000.00, in accordance with

- 1 -

the procedures established in the Rules of the Markets organized and managed by Borsa Italiana SpA. In order to respect the limit envisaged in the third paragraph of Article 2357 of the Italian Civil Code, the number of shares to be acquired and the relative amount shall take into account the number and amount of Eni shares already held in the portfolio.

Company Contacts:

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

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

- 2 -

Eni and Sonatrach reached an agreement on their gas contract

San Donato Milanese (Milan), May 28, 2013 - Eni and Sonatrach have agreed on a package solution for 2013 and 2014 within the framework of their commercial discussions under the existing gas contract.

As part of the Agreement, Eni and Sonatrach will reduce certain quantities of the contractual gas volumes delivered into Italy.

This agreement is part of the renegotiations program started in the recent months, and contributes to the announced objectives of profitability and cash generation.

Company Contacts:

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

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com

Eni: Board of Directors approves bond issue

San Donato Milanese (Milan) May 30, 2013 - Eni's Board of Directors this afternoon approved the possible issue of one or more bonds, to be placed with institutional investors, with a value of up to a maximum amount of 3 billion euro, or its equivalent in other currencies, to be issued in one or more tranches by May 30, 2014.

The bonds will enable Eni to maintain a well-balanced financial structure, in terms of short term and medium/long-term debt and average duration of the debt. The bonds may be listed on regulated markets.

Company Contacts:

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

ufficio.stampa@eni.com
segreteriasocietaria.azionisti@eni.com
investor.relations@eni.com

Web site: www.eni.com