Eni

Annual Report • May 12, 2016

Fact Book 2015

Mission

We are a major integrated energy company, committed to growth in the activities of finding, producing, transporting, transforming and marketing oil and gas. Eni men and women have a passion for challenges, continuous improvement, excellence and particularly value people, the environment and integrity.

Countries of activity

EUROPE

Austria, Belgium, Croatia, Cyprus, Czech Republic, France, Germany, Greece, Greenland, Hungary, Ireland, Italy, Luxembourg, Norway, Portugal, Romania, Slovakia, Slovenia, Spain, Switzerland, the Netherlands, the United Kingdom, Turkey, Ukraine

AFRICA Algeria, Angola, Congo, Egypt, Gabon, Ghana, Ivory Coast, Kenya, Liberia, Libya, Mozambique, Nigeria, South Africa, Tunisia

ASIA AND OCEANIA

Australia, China, India, Indonesia, Iraq, Japan, Kazakhstan, Kuwait, Malaysia, Myanmar, Oman, Pakistan, Russia, Saudi Arabia, Singapore, South Korea, Taiwan, the United Arab Emirates, Timor Leste, Turkmenistan, Vietnam

AMERICA Argentina, Canada, Ecuador, Mexico, the United States, Trinidad & Tobago, Venezuela

Eni's Fact Book is a supplement to Eni's Integrated Annual Report and is designed to provide supplemental financial and operating information. It contains certain forward-looking statements regarding capital expenditure, dividends, allocation of future cash flow from operations, evolution of financial structure, future operating performance, targets of production and sale growth, execution 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 oil&gas 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 of oil, gas and refined products; operational problems; general economic conditions; geopolitical factors including international tensions, social and political instability, changes in the economic and legal frameworks in Eni's countries of operations, regulation of the oil&gas industry, power generation and environmental field, development and use of new technologies; changes in public expectations and other changes in business

conditions; the actions of competitors.

Fact Book 2015

Contents

Eni at a glance	4
Business model	10
Targets, drivers and 2015 performance	12
Exploration & Production	17
Gas & Power	43
Refining & Marketing	51
Tables
Financial Data	61
Employees	72

Supplemental oil and gas information

73 93

Quarterly information

Eni at a glance

Eni is an integrated company that operates across the entire energy chain in 66 Countries around the world.

Eni's solid portfolio of conventional oil assets with competitive costs as well as the resource base with options for anticipated monetization, ensure high value generation from Eni's upstream activity. The large presence in the gas and LNG markets, and the commercial know-how enable the company to capture synergies and catch joint opportunities and projects in the hydrocarbon value chain. Eni's strategies, resource allocation processes and conduct of day-by-day operations underpin the delivery of sustainable value to shareholders and, more generally, to all of stakeholders, respecting the Countries where the company operates and the people who work for and with Eni. Eni's way of doing business, based on operating excellence, focus on health, safety and the environment, is committed to preventing and mitigating operational risks.

Results

In 2015, the transformation of Eni which management started in 2014 anticipating a prolonged downturn in crude oil prices, has achieved outstanding results by growing in the core oil&gas business, restructuring the industrial setup in other businesses and by improving organizational efficiency.

Adjusted1 operating profit was €4.1 billion, down by 64% (or by €7.34 billion) primarily reflecting the lower contribution from the upstream segment (down by €7.44 billion, or by 64%), due to falling commodity prices, with an impact of €8.8 billion net of currency differences, partially offset by production growth and efficiency gains of €2.2 billion while lower one-time effects associated with gas contract renegotiations negatively affected operating profit by €0.7 billion. Adjusted net profit was €0.33 billion, worsening by €3.52 billion from 2014 (down by 91%) due to a decline in operating profit and a higher tax rate driven by the impact of the scenario.

Robust cash flow generation (€12.19 billion), reduced by 15%, even in a lower Brent price scenario of 53 \$/bl, down by 47%. This cash flow, together with cash from disposals of €2.26 billion, funded a fair amount of capital expenditure for the year and the financial requirements for the dividend payments to Eni shareholders (€3.46 billion).

As of December 31, 2015, leverage was 0.31. Net borrowings was €16.86 billion. The effects of Saipem transaction reduced net debt by €4.8 billion and yielded reduction in leverage calculated on a pro-forma basis to 0.22.

Saipem disposal > On January 22, 2016, there was the closing of the agreements signed on October 27, 2015 with Fondo Strategico Italiano (FSI). Those include the sale of the 12.503% stake of the share capital of Saipem to FSI and the concurrent entrance into force of the shareholder agreement with Eni, which was intended to establish joint control over the former Eni's subsidiary. Saipem transaction is in line with Eni's strategy: (i) to become even more focused on upstream core business by making available additional financial sources to be reinvested in the development of oil and gas reserves; (ii) to strengthen Eni's balance sheet.

Versalis disposal > Negotiations are underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis SpA, would support Eni in implementing the industrial plan designed to upgrade this business.

Hydrocarbon production > 1.76 million boe/d, up by 10.1% from 2014 driven by new fields' start-ups and the continuing ramp-up of production at fields started in 2014 (adding 139 kboe/d) mainly in Angola, Venezuela, the United States and the United Kingdom, higher production in Libya and Iraq as well as the recovery of trade receivables for past investments in Iran.

(1) Non-GAAP measure. Exclude as usual the items "profit/loss on stock" and extraordinary gains and losses (special items), while they reinstate the effects relating to the elimination of gains and losses on intercompany transactions with sectors which are in the disposal phase, E&C and Chemical.

Zohr discovery > Made a world-class gas discovery at the Zohr exploration prospect in the deep waters of the Mediterranean Sea. This field is estimated to retain up to 30 trillion cubic feet of gas in place. In February 2016, the development plan was approved and first gas is expected in 2017.

Exploration successes > In 2015 Eni continued its track record of exploration successes with about 1.4 billion boe of additions to the Company's reserve backlog (vs. an initial guidance of 0.5 billion boe) at a cost of \$0.7 per barrel. In addition to the supergiant Zohr discovery, other important successes (Nkala Marine in Congo, Nooros in Egypt, Area D in Libya, Merakes in Indonesia) were near-field discoveries with quick time-to-market and immediate benefits on cash flow, in line with Eni's new exploration strategy.

Safety > In 2015 Eni continued to implement the communication and training program "Eni in safety" for all its employees. The initiative and other investments in safety supported a positive trend (down by 42.4% from 2014) in the injury frequency rate (down by 27.6% employees injury frequency rate; down by 48.6% contractors injury frequency rate) which improved for the eleventh consecutive year.

The injury severity index recorded a positive trend, reducing by 36% compared to 2014, reflecting the lower level of severity of injuries incurred by contractors.

Climate change > In 2015, Eni and the other companies joining the oil&gas Climate Initiative, in a joint declaration of collaboration confirmed their commitment in limiting the average increase of the global temperature below the two degrees threshold. Furthermore, Eni together with other five oil&gas European companies asked the United Nations Framework Convention on Climate Change (UNFCCC) and the COP21, to introduce the systems to define a cost for GHG emissions leveraging on clear, stable and more ambitious regulatory framework. These will also be useful to harmonize different national systems.

Sustainability indexes > Eni's place on the Dow Jones Sustainability World Index was confirmed for the ninth consecutive year. The index features companies that are distinguished by their excellent performance in all the fields of sustainability. Eni's inclusion was also confirmed on the FTSE4Good, one of the world's most prestigious corporate social responsibility stock-market indexes. This reflects Eni's excellent performance in environmental sustainability, respect for human rights, corporate governance and transparency, relationships with stakeholders.

Strategy

Starting from the second half of 2015, the oil price reported a significant contraction, falling below 30 \$/bl in January 2016. In the 2016-2019 plan period, the oil price is expected to rise gradually to 65 \$/bl by 2019 following progressive rebalancing of the market.

In such context, the strategy was defined taking into account three different time horizons:

• The short-term, by pursuing cash flow maximization to safeguard financial robustness while raising efficiency and accelerating initiatives aimed at cost reduction;
• The medium-term, by means of the focus on investments aimed to develop the significant resources in the portfolio, characterized by low break even, as to guarantee the reserves' replacement and production growth;
• The long-term, by creating the basis for the society to get ready for the low-carbon energy environment.

In the short and medium term, the main goal of cash generation will be pursued by means of specific industrial initiatives in Eni's businesses, selective investments mainly in the Exploration & Production segment and further initiatives of costs reduction. In particular, the definition of the capex plan leveraged on the high-value projects with accelerated rates of return: in the 2016-2019 plan, capital expenditure plan of €37 billion is 21% lower compared to the previous plan, at constant foreign exchange rate. The reduction is mainly due to the Exploration & Production segment, in spite of the additional spending for the Shorouk discovery (Egypt) while benefiting from projects' rephasing/ reconfiguration and contracts' renegotiations.

The 2016-2019 divestment plan amounts to approximately €7 billion, before taxation and excluding Saipem transaction, stemming from anticipated monetization of exploratory discoveriesas well as further refocusing of activities on the core business.

The combined effect of the industrial actions for the development of the Exploration & Production segment, restructuring of the mid and downstream businesses and widespread initiatives of spending review will allow to reduce significantly the Brent break-even level with a cash neutrality (including dividend floor) at 60 \$/bl by 2017.

Dividend policy

Despite the worsening scenario, considering Group's transformation process and Eni strategic goals, the Company will propose a dividend of €0.8 per share in 2016.

Performance and goals

Thanks to the transformation process implemented by our management, nowadays Eni can leverage on an excellent competitive positioning, further strengthened by our recent exploration successes, a robust pipeline of projects and a solid financial structure to withstand the downturn from a strong base.

The actions defined in the 2016-2019 strategic plan are able to combine the necessity for efficiency, spending selection and financial discipline with those of the profitable and sustainable growth in core oil&gas business, creating the fundamentals for a robust recovery of profitability even in a very difficult environment like the current one.

Hereunder are reported the main strategic pillars identified by Eni's management, the results achieved in 2015 thanks to the implemented transformation process and the 2016-2019 targets.

Strategic pillars	2015 Achievements	2016-2019 Plan
Efficient and valuable growth	- Hydrocarbon production: +10.1%	- Hydrocarbon production: >+3%
	- Upstream capex: €10.2 bln	- Upstream capex: -18% vs previous plan
	- Exploration resources: 1.4 bln boe @ \$0.7/boe	- Exploration resources: 1.6 bln boe @ \$2.3/boe
Restructuring	- G&P: adjusted EBIT almost at break-even	- G&P: adjusted EBIT in structural break-even from 2017
	- R&M: return to profitability	- R&M: adjusted operating profit at €0.7 bln in 2019
	- Refining margin break-even: \$5/bl	- Refining margin break-even at \$3/bl
	- G&A savings: €0.6 bln	- Cumulative G&A savings: €2.5 bln through 2019
Transformation	- Disposals: €7 bln including Saipem transaction	- Disposal target: €7 bln

Main data

Key financial data(a)(b)	(€ million)	2011	2012	2013	2014	2015
Net sales from operations - continuing operations		107,690	127,109	98,547	93,187	67,740
Operating profit (loss) - continuing operations		16,803	15,208	7,867	7,585	(2,781)
Special items		1,540	4,692	2,910	1,572	5,762
Profit (loss) on stock		(1,113)	(17)	503	1,290	814
Adjusted operating profit (loss)- continuing operations		17,230	19,883	11,280	10,447	3,795
Exploration & Production		16,075	18,537	14,643	11,551	4,108
Gas & Power		(247)	398	(622)	168	(126)
Refining & Marketing		(539)	(289)	(472)	(65)	387
Chemicals		(273)	(483)
Engineering & Construction		1,443	1,485
Corporate and other activities		(492)	(547)	(542)	(443)	(369)
Impact of unrealized intragroup profit elimination and consolidation adjustments		1,263	782	(1,727)	(764)	(205)
Group net profit (loss)(*)		6,860	7,790	5,160	1,291	(8,783)
of which: continuing operations		6,902	4,200	3,472	101	(7,680)
discontinued operations		(42)	3,590	1,688	1,190	(1,103)
Group adjusted net profit (loss)(*)		6,969	7,325	4,430	3,707	436
of which: continuing operations		6,938	7,130	2,499	2,200	(698)
discontinued operations		31	195	1,931	1,507	1,134
Net cash provided by operating activities		14,382	12,567	11,026	15,110	11,903
of which: continuing operations		13,763	12,552	9,132	13,162	11,181
discontinued operations		619	15	1,894	1,948	722
Capital expenditure		13,438	13,561	12,800	12,240	11,556
of which: continuing operations		11,909	12,805	11,584	11,264	10,775
discontinued operations		1,529	756	1,216	976	781
Shareholders' equity including non-controlling interest		60,393	62,417	61,049	62,209	53,669
Net borrowings		28,032	15,069	14,963	13,685	16,863
Leverage		0.46	0.24	0.25	0.22	0.31
Net capital employed		88,425	77,486	76,012	75,894	70,532
of which: Exploration & Production		42,024	42,369	45,699	47,629	50,522
Gas & Power		12,367	10,597	8,462	9,031	5,803
Refining & Marketing		9,188	8,871	8,737	6,738	5,492

(a) Following the divestment plan of Saipem and Versalis, the two operating segments E&C and Chemical have been classified as discontinued operations based on the guidelines of IFRS 5.

2013 and 2014 data have been restated consistently.

(b) 2011 and 2102 results measure as discontinued operations only Regulated Businesses in Italy, divested in 2012.

(*) Attributable to Eni's shareholders.

Key market indicators	2011	2012	2013	2014	2015
Average price of Brent dated crude oil(a)	111.27	111.58	108.66	98.99	52.46
Average EUR/USD exchange rate(b)	1.392	1.285	1.328	1.329	1.110
Average price in euro of Brent dated crude oil	79.94	86.83	81.82	74.48	47.26
Standard Eni Refining Margin (SERM)(c)	1.82	4.12	2.43	3.21	8.32
Euribor - three-month euro rate (%)	1.40	0.60	0.22	0.21	(0.02)

(a) In US dollars per barrel. Source: Platt's Oilgram.

(b) Source: ECB.

(c) In USD per barrel. Source: Eni calculations. It gauges the profitability of Eni's refineries against the typical raw material slate and yields.

Eni at a glance Main data

Selected operating data		2011	2012	2013	2014	2015
Corporate(a)
Employees at period end(*)	(number)	72,574	79,405	30,970	29,403	29,053
of which: - women(**)		12,542	12,847	7,504	7,370	7,254
- outside Italy		45,516	52,008	13,343	12,672	12,333
Female managers(**)	(%)	18.5	18.9	23.5	23.8	24.2
Employee injury frequency rate	(No. of accidents per million of worked hours)	0.65	0.57	0.28	0.29	0.21
Contractor injury frequency rate		0.57	0.45	0.49	0.35	0.18
Fatality index	(Fatal injuries per one hundred millions of worked hours)	1.94	1.10	0.00	1.08	0.39
Oil spills due to operations	(bbl)	7,295	3,759	1,762	1,161	1,603
GHG emission	(mmtonnes CO2 eq)	49.1	52.8	43.9	38.9	38.5
R&D expenditures(b)	(€ million)	190	211	142	134	139
Expenditure for the territory(c)	(€ million)	101	91	100	96	97
Exploration & Production
Net proved hydrocarbons reserves	(mmboe)	7,086	7,166	6,535	6,602	6,890
Reserve life index	(years)	12.3	11.5	11.1	11.3	10.7
Liquids production	(kbbl/d)	845	882	833	828	908
Natural gas production	(mmcf/d)	4,320	4,501	4,320	4,224	4,681
Hydrocarbons production	(kboe/d)	1,581	1,701	1,619	1,598	1,760
Gas & Power
Sales of consolidated companies (including own consumption)	(bcm)	84.37	84.30	83.60	81.73	84.94
Sales of Eni's affiliates (Eni's share)		9.53	8.29	6.96	4.38	2.78
Total sales and own consumption (G&P)		93.90	92.59	90.56	86.11	87.72
E&P gas sales in Europe and in the Gulf of Mexico		2.86	2.73	2.61	3.06	3.16
Worldwide gas sales		96.76	95.32	93.17	89.17	90.88
Electricity sold	(TWh)	40.28	42.58	35.05	33.58	34.88
Refining & Marketing
Refinery throughputs on own account	(mmtonnes)	31.96	30.01	27.38	25.03	26.41
Balanced capacity of wholly-owned refineries	(kbbl/d)	767	767	787	617	548
Sales of refined products	(mmtonnes)	45.02	48.33	35.41	34.59	35.24
Retail sales of refined products in Europe		11.37	10.87	9.69	9.21	8.89
Service stations at year end	(units)	6,287	6,384	6,386	6,220	5,846
Average throughput of service stations in Europe	(kliters/y)	2,206	2,064	1,828	1,725	1,754

(a) Pertaining to continuing operations. Following the divestment plan of Saipem and Versalis, data for the year 2015 do not include the contribution of the divested segments. 2013 and 2014 results have been restated consistently. 2011 and 2012 data do not include the contribution of Regulated Businesses in Italy, divested in 2012.

(b) Net of general and administrative costs.

(c) Includes investments for local communities, charities, association fees, sponsorships, payments to Fondazione Eni Enrico Mattei and Eni Foundation.

(*) See page 72 for details on employees by business segments.

(**) Do not include employees of equity accounted entities.

Share data		2011	2012	2013	2014	2015
Net profit (loss)(a)(b)(*)	(€)	1.90	1.16	0.96	0.03	(2.13)
Dividend		1.04	1.08	1.10	1.12	0.80
Cash dividends to Eni's shareholders(c)	(€ million)	3,695	3,840	3,949	4,006	3,457
Cash flow(*)	(€)	3.97	3.41	3.20	3.65	3.10
Dividend yield(d)	(%)	6.6	5.9	6.5	7.6	5.7
Net profit (loss) per ADR(a)(e)(*)	(USD)	5.29	2.98	2.55	0.08	(4.73)
Dividend per ADR(e)		2.73	2.82	2.99	2.65	1.77
Cash flow per ADR(e)		11.05	8.77	8.49	9.69	6.89
Dividend yield per ADR(d)(e)	(%)	6.6	5.9	6.5	7.6	5.7
Pay-out		55	50	80	313	(33)
Number of shares at period-end	(million)	4,005.4	3,634.2	3,634.2	3,634.2	3,634.2
Average number of share outstanding in the year(f) (fully diluted)		3,622.7	3,622.8	3,622.8	3,610.4	3,601.1
TSR	(%)	5.1	22.0	1.3	(11.9)	1.1

(*) Pertaining to continuing operations. Following the divestment plan of Saipem and Versalis, the two operating segments E&C and Chemical have been classified as discontinued operations based on the guidelines of IFRS 5. 2013 and 2014 reporting periods have been restated consistently. 2011 and 2102 results measure as discontinued operations Regulated Businesses in Italy, divested in 2012.

(a) Calculated on the average number of Eni's shares outstanding during the year.

(b) Pertaining to Eni's shareholders.

(c) The amount of dividends for the year 2015 is based on the Board's proposal.

(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.

Share information		2011	2012	2013	2014	2015
Share price - Milan Stock Exchange
High	(€)	18.42	18.70	19.48	20.41	17.43
Low		12.17	15.25	15.29	13.29	13.14
Average		15.95	17.18	17.57	17.83	15.47
Year end		16.01	18.34	17.49	14.51	13.80
ADR price(a) - New York Stock Exchange
High	(USD)	53.74	49.44	52.12	55.30	39.29
Low		32.98	36.85	40.39	32.81	29.28
Average		44.41	44.24	46.68	47.37	34.31
Year end		41.27	49.14	48.49	34.91	29.80
Average daily exchanged shares	(million shares)	22.85	15.63	15.44	17.21	20.30
Value	(€ million)	355.0	267.0	271.4	304.0	312.0
Weighted average number of shares outstanding(b)	(million shares)	3,622.7	3,622.8	3,622.8	3,610.4	3,601.1
Market capitalization(c)
EUR	(billion)	58.0	66.4	63.4	52.4	50.2
USD		75.0	87.7	87.4	63.6	55.7

(a) One ADR represents 2 Eni's shares.

(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	(€/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	(million shares)		1.9	15.0	24.4	39.6
Percentage of share capital(a)	(%)	15.0	16.2	18.2	15.2	5.0
Proceeds	(€ million)	3,254	4,596	6,869	6,714	2,721

(a) Refers to share capital at December 31, 2015.

Business model

Eni's business model targets long-term value creation for its stakeholders by delivering on profitability and growth, efficiency and operational excellence and handling operational risks of its businesses, as well as environmental conservation, and local communities relationships, preserving health and safety of people working in Eni and with Eni, in respect of human rights, ethics and transparency. The main capitals used by Eni (financial capital, productive capital, intellectual capital, natural capital, human capital, social and relationship capital) are classified in accordance with the criteria included in the

"International IR Framework" published by the International Integrated Reporting Council (IIRC). Robust 2015 financial results and sustainability performance, notwithstanding a weak scenario for commodities prices, rely on the responsible and efficient use of our capitals. Hereunder is articulated the map of the main capitals exploited by Eni and actions positively effecting on their quality and availability. At the same time, the scheme evidences how the efficient use of capitals and related connections create value for the company and its stakeholders.

	stock of capital	Eni's main actions	value creation for Eni	value creation for Eni's stakeholders
financia capital	- Financial structure - Liquidity reserves	- Cash flow from operations - Bank loans - Bonds - Maintaining strategic liquidity - Hedging - Dividends - Working capital optimization	- Going concern - Lower cost of capital - Reduction of working capital - Leverage optimization - M&A opportunities - Mitigation of market volatility - Credit worthiness	- Yields - Share price appreciation - Social and economical growth - Satellite activities
productive capital	- Onshore and offshore plants - Pipelines and storage plants - Liquefaction plants - Refineries - Distribution networks - Power plants - Buildings and other equipment - Hydrocarbon reserves [Oil and gas]	- Technological upgrade - Process upgrade - Investment in new businesses (biorefinery, car sharing) - Maintenance and development activities - Increase environment Certifications (ISO 14001, ISO 50001, EMAS, etc.)	- Returns - Enlarging asset portfolio - Increase assets value - Reduction of operational risk - Energy and operational efficiency - Reputation - Hydrocarbon reserves growth	- Availability of energy sources and green products - Employment - Satellite activities - Reduction of direct GHG emissions and responsible use of resources
intellectual capital	- Technologies and intellectual property - Corporate internal procedures - Corporate governance system - Integrated risk management - Management and control systems - Knowledge management - ICT (Green Data Center)	- Research and development expenditures - Partnership with centres of excellence - Development of proprietary technologies and patents - Application of procedures and systems - Audit	- Competitive advantage - Risk mitigation - Transparency - Performance - License to operate - Stakeholders' acceptability	- Reduction of environmental and social impacts - Transfer of best available technologies and know-how to host Countries - Contribution to the fight against corruption - Green products
human capital	- Health and safety of people - Know-how and skills - Experience - Engagement - Diversity (gender, seniority, geographical) - Eni's thinking	- Safety at work - Recruiting, education and training on the job - Promotion of human rights - Eni's people engagement - Knowledge management - Welfare - Leveraging on diversity - Enhancing individual talents and remuneration in accordance to a merit system	- Performance - Efficiency - Competitiveness - Innovation - Risk mitigation - Reputation - Talent attraction - Job enhancement - Career development	- Create employment and preserve jobs - Job enhancement - Wellness of Eni's people and local communities - Increase and transfer know-how
social and relationship capital	- Relationship with stakeholders (institutions, governments, communities, associations, customers, suppliers, industrial partners, NGO, universities, trade unions) Eni brand	- Stakeholders' Engagement - MoU with Governments and local authorities - Projects for local development and Local content - Strategic partnerships - Involvement in international panel discussion - Development of programmes on research and training - Partnerships with trade unions - Quality of services rendered - Brand management	- Operational & social licence - Reduction of time-to-market - Country risk reduction - Market share - Alignment to international best practices - Reputation - Competitive advantage - Suppliers reliability - Customers retention	- Local socio-economical development - Customers and suppliers satisfaction - Share of expertise with territories and communities - Satisfaction and incentive of people - Promoting respect for workers' rights
natura capital	- Oil and gas reserves - Water - Biodiversity and ecosystems - Air - Soil	- Exploration, production, transporting, refining and distributing hydrocarbons - Investment in new businesses (biorefinery, car sharing) - Investment in technological and process upgrade - Remediation activities - Investment in alternative energy sources	- Hydrocarbon reserves growth - Opex reduction - Mitigation of operational risk (asset integrity) - Reputation - License to operate - Stakeholders' recognition	- Reduction of gas flared - Reduction of oil spill - Reduction of blow out risk - Preservation of biodiversity - Green products - Containment of water consumption (reinjection and water reuse) - Energy efficiency

Targets, drivers and 2015 performance

The table below shows how actions taken in managing each main capital, contribute to achieve business targets.

The different actions are classified on the basis of four strategic targets which lead Eni's business segments.

The actions reported below represent the management system of

each capital which allow to achieve business goals, on the one hand reducing risks, on the other,increasing profitability.

In particular, are highlighted the connection between actions carried on Upstream business, capitals used by Eni and financial/non financial results reported in 2015.

The following pages contain additional details about the most relevant financial and non-financial KPI: for each strategic target are valued those indicators which express the use each capital

employed by Eni (financial, productive, intellectual, human, social and relationship, natural) in order to achieve the business strategy.

	- Fuel value and increase explorative resources - Growth in upstream cash generation	- Profitability and sustainable cash generation in the Gas & Power segment	- Ebit adjusted and free cash flow steadily positive in the Refining & Marketing segment	- Focus on efficiency
financial capital	- Investment selectivity - Reduction of opex and G&A costs - Reduction of exposure to partners / National Companies - Reduction of time-to-market	Gas contracts portfolio restructuring - Working capital optimization - Simplifying the operations and optimization of logistic costs Recover in profitability and optimization of B2B contracts	- Investment selectivity - Opex reduction	- Capex reduction - G&A costs reduction - Working capital optimization
productive capital	- Renewal of exploration portfolio - HPC computing center - Proprietary instruments for seismic activity - Production growth - Operatorship - Project execution optimization - Asset integrity - Portfolio management (assets) - Power generation projects from renewable sources	Continental hub monitoring Enhancing Asset Back Trading - Upstream integration and increasing value of gas projects Power plants optimization - Monitoring developments in regulation	- Critical sites reconversion/rationalization - Promotion of energy efficiency	- Process optimization - Lean Organization
intellectual capital	- R&D investments - Proprietary technologies development and patents management Development of technologies to increase the recovery rate	Take-or-pay risk integrated management Development of innovative products and services Evolution in processes and systems	- R&D investments - Business innovation - Research applied in the green business	- Proprietary technologies development and patents management - Continuous improvement - Change management
human capital	- Safety in the workplace - Knowledge management - Recruitment, education and training on the job - Internal know-how enhancement - Promotion of human rights and integrity culture	Safety in the workplace Reorganization/streamlining operations - Internal know-how enhancement - Change management	- Safety in the workplace - Internal know-how enhancement - Job rotation - Development of new skills	- Safety in the workplace - Involvement of employees - Internal know-how enhancement - Activity insourcing
relationship capital	- Partnerships with governments and local authorities - Territorial development and local content projects - Increase in access to energy - Respect of human rights - Promotion of transparency	Gas advocacy Relationship with customers and suppliers - Know-how in negotiations	- Dialogue with trade unions - Local stakeholders management	- Dialogue with trade unions Stakeholders management
natural capital	- Increase of oil&gas reserves - Oil spill reduction - Reduction of GHG emissions - Blowout reduction through optimization of upstream operations - Gas valorization targeting for zero gas flaring Biodiversity protection concible areas	Energy efficiency initiatives Promotion of energy efficiency among customers	- Investments in biorefining - Promotion of energy efficiency	- Promotion of energy efficiency - Efficient use of resources

2015 performance(*)

	Fuel value and increase explorative resources and growth in upstream cash generation
			2013	2014	2015
Financial capital	Capital expenditure	(€ million)	10,475	10,524	10,234
	Opex per boe	(\$/boe)	8.3	8.4	7.2
	Cash flow per boe	(\$/boe)	31.9	30.1	20.1
	Proved hydrocarbon reserves	(mmboe)	6,535	6,602	6,890
Productive capital	Reserves life index	(years)	11.1	11.3	10.7
	Organic reserves replacement ratio	(%)	105	112	148
	Direct GHG emission	(million tonnes CO2 eq)	27.4	23.4	22.8
Natural capital	- of which CO2 eq from flaring		9.13	5.73	5.51
	CO2 eq emissions/100% operated hydrocarbon gross production	(tonnes CO2 eq/kboe)	31.8	27.5	25.0
	Volume of hydrocarbons sent to process flaring	(mmcm/d)	9.10	4.60	4.28
	Oil spills due to operations (>1 bbl)	(bbl)	1,728	936	1,146
	Produced water re-injected	(%)	55	56	56
Social and relationship capital	Investments on territories following agreements, conventions and PSA (community investment)	(€ million)	53	63	71
Intellectual capital	Existing patents	(number)	2,370	2,016	2,088
	First patent filing applications		8	15	8
Human capital	Employees at year end	(number)	12,352	12,681	12,728
	Employees outside Italy		8,219	8,147	8,156
	- of which locals Female employees		6,476 2,442	6,441 2,462	6,266 2,453
	Number of hiring		1,324	681	387
	Injury frequency rate of total workforce	(No. of accidents per million worked hours)	0.23	0.23	0.13
	Safety expenditure and expenses	(€ million)	150	100	190
	No. employees assessment during the year/No. planned assessment for the year	(%)	79	53	66
	Employees covered by performance assessment tools (senior managers,
	managers/supervisors and young graduates)		65	62	63
	Training expenditure	(€ million)	44.4	29.0	17.6
	Profitability and sustainable cash generation in the Gas & Power segment
			2013	2014	2015
capital	Adjusted operating profit (loss)	(€ million)	(622)	168	(126)
Financial	Operating expenses reduction Capital expenditure	(%) (€ million)	(10) 229	(15) 172	(28) 154
	Worldwide gas sales	(bcm)	93.17	89.17	90.88
capital	LNG sales		12.4	13.3	13.5
Productive	Customers in Italy	(million)	8.00	7.93	7.88
	Electricity sold	(TWh)	35.05	33.58	34.88
	Direct GHG emissions	(million tonnes CO2 eq)	11.3	10.1	10.6
Natural capital	CO2 eq emissions/kWheq (EniPower)	(gCO2 eq/kWheq)	408.78	410.67	410.09
	Power generation (EniPower) emissions/kWheq (EniPower)	(TWh) eq/KWheq)	23.14 0.16	21.04 0.15	22.34 0.14
	NOx emissions/kWheq (EniPower)	(gNO2 eq/kWheq)	0.017	0.001	0.001
	SOx Water withdrawals/kWeq produced (EniPower)	(gSO2 (cm/kWheq)	0.017	0.017	0.015
Social and relationship capital	Customer satisfaction rate	(scale from 0 to 100)	80.0	81.4	85.6
Intellectual capital	Existing patents	(number)	56	43	7
	Employees at year end	(number)	4,791	4,469	4,388
capital	Employees outside Italy		2,550	2,437	2,402
Human	Female employees		1,537	1,411	1,363
	Number of hiring		226	116	131
	Injury frequency rate of total workforce	(No. of accidents per million worked hours)	1.32	0.46	0.49
	Safety expenditure and expenses	(€ million)	9	7	7
	Employees covered by performance assessment tools (senior managers,	(%)	63	72	69
	managers/supervisors and young graduates) Training hours	(number) 147,011		92,701	98,579

(*) The data related to employees do not include the companies consolidated with the proportional method. For details about the employees for segment, coherent with the consolidation perimeter of the Relationship Financial Annual 2015, see at page 72.

	Ebit adjusted and free cash flow steadily positive in the Refining & Marketing segment
			2013	2014	2015
Financial capital	Adjusted operating profit (loss)	(€ million)	(472)	(65)	387
	Refining break-even margins	(\$/bl)		6	5
	Refining capital expenditure	(€ million)	462	362	282
	Service stations in Europe at year end	(number)	6,386	6,220	5,846
Productive capital	Balanced capacity of refineries	(kbbl/d)	787	617	548
	Average plant utilization rate	(%)	66	78	95
	Direct GHG emissions	(million tonnes CO2 eq)	5.2	5.3	5.1
Natural capital	GHG emissions/refining throughputs(a)	(tonnes CO2 eq/kt)	252.08	286.92	237.39
	SOx emissions/refining throughputs(a)	(tonnes SO2 eq/kt)	0.53	0.32	0.29
	SOx emissions	(ktonnes SO2 eq)	10.80	5.70	5.97
Social and relationship capital	Customer satisfaction index	(likert scale)	8.1	8.2	8.3
	Customers involved in the satisfaction survey	(number)	29,863	24,081	23,628
Intellectual capital	Existing patents	(number)	839	662	648
	First patent filing applications		6	16	4
Human capital	Employees at year end	(number)	6,469	5,823	5,234
	Female employees		1,176	1,045	911
	Injury frequency rate of total workforce	(No. of accidents per million worked hours)	1.05	0.89	0.80
	Safety expenditure and expenses	(€ million)	43	31	27
	Employees covered by performance assessment tools (senior managers, managers/supervisors and young graduates)	(%)	48	40	51
	Training hours	(number)	244,279	163,321	157,321
	Training expenditure	(€ million)	3.3	2.5	1.9

Focus on efficiency

			2013	2014	2015
Financial capital	Capital expenditure	(€ million)	11,584	11,264	10,775
	Changes in working capital		121	2,148	4,450
	Purchases, services and other		78,108	74,067	53,983
	Net consumption of primary resources		(toe) 11,675,939 10,606,496		10,910,143
Natural capital	- of which: natural gas		9,809,086	9,107,522	9,245,994
	- of which: oil products			1,767,269 1,423,944	1,572,924
	- of which: other fuels		99,583	75,030	91,225
	Energy consumptions from productive activities/100% operated hydrocarbon gross production	(GJ/toe)	1.54	1.67	1.62
	Energy Intensity Index (R&M)	(%)	76.0	77.8	79.9
	Total water withdrawals	(mmcm)	1,193	1,037	872
Human capital	Days of absence due to accidents - Total workforce	(number)	4,418	3,988	2,312
	Total employment disputes		869	864	959
	Disputes/employees ratio		326/869	370/864	470/959

Targets, drivers and 2015 performance

Other significant performances

			2013	2014	2015
	Members of Eni's Board of Directors	(number)	9	9	9
Governance	- executive		1	1	1
	- non executive		8	8	8
	- indipendent(a)		7	7	7
	- non indipendent		2	2	2
	- members of minorities		3	3	3
	Presence of women in the Board of Directors of Eni Group companies	(%)	17	26	27
	Presence of women in the Board of Statutory Auditors of Eni Group companies		29	35	34
Human capital	Employees at year end	(number)	29,176	28,597	28,246
	- men		21,672	21,227	20,992
	- women		7,504	7,370	7,254
	Local employees abroad by professional category		10,510	10,442	9,975
	- of which senior manager		97	83	71
	- of which manager/supervisors		1,849	1,883	1,869
	- of which employees		6,150	6,181	5,902
	- of which workers		2,414	2,295	2,133
	Female managers (senior manager and manager/supervisors)	(%)	23.5	23.8	24.2
	Injury frequency rate of total workforce	(No. of accidents per million worked hours)	0.43	0.33	0.19
	Employees injury frequency rate	(No. of accidents per million worked hours)	0.28	0.29	0.21
	Contractors injury frequency rate	(No. of accidents per million worked hours)	0.49	0.35	0.18
	Fatality index of total workforce	(Fatality injuries per one hundred millions of worked hours)	0.00	1.08	0.39
	Total Recordable Injury Rate of employees	(Total recordable injuries/worked hours) x 1,000,000	0.41	0.35	0.34
	Total Recordable Injury Rate of contractors	(Total recordable injuries/worked hours) x 1,000,000	0.90	0.75	0.43
	Total Recordable Injury Rate of workforce	(Total recordable injuries/worked hours) x 1,000,000	0.75	0.62	0.40
	Safety expenditure and expenses	(€ million)	205	143	239
	Training hours	(khours)	1,493	1,032	915
	Training expenditure	(€ million)	54.63	37.15	27.51
	Total spending for the territory	(€ million)	100	96	97
Social and	Suppliers used	(number)	13,573	11,342	9,268
	Total procurement	(€ million)	19,043	22,955	19,514
relationship capital	Suppliers subjected to qualification procedures including screening on Human Rights	(number)	2,434	3,846	2,806
	SA8000 Audits carried out		23	20	16(b)
	Eni security personnel trained on Human Rights		235	143	61
	Security contracts containing clauses on Human Rights	(%)	83	95	85
	R&D expenditure(c)	(€ million)	142	134	139
Intellectual capital	First patent filing applications	(number)	35	50	22
	- of which filing of renewable energy		21	17	11
	Existing patents		3,644	3,056	3,162
Natural capital	Direct total GHG emissions	(million tonnes CO2 eq)	43.9	38.9	38.5
	NOx emissions	(tonnes NO2 eq)	74,657	62,238	66,523
	SOx emissions	(tonnes SO2 eq)	22,062	19,124	10,501
	NMVOC (Non Methan Volatile Organic Compounds) emissions	(tonnes)	39,060	22,664	17,227
	TSP (Total Suspended Particulate) emissions		2,103	1,578	1,763
	Total number of oil spills (> 1 bbl)	(number)	382	362	247
	Total volume of oil spills (> 1 bbl)	(bbl)	7,764	15,562	16,450
	- from sabotage		6,002	14,401	14,847
	- due to operations		1,762	1,161	1,603
	Total water withdrawals	(mmcm)	1,193	1,037	872
	- of which sea water - of which fresh water		1,114 61	968 59	801 58
	- of which salt/salty water taken from underground or surface sources		18	10	13

(a) This refers to independence according to law, mentioned by Eni Statute; 6 out 9 directors are indipendent pursuant to Code of Self-regulation.

(b) Data include SA800 Audits of 8 suppliers/sub-suppliers that were performed in Ecuador, Vietnam, Algeria and Ghana as well as 8 follow-ups of audits performed in 2014 in Mozambique, Indonesia, Angola and Pakistan.

Key performance indicators

		2013	2014	2015
Injury frequency rate of total workforce	(No. of accidents per million of worked hours)	0.23	0.23	0.13
Net sales from operations(a)	(€ million)	31,264	28,488	21,436
Operating profit (loss)		14,868	10,766	(144)
Adjusted operating profit (loss)		14,643	11,551	4,108
Adjusted net profit (loss)		5,950	4,423	752
Capital expenditure		10,475	10,524	10,234
Profit per boe(b)(c)	(\$/boe)	16.1	13.8	7.4
Opex per boe(b)		8.3	8.4	7.2
Cash Flow per boe(d)		31.9	30.1	20.1
Finding & Development cost per boe(c)(d)		19.2	21.5	19.3
Average hydrocarbons realizations(d)		71.87	65.49	36.47
Production of hydrocarbons(d)	(kboe/d)	1,619	1,598	1,760
Estimated net proved reserves of hydrocarbons(d)	(mmboe)	6,535	6,602	6,890
Reserves life index(d)	(years)	11.1	11.3	10.7
Organic reserves replacement ratio(d)	(%)	105	112	148
Employees at period end	(number)	12,352	12,777	12,821
of which: outside Italy		8,219	8,243	8,249
Oil spills due to operations (>1 barrel)	(bbl)	1,728	936	1,146
Produced water re-injected	(%)	55	56	56
Direct GHG emissions	(mmtonnes CO2 eq)	27.4	23.4	22.8
of which: CO2 eq from flaring		9.13	5.73	5.51
Community investment	(€ million)	53	63	71

(a) Before elimination of intragroup sales.

(b) Consolidated subsidiaries.

(c) Three-year average.

(d) Includes Eni's share of equity-accounted entities.

Performance of the year

• ›In 2015, safety performance continued on a positive trend, reporting a further improvement in injury frequency rate of total workforce (down by 44%). Eni is engaged in maintaining a high safety standard in each of its operations leveraging also on continuous HSE awareness programs.
• › Greenhouse gas emissions decreased by 2.8% compared to the previous year (with a -3.9% reduction in emissions from flaring). Continuous improvements in energy efficiency, streamline logistics and emissions reduction more than offset the hydrocarbon production growth (performance indicator CO2 eq emissions/ hydrocarbons production down by 9.1% from 2014). In the year, the flaring down project of the M'Boundi field (Eni operator with an 83% interest), started up in 2014, received the Excellence award of World Bank Global Gas Flaring Reduction within Zero Routine Gas Flaring 2030 program due to significant emissions reduction.
• › Water reinjection continues to achieve an excellent industry performance (56% in 2015) and we recorded zero blow-outs for the twelfth consecutive year.
• ›In 2015 the E&P segment reported a decline of €3,671 million or 83% in adjusted net profit compared to a year ago, due to lower realization on commodities in dollar terms (down by 44.3% on

average) reflecting the fall of Brent crude benchmark and the weakness of gas markets in Europe and in the United States.

• › Oil and natural gas production was 1.760 million boe/d in 2015, up by 10.1% compared to the previous year and to a 5% target, the highest increase rate since 2001. Production ramp-up at fields started in the year will add approximately 200 kboe/d in 2016.
• › Estimated net proved reserves at December 31, 2015 amounted to 6.9 bboe based on a reference Brent price of \$54 per barrel. The organic reserves replacement ratio was 148% (135% on average since 2010). The reserves life index was 10.7 years (11.3 years in 2014).

Exploration activity

› Additions to the Company's reserve backlog were approximately 1.4 billion boe of resources, at a competitive cost of \$0.7 per barrel (compared to a target of 500 million boe at a cost not higher than \$2 per boe), particularly near-field discoveries with quick time-to-market and immediate cash flow and appraisal campaign of recent discoveries to support production level. The main discoveries were made:

• Egypt, with a world-class gas discovery at the Zohr exploration prospect (Eni's interest 100%) in the deep waters of the Mediterranean Sea. This field is estimated to retain 30 trillion cubic feet of gas in place and an accelerated fast track development leveraging on the existing offshore and onshore facilities is planned. In February 2016, Egyptian authorities approved the development plan of the Zohr discovery. First gas is expected in 2017;
• Congo, where the exploration activities of the pre-salt sequences in the Marine XII block (Eni operator with a 65% interest) continue to deliver new discoveries and confirm Eni's exploration technologies effectiveness, given the technical complexity of these plays. Eni estimates the oil and gas resources in place of the Marine XII block at approximately 5.8 billion boe. The production of the block currently flows at approximately 15 kboe/d;
• Libya, with gas and condensates discoveries in the contractual area D (Eni's interest 50%);
• Other exploration successes were made in Egypt, Pakistan, Indonesia and the United States.
• ›In Angola, signed a three-year extension of the exploration period of the operated Block 15/06 (Eni's interest 36.84%), where the first oil from the West Hub development project was achieved at the end of 2014.
• ›In March 2016, Eni signed a Farm-Out Agreement (FOA) with Chariot oil&gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco. The completion of this FOA is subject to the authorization of the Moroccan authorities, to current partners' approval and other conditions precedent.
• › Entrance into the upstream sector of Mexico by signing the Production Sharing Contract as operator of the Block 1 (Eni's interest 100%) to develop the Amoca, Miztón and Tecoalli fields. These fields located in the Gulf of Mexico shallow waters are estimated to retain 800 million barrels of oil and 480 billion cubic feet of gas in place. The delineation campaign of the fields was submitted to the Mexican authorities in the first quarter of 2016 and plans the drilling of four wells in order to define a fast track and synergic development plan.
• › Signed a preliminary agreement with KazMunayGas to acquire 50% of the mineral rights in the Isatay block in the Caspian Sea.
• ›The exploration portfolio was renewed by means of new exploration acreage covering approximately 21,500 square kilometres net to Eni in particular in Egypt, Myanmar, the United Kingdom and Ivory Coast as well as Mexico, as mentioned above.
• ›In 2015 exploration expenditure amounted to €820 million, mainly related to the completion of the 29 new exploratory wells (19.1 net to Eni). An overall commercial success rate was 16.7% (25.1% net to Eni). In addition, 80 exploratory drilled wells are in progress at year end (41.6 net to Eni).

Sustainability and portfolio developments

• › As planned, in 2015, Eni achieved the start-up of 10 major new fields with 139 kboe/d of new production, of which the most significant were:
• the giant Perla gas field (Eni's interest 50%) offshore Venezuela, retaining a potential of up to 17 Tcf of gas in place (or 3.1 billion

boe). A production plateau of approximately 1,200 mmcf/d is expected by 2020. Gas is sold to the national oil and gas company PDVSA under a Gas Sales Agreement running until 2036;

• the Cinguvu field, part of the West Hub Development phased project in Block 15/06 offshore Angola. In addition, early in 2016 the third M'Pungi satellite field came on stream achieving an overall plateau of 25 kbbl/d net to Eni;
• the Nené Marine and Litchendjili fields in the block Marine XII (Eni operator with a 65% interest) in Congo. The overall production plateau is estimated in 40 kboe/d for the next four-years;
• the Kizomba satellites Phase 2 project (Eni's interest 20%) off Angola, with a peak production estimated in approximately 70 kboe/d;
• the Hadrian South (Eni's interest 30%) and Lucius (Eni's interest 8.5%) fields in the Gulf of Mexico, with an overall production of 23 kboe/d;
• other main projects started up in Egypt, the United Kingdom, Norway, the United States and Italy.
• ›In Mozambique, following the signing of the Unitization and Unit Operating Agreement (UUOA) and in full agreement with all the concessionaries of the projects, a unitization was set out for the development of the natural gas reservoirs straddling Areas 4 (operated by Eni) and 1 (operated by Anadarko) in the Rovuma Basin, offshore Mozambique. In accordance with the UUOA, the development of the straddling reservoirs will be carried out at an early stage in a separated but coordinated way by the two operators, until 24 Tcf of natural gas reserves are developed (12 Tcf of natural gas from each Area). Future developments will be jointly pursued by Area 4 and Area 1 concessionaires. The Final Investment Decision relating the Mamba field in Eni's operating Area is expected in 2017.
• › Finalized a strategic oil agreement in Egypt, which provides investment of up to \$5 billion (at 100%) to develop the Country's oil and gas reserves in future years. Eni has also agreed on new terms for ongoing oil contracts, with the economic effects retroactive to January 1, 2015. Set new measures to reduce overdue amounts of trade receivables relating to hydrocarbon supplies to Egyptian state-owned companies.
• ›In February 2016, Mozambique authorities approved the development of the first development phase of Coral (Eni operator with a 50% interest), targeting to put into production 5 trillion cubic feet of gas.
• › Signed an agreement to supply 1.4 mmtonnes/y of LNG from the Eni-operated Jangkrik field (Eni's interest 55%) to the Indonesian state-run company PT Pertamina, effective in 2017. The agreement will support the development of the Jangkrik field.
• ›In Ghana, Eni sanctioned the final investment decision for the integrated OCTP oil and gas project (Eni operator with a 47.22% interest). The first oil is expected in 2017.
• ›In March 2016, production started up at the Goliat oilfield (Eni operator with a 65% interest) in the Barents Sea, in Norway. Production is expected to achieve 65 kbbl/d net to Eni.
• ›The Project Integrée Hinda (PIH) in the M'Boundi area in Congo involved approximately 25,000 people in the five-year 2011-2015 period with specific programs and in collaboration with local Authorities, to improve education, health, agriculture and access to water.
• ›The business sustainability in the medium to long-term remains a key factor in the growth strategy of upstream sector with initiatives to support the local development always more integrated into business activities. In particular, during the year

projects in Ghana and Mozambique started with initiatives to improve health, access to clean water, education and training; the initiatives in Nigeria, Iraq and Indonesia continue.

› Development expenditure was €9,341 million (down by 12% net of exchange rate effects) to fuel the growth of major

projects and to maintain production plateau particularly in Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia, Italy and the United Sates.

›In 2015 overall R&D expenditure of the Exploration & Production segment amounted to €78 million (€83 million in 2014).

Activity Areas

Italy

Eni has been operating in Italy since 1926. In 2015, Eni's oil and gas production amounted to 169 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 developed and undeveloped acreage of 21,083 square kilometres (16,975 square kilometres net to Eni).

Eni's exploration and development activities in Italy are regulated by concession contracts (51 operated onshore and 64 operated offshore) and exploration licenses (11 onshore and 9 offshore).

Adriatic and Ionian Sea

Production Fields in the Adriatic and Ionian Sea accounted for 45% of Eni's domestic production in 2015, mainly gas. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia and Porto Garibaldi. Production is operated by means of 68 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. The system is subject continuously to rigorous safety control, maintenance activities and production optimization.

Development Main development activities concerned: (i) maintenance and optimization of production, mainly at the Barbara, Anemone, Annalisa, Armida and Guendalina fields; (ii) start-up of the Bonaccia NW project and ongoing development activities at the Clara field; and (iii) launch of CLEAN SEA programme (Continuous Long-term Environment Monitoring and Asset Integrity at Sea), a robotic system of environmental monitoring and inspection of offshore facilities.

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. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields is treated by the Viggiano oil center.

On March 31 2016, as part of an investigation commenced by the Italian Public Prosecutor of Potenza for alleged environmental crimes that is disclosed in the legal proceeding section in the Annual report on Form 20-F 2015 (see page F-86), it was ordered the seizure of certain plants that are functional to the activity of hydrocarbons production, which has been shut down. The interruption is currently affecting a production of approximately

60 kboe/d net to Eni. The value-in-use of the Val D'Agri CGU determined as part of the impairment review of 2015 significantly exceeds the CGU carrying amount, so to exclude that even under the worst-case production shutdown among the currently foreseeable scenarios a reduction of the CGU book value at the reporting date might occur.

Development The development plan is progressing in line with the commitments agreed with the Basilicata Region, particularly in 2015: (i) a new gas treatment unit realized, in order to improve production capacity of the treatment oil centre and the environmental performance; (ii) the Environmental Monitoring Plan is being implemented. This project represents a benchmark in terms of environmental protection. In addition, Eni implements best practices in environmental protection by means of the Action Plan for Biodiversity in Val d'Agri; and (iii) programs to support a cultural and social development, tourism as well as development of agricultural and food farming businesses.

Sicily

Production Eni operates 12 production concessions onshore and 3 offshore. The main fields are Gela, Ragusa, Tresauro, Giaurone, Fiumetto and Prezioso, which in 2015 accounted for approximately 11% of Eni's production in Italy.

Following the Memorandum of Understanding for the Gela area, signed with the Ministry of Economic Development in November 2014, Eni started preparatory study on the Argo Cluster offshore development project.

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, on a total developed and undeveloped acreage of 9,904 square kilometres (3,114 square kilometres net to Eni). Eni's production in Norway amounted to 105 kboe/d in 2015.

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 Åsgard (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 2015 accounted for 74% of Eni's production in Norway. The gas produced in the area is collected at the Åsgard 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 The activity of the year concerned the start-up of: (i) the Asgard Subsea Compression project in order to optimize production from Mitgard (Eni's interest 14.8%) and Mikkel fields; and (ii) the FSU at Heidrun field (Eni's interest 5.2%).

Exploration Eni holds interests in 30 Prospecting Licenses ranging from 5% to 50%, 4 of these are operated.

Norwegian Section of the North Sea

Production Eni holds interests in 2 production licenses. The main producing field is Ekofisk (Eni's interest 12.39%) in PL 018, which in 2015 produced approximately 24 kboe/d net to Eni and accounted for 23% 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 Emden terminal in Germany for gas. At the beginning of 2015, production start-up was achieved at the Eldfisk 2 field.

Development The activity of the year concerned the maintenance and optimization of the production at the Ekofisk field.

Exploration Eni holds interests in 7 Prospecting Licenses ranging from 12.39% to 45%, of which one as operator.

In 2015, Eni was awarded the PL 044C exploration license with a 13.12% interest.

Barents Sea

Eni holds interests in 16 prospecting licenses, 11 of these are operated. Barents Sea is a strategic area with a huge resource base, which will be developed in compliance with the tightest environmental and safety standards provided for the people and environment protection, considering the fragile ecosystem. Production In March 2016, production start-up was achieved at the Goliat oilfield (Eni operator with a 65% interest) in the Barents Sea. Production plateau is expected at 65 kbbl/d net to Eni. The project includes a subsea system consisting of 22 wells, of which 12 are oil producers, 7 water injectors and 3 gas injectors, linked to the largest cylindrical FPSO in the world by subsea production and injection flowlines. The use of well-advanced technologies, electricity supply provided to the platform from the mainland and the re-injection of produced water and natural gas into reservoir as well as zero gas flaring during production activities will allow to minimize environmental impact.

The Goliat project is also equipped with a well-advanced emergency system for the management of oil spills, in terms of organization, equipment and technology advancement. The testing performed in 2015 confirmed that oil spill contingency

response plan is in line with all the requirements of Norwegian Authorities. This result was achieved also thanks to the Costal Oil Spill Preparedness Improvement Program (COSPIP), launched by Eni jointly with other major oil companies and local and international research institutes.

Exploration In 2015 Eni was awarded the operatorship and a 40% interest in the PL 806 exploration license.

United Kingdom

Eni has been present in the United Kingdom 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 2,442 square kilometres (1,905 square kilometres net to Eni). In 2015, Eni's net production of oil and gas averaged 76 kboe/d. Exploration and production activities in the United Kingdom are regulated by concession contracts.

Production Eni currently holds interests in 5 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other fields are Elgin/Franklin (Eni's interest 21.87%), J-Block and Jasmine (Eni's interest 33%), Jade (Eni's interest 7%) and MacCulloch (Eni's interest 40%), which in 2015 accounted for 59% of Eni's production in the UK.

Eni started production of the Phase 2 at the West Franklin field (Eni's interest 21.87%), following the completion of two productive wells.

Development Development activities concerned drilling activities

for the completion of the development of Jasmine field.

Exploration Eni holds interests in 26 exploration blocks ranging from 7% to 100%, in 16 of these Eni is operator.

In 2015, Eni was awarded four exploration licenses in the Central North Sea, with interests ranging from 9.13% to 100%. In addition, Eni finalized the acquisition of three licenses in the Southern North Sea, with a 100% interest.

North Africa

Algeria

Eni has been present in Algeria since 1981. In 2015, Eni's oil and gas production averaged 96 kboe/d. Developed and undeveloped acreage of Eni's interests was 3,409 square kilometers (1,179 square kilometers net to Eni).

Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) blocks 403a/d (Eni's interest from 65% to 100%); (ii) block Rom North (Eni's interest 35%); (iii) blocks 401a/402a (Eni's interest 55%); (iv) blocks 403 (Eni's interest 50%); (v) block 405b (Eni's interest 75%); and (vi) block 212 (Eni's interest 22.38%) with discoveries already made. In addition, Eni holds interest in the non-operated block 404 and block 208 with a 12.25% stake.

Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

Blocks 403a/d and Rom Nord

Production Production comes mainly from the HBN and Rom and satellites fields and represented approximately 22% of Eni's production in Algeria in 2015. 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 HBNS oil center operated by the Groupment Berkine.

The activity of the year concerned infilling activities and production optimization in the area.

In 2015, Eni signed with relevant Authorities a five-year extension for the operated field Rom East (Eni's interest 100%).

Blocks 401a/402a

Production Production comes mainly from the ROD/SFNE and satellite fields and accounted for approximately 14% of Eni's production in Algeria in 2015. The activity of the year concerned the drilling of new wells and production optimization.

Block 403

Production The main fields are BRN, BRW and BRSW, which accounted for approximately 10% of Eni's production in Algeria in 2015. Activities during the year concerned infilling wells and production optimization.

Block 404

Production The main fields are HBN and HBNS and satellites, which accounted for approximately 21% of Eni's production in Algeria in 2015. Activities during the year concerned infilling wells and production optimization.

Block 405b

Production Production comes mainly from MLE-CAFC project and accounted for approximately 16% of Eni's production in the Country.

The natural gas treatment plant has a production and export capacity of 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 Development and optimization activities progressed at the MLE-CAFC production fields, by means of construction and infilling activities as well as production optimization. The project includes an additional oil phase with a start-up expected in 2017, targeting a production plateau more than 30 kboe/d net to Eni.

Block 208

Production The El-Merk field is the main production project and accounted for approximately 18% of Eni's production in Algeria in 2015. Production is treated by means of a gas treatment plant for approximately 600 mmcf/d and two oil trains for 65 kbbl/d each. Activities during the year concerned infilling wells and production optimization.

Egypt

Eni has been present in Egypt since 1954. In 2015, Eni's share of production in this Country amounted to 189 kboe/d and accounted for approximately 11% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage in Egypt was 23,452 square kilometres (9,668 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 76%) 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 2015, production from these large concessions accounted for approximately 92% of Eni's production in Egypt.

In March 2015, Eni and the Egyptian Ministry of Petroleum and Mineral Resources signed a framework agreement, which comprises a plan to invest up to \$5 billion (at 100%) in the development of the Country's oil and gas reserves over the next few years. The agreement also includes a revision of certain Eni's ongoing oil contracts, with the economic effects retroactive to January 1, 2015. The agreement also comprises the identification of new measures to reduce overdue amounts of trade receivables relating to hydrocarbons supplies to Egyptian stateowned companies. In November 2015, as foreseen in the agreement, Eni signed three amendments for the concessions of Sinai 12 (Eni's interest 100%) and Abu Madi (Eni's interest 75%), North Port Said and Baltim, for the realization of projects to be implemented in the next years and to support the increasing energy needs of Egyptian local demand. In addition, Eni signed a new Concession Agreement for the Ashrafi area (Eni's interest 25%). Certain planned activities are currently in the execution phase and one additional well in Baltim concession has already been put into production.

Exploration activities yielded positive results with the giant Zohr gas discovery, in the operated Shorouk licence (Eni's interest 100%) located in the deep offshore of Mediterranean Sea. This field is estimated to retain 30 trillion cubic feet of gas in place. The discovery could grant energy independence to the Country for many years to come. In February 2016, the Egyptian Ministry of Petroleum and Mineral Resources has approved to award to Eni the Zohr Development Lease that allows the start-up of the development program at the Zohr gas field. The first gas is expected at the end of 2017. In addition, appraisal activity yielded positive results with

the Zohr 2X well, the first delineation well. The delineation campaign provides the drilling of three additional wells.

During the year, Concession Agreements were ratified for the following blocks: (i) the Southwest Melehia (Eni's interest 100%) in the western desert; (ii) Karawan (Eni operator with a 50% interest) and North Leil (Eni's interest 100%) in the deep offshore of Mediterranean Sea; (iii) North El Hammad (Eni operator with 37.5% interest) and North Ras El Esh (Eni's interest 50%) in the offshore Nile Delta, which is still expected to be ratified by the Country's Authorities.

Exploration and production activities in Egypt are regulated by Production Sharing Agreements.

Gulf of Suez

Production Production mainly comes from the Belayim field, Eni's first large oil discovery in Egypt, which produced approximately 97 kbbl/d (64 kbbl/d net to Eni) in 2015.

Development Activities were performed in the Sinai 12 area by means of the drilling of the infilling wells in order to optimize the residual mineral potential recovery.

During the year, the Chemical Enhanced Oil Recovery pilot project was launched in order to optimize the recovery of the mineral potential of the Belayim field.

Exploration Exploration activity yielded positive results with the Sidri-18 oil well in the Abu Rudeis concession (Eni's interest 100%).

Nile Delta

North Port Said

Production Production for the year amounted to approximately 25 kboe/d (approximately 18 kboe/d net to Eni), approximately 106 mmcf/d of natural gas and approximately 3 kbbl/d of condensates. Part of the production of this concession is supplied to the United Gas Derivatives Co (Eni's interest 33.33%) with a treatment capacity of 1.3 bcf/d of natural gas and a yearly production of 380 ktonnes of propane, 305 ktonnes of LPG and 1.5 mmbbl of condensates. Development Activities performed have aimed at supporting current gas production.

Baltim

Production In 2015 production amounted to approximately 40 kboe/d (approximately 12 kboe/d net to Eni); approximately 177 mmcf/d of natural gas and 5 kbbl/d of condensates.

Development Activities performed have aimed at supporting current gas production.

Ras el Barr

Production In 2015, the production amounted to approximately 83 kboe/d (approximately 25 kboe/d net to Eni), mainly gas from Ha'py, Akhen, Taurt and Seth fields.

Development During the year, sub-sea END Phase 3 project was started up.

El Temsah

Production This concession includes the Temsah, Denise, Tuna and DEKA fields. Production in 2015 amounted to approximately 115 kboe/d (approximately 32 kboe/d net to Eni); approximately 600 mmcf/d of natural gas and approximately 3 kbbl/d of condensates net to Eni.

Development Development activities concerned infilling activity in order to optimize the residual mineral potential recovery.

Exploration in the Nile Delta

Exploration activity yielded positive results with a gas discovery in the Nooros exploration prospect, located in the Abu Madi West license (Eni's interest 75%). This field is estimated to retain approximately 530 billion cubic feet of gas in place with upside, and associated condensates. The discovery was put into production in two months time through a tie-in to the existing Abu Madi gas treatment plant. In February 2016, a new success exploration was achieved with the drilling of the Nidoco North 1X well. Production start-up is expected in the second quarter 2016 and will allow to achieve an overall production of 45 kboe/d in the area.

Western Desert

Production Other operated production activities are located in the Western Desert, in particular in the Melehia, Ras Qattara, West Abu Gharadig (Eni's interest 45%) and West Razzak (Eni's interest 100%) development permits containing mainly oil. Concessions in the Western Desert accounted for approximately 16% of Eni's production in Egypt in 2015.

Development Development activities included infilling activities in order to optimize the mineral potential recovery factor, particularly in the Meleiha concession.

Exploration Exploration activity yielded positive results with an oil and gas discovery with the Melehia West Deep well in the Melehia concession.

Libya

Eni started operations in Libya in 1959. 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). Exploration and development activities include six contract areas. 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 & 4) and in the onshore contract Areas A, B and offshore Area D.

In recent years, Eni's production levels in Libya were negatively impacted by an internal revolution and a change of regime in 2011, which led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political development forced Eni to temporarily interrupt or reduce its producing activities, until the situation began to stabilize. In 2015, Eni's facilities in Libya produced on average 365 kboe/d, returned to levels not seen from the outbreak of the civil war. In case of major unfavorable geopolitical developments in Libya including but not limited to, a resurgence of civil war, renewed internal tensions, civil disorder or any other outbreak of violence, we could be forced to shut down our operations and interrupt production.

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 January 2015, Eni and the State company NOC signed an agreement that ensures during the 2015-2018 four-year period the sale of the associated gas to the production of the Bu Attifel oilfield in the contractual area B.

Development activities in the contractual area D concerned: (i) the linkage and the start-up of three infilling wells, in addition to the activity of production optimization at the Wafa field; and (ii) the start-up of the second development phase of the Bahr Essalam field by means of the start-up of drilling campaign and the award of EPC contract for the construction of linkage subsea facility to the onshore treatment plans.

Exploration activities near-field yielded positive results in the contractual area D, with gas and condensates discoveries: (i) in the offshore Bahr Essalam South exploration prospect, nearby to the Bahr Essalam production field; and (ii) in the offshore Bouri North exploration prospect, nearby to the Bouri production field. These discoveries confirm the high mineral potential of the natural gas resources still present in the Country.

Tunisia

Eni has been present in Tunisia since 1961. In 2015, Eni's production amounted to 12 kboe/d. Eni's activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed acreage of 3,600 square kilometers (1,558 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), Djebel Grouz (Eni operator with a 50% interest), MLD (Eni's interest 50%) and El Borma (Eni's interest 50%) onshore blocks.

Development Production optimization represents the main activity currently performed in the production concessions to mitigate the natural field production decline

Sub-Saharan Africa

Angola

Eni has been present in Angola since 1980. In 2015, Eni's production averaged 101 kboe/d. Eni's activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 21,296 square kilometers (4,404 square kilometers net to Eni). The main Eni's asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub project, where production started up in 2014 and the East Hub development project is underway with start-up expected in 2017.

Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni's interest 9.8%) north of the Angolan coast; (ii) Development Areas in the former Block 3 (Eni's interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni's interest 20%) in the deep offshore west of Block 0; (iv) the Lianzi Development Area in the Block 14K/A IMI (Eni's interest 10%), where a unitization was implemented with the Congo-Brazaville area; and (v) 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 Block 35/11 (Eni operator with a 30% interest), Block 3/05-A (Eni's interest 12%), onshore Cabinda North block (Eni's interest 15%) and the Open Areas of Block 2 assigned to the Gas Project (Eni's interest 20%).

In 2015 Eni and the State company Sonangol signed certain agreements aimed at strengthening strategic and operational partnership, which include: (i) the commitment to upgrade the current development plans for the Lobito refinery, owned by the Angolan national company, with Eni's expertise and know-how in the downstream sector including the potential synergies deriving from existing refineries; and (ii) the commitment to progress the ongoing evaluation of the gas resources in the Lower Congo Basin, in the framework of a strategy aimed at guaranteeing accessible energy in the Country. Once these are developed, they will allow energy supply to the internal market, sustaining local economy and the agricultural projects, which ease the diversification of the Country's economy. 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 2015, production from this block amounted to approximately 289 kbbl/d (approximately 28 kbbl/d net to Eni). Oil production from Area A, deriving mainly from the Takula, Malongo and Mafumeira fields amounted to approximately 17 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 11 kbbl/d net to Eni.

Development Development activities concerned: (i) the completion of flaring down activities at the Nemba field, with a reduction of gas flared of approximately 85%; and (ii) the Mafumeira project with production start-up expected at the end of 2016 Infilling activities and near-field exploration are underway on the whole block in order to mitigate the natural field production decline.

Block 3

Production Block 3 is divided into three production offshore areas. Oil production is treated at the Palanca terminal and delivered to storage vessel unit and then exported. In 2015, production from this area amounted to approximately 49 kbbl/d (approximately 4 kbbl/d net to Eni).

Production start-up was achieved at the Gazela field with a production of approximately 3 kbbl/d.

Block 14

Production In 2015, Development Areas in Block 14 produced approximately 114 kbbl/d (approximately 16 kbbl/d net to Eni), accounting for approximately 14% of Eni's production in the Country. It is one of the most fruitful areas in the West African offshore, recording 9 commercial discoveries to date. Its main fields are Kuito, Landana and Tombua as well as Benguela-Belize/Lobito-Tomboco. Associated gas of the area 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).

Production start-up was achieved at the Lianzi project (Eni's interest 10%), with the start-up of the first two wells which yielded approximately 25 kbbl/d by the end of the year. The start-up of an additional well in 2016 will allow to reach a production peak of approximately 35 kbbl/d.

Block 15

Production The block produced approximately 326 kbbl/d (approximately 37 kbbl/d net to Eni) in 2015. Production derives mainly from the Kizomba discovery area with: (i) the Hungo/ Chocalho fields, started-up in 2004 as part of phase A of the global development plan of the Kizomba reserves; (ii) the Kissanje/Dikanza fields, started up in 2005, as part of Phase Kizomba B; (iii) satellites Kizomba Phase 1 project, started up in 2012, and Phase 2 project, started up in 2015. In 2015, the fields of Kizomba area produced approximately 289 kbbl/d (approximately 34 kbbl/d net to Eni). Other main fields in Block 15 are Mondo and Saxi/Batuque fields which produced approximately 37 kbbl/d (approximately 3 kbbl/d net to Eni) in 2015. These fields are operated by FPSO units.

Block 15/06

The activities concerned to put in production approximately 450 mmbbl of reserves by means of the development of West Hub projects, sanctioned in 2010, and East Hub project, sanctioned in September 2013.

The West Hub Project, with start-up at the end of 2014, represents the first Eni-operated producing project in the Country. The development program plans to hook up the Block's discoveries to the N'Goma FPSO in order to support production plateau. In April 2015, production start-up was achieved at the Cinguvu field, following the first oil of the Sangos field, and in January 2016, Eni started

production from the M'Pungi field, with an overall production of approximately 25 kbbl/d net to Eni.

The East Hub project with start-up expected in 2017 will develop the reservoir in the north-eastern area by means of a development program similar to the West Hub.

Eni and Sonangol agreed a revision of certain contractual terms to support investments in the Block 15/06, where in January 2015, Eni obtained a three-year extension of the exploration period.

The LNG business in Angola

Eni holds a 13.6% interest of the Angola LNG consortium that manages a LNG plant, located in Soyo, with a processing capacity of approximately 1 bcf/d of natural gas, producing 5.2 mmtonnes/y of LNG and over 50 kbbl/d of condensates and LPG. The plant envisages the development of 10,594 bcf of gas in 30 years.

Congo

Eni has been present in Congo since 1968. In 2015, production averaged 103 kboe/d net to Eni. Eni's activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore over a developed and undeveloped acreage of 2,737 square kilometres (1,354 square kilometres net to Eni).

Exploration and production activities in Congo are regulated by Production Sharing Agreements.

Production Eni's main operated oil producing interests are the Zatchi (Eni's interest 56%), Loango (Eni's interest 42.5%), Ikalou (Eni's interest 100%), Djambala (Eni's interest 50%), Foukanda and Mwafi (Eni's interest 58%), Kitina (Eni's interest 52%), Awa Paloukou (Eni's interest 90%), M'Boundi (Eni's interest 83%), Kouakouala (Eni's interest 75%), Nené Marine (Eni 65%), Zingali and Loufika (Eni's interest 100%) fields, with an overall production of approximately 75 kboe/d net to Eni. Other relevant not operated producing areas are a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits with a production of approximately 28 kboe/d net to Eni.

Eni achieved production start-up of the Litchendjili field in the Marine XII block (Eni operator with a 65% interest) by means of the installation of a production platform, the construction of transport facilities and onshore treatment plant. Peak production is estimated at 14 kboe/d net to Eni and is expected in 2016. Natural gas production will feed the CEC power station (Eni's interest 20%) while oil production start-up is expected with the next development wells.

Development Development activities progressed at the Nené Marine production field, started up in 2014, located in the Marine XII block, with the completion and start-up of two additional productive wells. In 2015, the final investment decision for the Phase 2 of Nené Marine was sanctioned and start-up is expected in the second half of 2016. The Project Integreé Hinda (PIH) was completed in the year. The social project provides to support the living conditions in the M'Boundi area. In the five-year 2011-2015 period, this program provided to improve education, health, agriculture and access to water, with specific initiatives and in collaboration with local Authorities. The program involved approximately 25,000 people. Eni, with the support of the Earth Institute of the Columbia University launched a program to design a monitoring system to assess the effectiveness of the PIH project and to check its support to the development of the area.

The completion of the flaring down project of the M'Boundi field achieved a zero flaring target in the area, with a decrease of approximately 74 mmcf in daily volumes of gas flaring. In particular, the associated gas was fully valorized through: (i) a program of gas injection in order to optimize reserve recovery; (ii) a long-term supply

contract to power plants in the area including the CEC power plant with a 300 MW generation capacity. In 2015, M'Boundi contractual supplies were approximately 14 kboe/d net to Eni. In addition, during the 2015, Eni and the local Authorities defined a frame cooperation agreement for the expansion of the CEC power plant, in order to promote the energy development in Congo and contribute to the Country's growth. Exploration Exploration activities yielded positive results in the Marine XII block with: (i) the Minsala N1 appraisal well, confirming the mineral potential of the Minsala discovery; and (ii) the Nkala Marine discovery with a mineral potential estimated in approximately 250-300 million boe. The exploration successes in the pre-salt sequences of the Marine XII block confirms Eni's exploration technologies effectiveness. Eni estimates the resources in place of oil and gas to be approximately 5.8 billion boe.

Ghana

Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni's interest 47.22%) permits which is regulated by a concession agreement. In March 2016, Eni was awarded the operatorship of the exploration license Cape Three Points Block 4 (Eni's interest 42.47%), located in the offshore of the Country.

Development Activities were focused on the development of oil and gas reserves of the OCTP concession. In 2015, Eni defined and signed a Gas Sale Agreement with the Ghana Authorities, as well as other agreements related to the guarantees for the sale of natural gas from the OCTP project, sanctioned and approved by the Ministry of Petroleum in December 2014. The integrated oil and gas development plan provides to put into production the Sankofa, Sankofa East and Gye Nyame discoveries. The first oil is expected in 2017 and the first gas in 2018. Peak production is estimated at 40 kboe/d net to Eni in 2019. In the year development activities concerned: (i) main contracts awarded for the realization of the FPSO and offshore facilities; and (ii) the start-up of the development activities with the drilling of 5 development wells.

In addition, during 2015, a Livelihood Restoration plan was defined to support local community.

Leveraging on Eni's cooperation model, a project together with local stakeholders was defined to support local communities in the medium to long-term. Main undergoing activities are focused in the Western Region of the Country, where the ongoing Health Project will involve more than 300,000 people. In particular, the project includes: (i) the building of 8 clinics, 6 of which have already been completed; (ii) the renovation of 9 already existing clinics, 2 of which completed; (iii) the building and renovation of a maternity ward, in addition to the one already inaugurated in 2015; and (iv) five ambulances were delivered, while training programmes for both medical and paramedical staff are being carried out, as well as further supply of medical equipment.

Mozambique

Eni has been present in Mozambique since 2006. Eni is operator with a 50% interest of Area 4 Block located in the offshore Rovuma Basin, which represents a new frontier in oil and gas industry thanks to extraordinary gas discoveries made during intense only three-year exploration campaign. To date, resource base reached 88 Tcf located in the different sections of the area.

In October 2015, Eni was awarded the operatorship of the exploration offshore Block A-5A (Eni's interest 34%). The block is located in the deep offshore of Zambesi covering an area of approximately 5,000 square kilometers.

Development The Company is planning to develop as first target the Coral discovery and a portion of the Mamba straddling resources. In November 2015, according to a Decree Law approved in December 2014, which defines the Rovuma Basin fiscal regime and the terms for the onshore liquefaction projects, all the concessionaries of Area 4 (operated by Eni) and Area 1 (operated by Anadarko) signed the Utilization and Unit Operating Agreement (UUOA). The agreement concerns the development of the Mamba and Prosperidade natural gas straddling reservoirs. In addition, the two operators jointly submitted to the Authorities the request for the allocation of the areas designated to the construction of the onshore liquefaction facilities. The development plan of the first phase of the Mamba project includes construction of two onshore LNG trains with a combined capacity of 10 mmtonnes/y and the drilling of 16 subsea wells, with start-up in 2022. Eni expects to produce up to 12 Tcf of gas according to its independent industrial plan, coordinated with the operator of Area 1. The FID is expected in 2017.

In February 2016, the local Authorities approved the first stage of the development plan of the Coral discovery. The project plans to put into production 5 Tcf of gas and includes the construction of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG-FLNG) with a capacity of 3.4 mmtonnes/y fed by 6 subsea wells. Start-up is expected in 2021. In September 2015, the project also received the Environmental License by means of a process of environmental and social assessment that involved local communities and national authorities. The EPCIC contracts award recommendation for the construction, installation and commissioning of the FLNG and supply of subsea equipment and drilling rig have been issued. Furthermore, the long-term LNG sale contract have been finalized. The

FID is expected in 2016, after approval of all contracts and commercial agreements by Mozambique authorities and JV partners. Leveraging on Eni's cooperation model, a medium-long term program was defined to support local communities also involving all local stakeholders as integrated part of the development activity. The guidelines of the program include projects to develop the socioeconomic conditions of local communities and respect for biodiversity. In particular, during 2015, certain projects were completed, such as: (i) Water Wells Project, aimed to improve access to water in the Palma area, by means of the water management system which includes the constitution of committees for local management in order to guarantee the sustainability of the initiatives in the long- term; (ii) educational programmes including primary and secondary school as well as professional training; (iii) power supply to the primary school in the Pemba area to support literacy; and (iv) the renovation of certain hospital departments in Pemba area and specific training initiatives dedicated to doctors, nurses and hospital technicians.

Nigeria

Eni has been present in Nigeria since 1962. In 2015, Eni's oil and gas production amounted to 137 kboe/d over a developed and undeveloped acreage of 32,015 square kilometers (7,432 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 OML 125 (Eni's interest 85%) and OPL 245 (Eni's interest 50%), 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 19 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.

In the exploration phase Eni operates offshore OML 134 (Eni's interest 85%), 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.

During the year, programs progressed to support the local community, with main activities in the construction of public infrastructure, education services, enhancing of health services, expanding the access to energy for local area, as well as training programs to promote the economic development, in particular in the agricultural sector.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for state-owned company.

Blocks OMLs 60, 61, 62 e 63

Production Onshore four licenses produced approximately 58 kboe/d and accounted for over 40% of Eni's production in Nigeria in 2015. 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 Island 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 2015, supplies to this power station were an overall amount of approximately 70 mmcf/d, corresponding to approximately 12 kboe/d (approximately 3 kboe/d net to Eni). Development Development activities progressed with: (i) the programmes to reduce gas flared and to monetize associated gas at the flow stations of Kwale/Oshi and Ebocha oil centre. In 2015, the volumes of flared gas decreased by approximately 85%; and (ii) the water management project by means of the construction of collection, treatment and re-injection facilities. In 2015, the first treatment hub was completed, through the construction of facilities with the overall capacity of 60 kbbl/day.

Block OML 118

Production The Bonga oil field produced approximately 19 kboe/d net to Eni in 2015. Production is supported by an FPSO unit with a 225 kboe/d treatment capacity and a 2 mmboe storage capacity. Associated gas is carried to a collection platform on the EA field and, from there, is delivered to the Bonny liquefaction plant. During the year, production start-up was achieved at the Bonga NW project, by means of the linkage of additional productive and infilling wells to the existing FPSO.

Block OML 125

Production Production derived mainly from the Abo field which yielded approximately 22 kboe/d net to Eni in 2015. Production is supported by an FPSO unit with a 45 kboe/d capacity and an 800 kboe storage capacity.

Eni completed activities and achieved production start-ups at the Abo project Phase 3, by means of the linkage of two additional production wells to the existing production facilities in the area.

SPDC Joint Venture (NASE)

In 2015, production from the SPDC JV accounted for approximately 20% of Eni's production in Nigeria (approximately 32 kboe/d). Development activities concerned: (i) the OML 28 block (Eni's interest 5%), where the drilling campaign progressed within the integrated project in the Gbara-Ubie area, aimed to supply natural gas to the Bonny liquefaction plant (Eni's interest 10.4%) with start-up expected in 2016; and (ii) the OML 43 block (Eni's interest 5%), where the development plan of the Forkados-Yokri field provides the drilling of

24 producing wells, the upgrading of existing flowstations and the construction of transport facilities. Start-up is expected in 2016.

The LNG business in Nigeria

Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant is operational, with a 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 currently provided under gas supply agreements with an expiring date in eighteen years from the SPDC JV and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an average amount of approximately 2,825 mmcf/d for the next four years (approximately 268 mmcf/d net to Eni corresponding to approximately 48 kboe/d). LNG production is sold under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co. During 2015, six new vessels were launched.

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA).

In June 2015, Eni and KazMunayGas (KMG) signed an agreement on the transfer to Eni of the 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The transfer is expected to be finalized after all necessary approvals required by law. The Isatay block is estimated to have significant potential oil resources and will be operated by a joint operating company established by KMG and Eni on a 50/50 basis. In addition, after the finalization of the FEED, the activities related to the contracts' award for the construction of a shipyard in Kuryk started, as provided by the agreements signed in 2014.

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 giant Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. The NCSPSA expires at the end of 2041.

On June 13, 2015, the Consortium completed a new setup of the operating model to execute the development of the project, targeting to streamline decision-making process, to increase efficiency in operations and to reduce costs. This new operating model provides that the company NCOC NV, participated by the seven partners of the Consortium, acts as the sole operator of all exploration, development and production activities at the Kashagan field.

In December 2015, the Authority of the Republic of Kazakhstan approved the Amendment 5 to the development plan and budget for the Phase 1 of the Kashagan project (the so-called "Experimental Program") which defines the update to the project schedule and budget and the activities for the replacement of the damaged pipelines which forced the Consortium to shut down the production at the Kashagan field soon after the start-up in September 2013. During the year, the activities progressed to replace the damaged pipelines and the Consortium expects to complete the installation works in the second half of 2016 with production re-start by the end of 2016. The production capacity of 370 kbbl/d planned for the Phase 1 is expected to be achieved during 2017.

Within the agreements with local Authorities, Eni has been conducting training program for Kazakh resources in the oil&gas sector, in addition to the realization of infrastructures with social purpose.

Karachaganak

Located onshore in West Kazakhstan, Karachaganak (Eni's interest 29.25%) is a liquid, gas and condensate giant 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.

In June 2015, the Gas Sales Agreement for the Karachaganak field (Eni 29.25%) was extended until 2038. The agreement provides the supply of currently produced gas volumes to the Orenburg treatment plant, including additional new development projects to support the current liquids and gas production.

Production In 2015, production of the Karachaganak field averaged 239 kbbl/d of liquids (56 net to Eni) and 924 mmcf/d of natural gas (218 net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 48%) at the Russian gas plant in Orenburg and the remaining volumes is utilized for re-injecting in the higher layers and the production

of fuel gas. Approximately 93% 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 (approximately 16 kbbl/d) are marketed at the Russian terminal in Orenburg.

Development The Karachaganak Expansion Project is currently under study. The project targets to install, in stages, the gas treatment plants and re-injection facilities to support liquids' production profile. The development plan is currently in the phase of technical and marketing definition of its first development phase, aimed to increase the capacity of gas re-injection. Eni continues its commitment to support local communities in the nearby area of Karachaganak field. In particular, activities focused on: (i) the professional training; and (ii) the construction of kindergartens, maintainance of hospitals and roads, building of heating plants and sport centres.

Moreover, following the re-definition of the Sanitary Protection Zone (SPZ) associated to the ongoing development projects, in 2015, according to the international standards and best practices, a project of relocation of the inhabitants from Berezovka and Bestau villages started.

Eni continues to conduct monitoring activities on biodiversity and ecosystems in the nearby of the production areas.

Rest of Asia

Indonesia

Eni has been present in Indonesia since 2001. In 2015, Eni's production mainly composed of gas, amounted to 17 kboe/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua, over a developed and undeveloped acreage of 34,633 square kilometers (25,124 square kilometers net to Eni); in total, Eni holds interests in 14 blocks.

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. Liquefied gas is exported to the Japanese, South Korean and Taiwanese markets.

Development The ongoing development activities that will ensure gas supllies to the Bontang liquefaction plant include: (i) the Jangkrik project (Eni operator with a 55% interest) in the Kalimantan offshore. This project provides for the drilling of production wells linked to a Floating Production Unit for gas and condensate treatment, as well as the construction of transportation facilities. Start-up is expected in 2017; and (ii) the Bangka project (Eni's interest 20%) in the eastern Kalimantan, with start-up expected in 2016.

In June 2015, Eni and its partners of the Jangkrik project signed two agreements with PT Pertamina for the purchase and sale of 1.4 million tons/year of LNG starting from 2017.

Other initiatives have been carried out in the field of environmental protection, health care and educational system to support local communities located in the operated areas of the eastern Kalimantan, Papua and North Sumatra.

Exploration Evaluation activities following the Merakes gas discovey in the deep offshore of the East Sepinngan block (Eni operator with

an 85% interest), allowed to increase significantly the estimates of gas reserves in place

Iran

Eni's activities in the Country regarded the recovery of its past costs incurred for the development of oil projects and currently handed over to local partners. Eni does not believe that its activities violate any applicable law also including the latest agreement between Iran and Western countries that led to the partial removal of sanctions.

Iraq

Eni has been present in Iraq since 2009 and is performing development activities over a developed acreage of 1,074 square kilometres (446 square kilometres net to Eni).

Development and production activities in Iraq are regulated by Technical Service Contract.

Production Production comes from Zubair oil field (Eni's interest 41.6%) with a production of 40 kbbl/d net to Eni in 2015. At the beginning of March 2016, three new generation plants for the oil, gas and water treatment (Initial Production Facilities – IPF) started. Those plants together with existing restructured and modernized facilities increased oil and natural gas treatment capacity of Zubair field to approximately 650 kbbl/d and will ensure the maximization of the associated gas utilization. In addition, these new facilities have also a water re-injection capacity of approximately 300 kbbl/d that will boost the Zubair's hydrocarbons production.

Development The first stage of the development activities (Rehabilitation Plan) of Zubair field was substantially completed. The project includes an additional development phase (Enhanced Redevelopment Plan), started in 2014, to achieve a production plateau of 850 kbbl/d.

In September 2015, Occidental of Iraq LLC, a partner of Eni Iraq BV in Zubair project, announced to exit the Zubair project, and in December 2015 SOC, the Iraqi state oil company, expressed its decision to take the place of the Occidental of Iraq LLC as a part of the project. Negotiations are underway between the parties involved. Supporting programs for the local community progressed with main activities in the education field, by means of renovation of school buildings and projects aimed to support teaching initiatives.

Pakistan

Eni has been present in Pakistan since 2000. In 2015, Eni's production mainly composed of gas amounted to 41 kboe/d, over a developed and undeveloped acreage of 21,876 square kilometers (8,810 square kilometers net to Eni).

Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).

Production Eni's main permits in the country are Bhit/Bhadra (Eni operator with a 40% interest), Sawan (Eni's interest 23.68%) and Zamzama (Eni's interest 17.75%), which in 2015 accounted for 75% of Eni's production in Pakistan.

Development Production optimization through infilling activities represents the main activity currently performed in the above listed fields to mitigate the natural field production decline.

Turkmenistan

Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the country,

over a developed acreage of 200 square kilometers (180 square kilometers net to Eni) in four areas. In 2015, Eni's production averaged 11 kboe/d.

Exploration and production activities are regulated by PSAs. Production Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap arrangement 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 the national oil company Turkmenneft, via national grid.

Development Development activities include: (i) a program to mitigate the natural field production decline; and (ii) projects in order to improve safety, efficiency and environment performance.

Americas

Ecuador

Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni's interest 100%) located in the Oriente Basin, in the Amazon forest, over a developed acreage of 1,985 square kilometers net to Eni. In 2015, Eni's production averaged 11 kbbl/d.

Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033, following a ten-year extension signed in December 2015.

Production Production deriving from the Villano field, started in 1999, is processed by a Central Production Facility and transported to the Pacific Coast through a pipeline network.

Development Preliminary activities started up at the Villano Phase VI and Oglan projects.

Maintenance activities and facilities upgrading progressed to support high safety standard and efficiency levels.

Trinidad and Tobago

Eni has been present in Trinidad and Tobago since 1970. In 2015, Eni's production averaged 70 mmcf/d (equal to 13 kboe/d). Activity is concentrated offshore North of Trinidad over a developed acreage of 382 square kilometers (66 square kilometers net to Eni). Exploration and production activities in Trinidad and Tobago are regulated by PSAs.

Production Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields, locate 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 coast and it is sold under longterm contracts with prices linked to the United States, as well as alternative destinations markets.

United States

Eni has been present in the United States since 1968. Activities are performed in the Gulf of Mexico, Alaska and in Texas onshore, over a developed and undeveloped acreage of 3,918 square kilometers (2,118 square kilometers). In 2015 Eni's oil and gas production was 98 kboe/d. Exploration and production activities in the United States are regulated by concessions.

Gulf of Mexico

Eni holds interests in 128 exploration and production blocks in the shallow and deep offshore of the Gulf of Mexico, of which 73 are operated by Eni.

As part of Eni's portfolio rationalization process, the sale of certain minor assets in the Gulf of Mexico was finalized.

Production The main operated fields are Allegheny and Appaloosa (Eni's interest 100%), Pegasus (Eni's interest 85%), Longhorn, Devils Towers and Triton (Eni's interest 75%). Eni also holds interests in Europa (Eni's interest 32%), Medusa (Eni's interest 25%), Thunder Hawk (Eni's interest 25%) and Frontrunner (Eni's interest 37.5%) fields.

During the year, production start-ups were achieved in the Gulf of Mexico at: (i) the Hadrian South field (Eni's interest 30%), with an estimated daily production of approximately 300 million cubic feet of gas and 2,250 barrels of liquids (about 16 kboe/d net to Eni); and (ii) the Lucius field (Eni's interest 8.5%), with an estimated production of approximately 7 kboe/d net to Eni.

At the beginning of 2016 production start-up was achieved at the Heidelberg project (Eni's interest 12.5%) in the deepwater Gulf of Mexico. Production plateau is expected to reach approximately 9 kboe/d net to Eni. Planned development activities progressed.

Development Development activities concerned the drilling activities at the operated Devil's Tower field as well as at non-operated fields Medusa (Eni's interest 25%), K2 (Eni's interest 13.39%) and St. Malo (Eni's interest 1.25%).

Texas

Production Production comes from the Alliance area (Eni's interest 27.5%), in the Fort Worth basin. This asset was acquired following an agreement with Quicksilver for unconventional gas reserves (shale gas). In 2015, Eni's production amounted to more than 6 kboe/d. Exploration Exploration activities yielded positive results with the Puckett Trust 1H well, within the agreement signed with Quicksilver Resources for joint evaluation, exploration and development of unconventional oil reservoirs (shale oil) in the southern part of the Delaware Basin, in West Texas. The discovery has already been connected to the existing production facilities.

Alaska

Eni holds interests in 61 exploration and development blocks in Alaska, with interests ranging from 30 to 100%; Eni is the operator in 40 of these blocks.

Production The main fields are Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni's interest 30%) with an overall production of 25 kbbl/d net to Eni in 2015.

Development Drilling activities progressed at the Nikaitchuq and Oooguruk fields.

Leveraging on Eni's model for sustainable development, during the year an updating of the Action Plan for Biodiversity and Ecosystem Services in the Nikaitchuq field area continued.

Venezuela

Eni has been present in Venezuela since 1998. In 2015, Eni's production averaged 25 kboe/d. Activity is concentrated in the offshore Gulf of Venezuela and Gulf of Paria as well as onshore in the Orinoco Oil Belt, over a developed and undeveloped acreage of 2,804 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 Eni's production comes from the Corocoro field (Eni's interest 26%), in the Gulfo de Paria, and the Junin 5 field (Eni's interest 40%), located in the Orinoco Oil Belt which contains 35 bbbl of certified heavy oil in place.

In addition, in July 2015, production started at the gas giant Perla field, located in the Cardon IV block (Eni's interest 50%) in the Gulf of Venezuela. The gas will be mainly used by PDVSA for the domestic market, under the Gas Sales Agreement running until 2036. The development of Perla has been planned in three phases with 21 wells and the installation of four offshore platforms linked via sealine to an onshore treatment plant. The production level at the year-end was approximately 500 mmcf/d at 100%. The second phase will ensure production ramp-up at approximately 800 mmcf/d. The development plan targets a long-term production plateau of approximately 1,200 mmcf/d through a third phase of development.

Development Drilling activities progressed at the Junin 5 oilfield. Possible optimization of development program is currently under evaluation.

Exploration Eni is also participating with a 19.5% interest in Petrolera Guiria for oil exploration and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest for gas exploration, both located offshore in the eastern Venezuela.

Australia and Oceania

Australia

Eni has been present in Australia since 2001. In 2015, Eni's production of oil and natural gas averaged 26 kboe/d. Activities are focused on conventional and deep offshore fields, over a developed and undeveloped acreage of 22,819 square kilometers (16,333 square kilometers net to Eni).

The main production blocks in which Eni holds interests 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). In the appraisal and development phase, Eni holds interests in NT/P68 (Eni's interest 100%) and NT/RL7 (Eni's interest 32.5%). In addition, Eni holds interest in 6 exploration licenses, of which 1 in the JPDA. 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 03-13

Production The liquids and gas Bayu Undan field started-up in 2004 and produced 149 kboe/d (approximately 13 kboe/d net to Eni) in 2015. Liquid production is supported by three treatment platforms and an FSO unit. Production of natural gas is carried by a 500-kilometer long pipeline and is treated at the Darwin liquefaction plant which has a capacity of 3.6 mmtonnes/y of LNG (equivalent to approximately 177 bcf/y of feed gas). LNG is sold to Japanese power generation companies under long-term contracts. The phase 3 of the Bayu Undan field was completed in order to increase liquids production and to sustain LNG production.

Block JPDA 06-105

Production The Kitan oil field started up in 2011 and amounted to 5 kbbl/d in 2015 (approximately 2 kbbl/d net to Eni). The exploitation of this field was concluded in December 2015.

Block WA-33-L

Production The Blacktip gas field started-up in 2009 and produced approximately 22 bcf/y in 2014 (approximately 11 kboe/d). 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 is sold under a 25-year contract to supply a power plant, signed with Australian society Power & Water Utility Co.

Estimated net proved hydrocarbons reserves by geographic area (mmboe)

(at December 31)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2013
Net proved hydrocarbons reserves	499	557	1,802	1,230	1,035	270	966	176	6,535
Consolidated subsidiaries	499	557	1,783	1,155	1,035	263	240	176	5,708
Equity-accounted entities			19	75		7	726		827
Developed	408	343	1,022	701	566	93	171	123	3,427
Consolidated subsidiaries	408	343	1,003	701	566	90	153	123	3,387
Equity-accounted entities			19			3	18		40
Undeveloped	91	214	780	529	469	177	795	53	3,108
Consolidated subsidiaries	91	214	780	454	469	173	87	53	2,321
Equity-accounted entities				75		4	708		787
2014
Net proved hydrocarbons reserves	503	544	1,756	1,320	1,069	290	960	160	6,602
Consolidated subsidiaries	503	544	1,740	1,239	1,069	285	232	160	5,772
Equity-accounted entities			16	81		5	728		830
Developed	401	335	919	725	589	115	214	135	3,433
Consolidated subsidiaries	401	335	904	702	589	112	188	135	3,366
Equity-accounted entities			15	23		3	26		67
Undeveloped	102	209	837	595	480	175	746	25	3,169
Consolidated subsidiaries	102	209	836	537	480	173	44	25	2,406
Equity-accounted entities			1	58		2	702		763
2015
Net proved hydrocarbons reserves	465	495	1,708	1,369	1,198	426	1,079	150	6,890
Consolidated subsidiaries	465	495	1,694	1,282	1,198	422	269	150	5,975
Equity-accounted entities			14	87		4	810		915
Developed	362	404	1,024	786	689	161	482	115	4,023
Consolidated subsidiaries	362	404	1,010	764	689	159	217	115	3,720
Equity-accounted entities			14	22		2	265		303
Undeveloped	103	91	684	583	509	265	597	35	2,867
Consolidated subsidiaries	103	91	684	518	509	263	52	35	2,255
Equity-accounted entities				65		2	545		612

Estimated net proved liquids reserves by geographic area (mmbbl)

(at December 31)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2013
Net proved liquids reserves	220	330	846	738	679	129	263	22	3,227
Consolidated subsidiaries	220	330	830	723	679	128	147	22	3,079
Equity-accounted entities			16	15		1	116		148
Developed	177	179	577	465	295	38	115	20	1,866
Consolidated subsidiaries	177	179	561	465	295	38	96	20	1,831
Equity-accounted entities			16				19		35
Undeveloped	43	151	269	273	384	91	148	2	1,361
Consolidated subsidiaries	43	151	269	258	384	90	51	2	1,248
Equity-accounted entities				15		1	97		113
2014
Net proved liquids reserves	243	331	790	756	697	132	264	13	3,226
Consolidated subsidiaries	243	331	776	739	697	131	147	13	3,077
Equity-accounted entities			14	17		1	117		149
Developed	184	174	534	477	306	64	142	12	1,893
Consolidated subsidiaries	184	174	521	470	306	64	116	12	1,847
Equity-accounted entities			13	7			26		46
Undeveloped	59	157	256	279	391	68	122	1	1,333
Consolidated subsidiaries	59	157	255	269	391	67	31	1	1,230
Equity-accounted entities			1	10		1	91		103
2015
Net proved liquids reserves	228	305	834	803	771	262	347	9	3,559
Consolidated subsidiaries	228	305	821	787	771	262	189	9	3,372
Equity-accounted entities			13	16			158		187
Developed	171	237	555	517	355	126	178	9	2,148
Consolidated subsidiaries	171	237	542	511	355	126	149	9	2,100
Equity-accounted entities			13	6			29		48
Undeveloped	57	68	279	286	416	136	169		1,411
Consolidated subsidiaries	57	68	279	276	416	136	40		1,272
Equity-accounted entities				10			129		139

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

		Rest of Europe		Sub-Saharan				Australia and
	Italy		North Africa	Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
(at December 31)
2013
Net proved natural gas reserves	1,532	1,247	5,246	2,704	1,957	772	3,862	848	18,168
Consolidated subsidiaries	1,532	1,247	5,231	2,374	1,957	744	509	848	14,442
Equity-accounted entities			15	330		28	3,353		3,726
Developed	1,266	904	2,447	1,295	1,488	300	315	561	8,576
Consolidated subsidiaries	1,266	904	2,432	1,295	1,488	286	310	561	8,542
Equity-accounted entities			15			14	5		34
Undeveloped	266	343	2,799	1,409	469	472	3,547	287	9,592
Consolidated subsidiaries	266	343	2,799	1,079	469	458	199	287	5,900
Equity-accounted entities				330		14	3,348		3,692
2014
Net proved natural gas reserves	1,432	1,171	5,306	3,095	2,049	864	3,821	807	18,545
Consolidated subsidiaries	1,432	1,171	5,291	2,744	2,049	846	468	807	14,808
Equity-accounted entities			15	351		18	3,353		3,737
Developed	1,192	887	2,125	1,360	1,553	271	399	675	8,462
Consolidated subsidiaries	1,192	887	2,110	1,271	1,553	261	393	675	8,342
Equity-accounted entities			15	89		10	6		120
Undeveloped	240	284	3,181	1,735	496	593	3,422	132	10,083
Consolidated subsidiaries	240	284	3,181	1,473	496	585	75	132	6,466
Equity-accounted entities				262		8	3,347		3,617
2015
Net proved natural gas reserves	1,304	1,044	4,811	3,101	2,354	890	4,020	771	18.295
Consolidated subsidiaries	1,304	1,044	4,798	2,714	2,354	878	439	771	14,302
Equity-accounted entities			13	387		12	3,581		3,993
Developed	1,051	919	2,579	1,475	1,830	194	1,668	585	10,301
Consolidated subsidiaries	1,051	919	2,566	1,390	1,830	185	373	585	8,899
Equity-accounted entities			13	85		9	1,295		1,402
Undeveloped	253	125	2,232	1,626	524	696	2,352	186	7,994
Consolidated subsidiaries	253	125	2,232	1,324	524	693	2,286	186	5,403
Equity-accounted entities				302		3	66		2,591

Production of oil and natural gas by Country(a)	(kboe/d)	2013	2014	2015
Italy		186	179	169
Rest of Europe		155	190	185
Croatia		8	7	4
Norway		106	112	105
United Kingdom		41	71	76
North Africa		556	567	662
Algeria		88	109	96
Egypt		227	206	189
Libya		228	239	365
Tunisia		13	13	12
Sub-Saharan Africa		332	325	341
Angola		87	84	101
Congo		120	106	103
Nigeria		125	135	137
Kazakhstan		100	88	95
Rest of Asia		144	98	135
China		8	4	3
India		1	1	1
Indonesia		16	16	17
Iran		4	1	22
Iraq		22	21	40
Pakistan		52	45	41
Russia		31
Turkmenistan		10	10	11
Americas		116	125	147
Ecuador		13	12	11
Trinidad & Tobago		11	11	13
United States		82	92	98
Venezuela		10	10	25
Australia and Oceania		30	26	26
Australia		30	26	26
Total outside Italy		1,433	1,419	1,591
		1,619	1,598	1,760
of which equity-accounted entities		54	22	34
Angola		3	2
Indonesia		5	5	5
Russia		31
Tunisia		5	5	4
Venezuela		10	10	25

Oil and natural gas production sold	2013	2014	2015
Oil and natural gas production (mmboe)	591.0	583.1	642.4
Change in inventories other	(5.7)	(4.2)	(1.9)
Own consumption of gas	(30.0)	(29.4)	(26.4)
Oil and natural gas production sold(b)	555.3	549.5	614.1
Oil (mmbbl)	299.54	299.78	330.12
- of which to mid-downstream sectors	178.83	184.74	201.92
Natural gas (bcf)	1,405	1,371	1,560
- of which to G&P	385	371	394

(a) Includes volumes of gas consumed in operations (397, 442 and 451 mmcf/d, in 2015, 2014 and 2013, respectively).

(b) Includes 11.4 mmboe of equity-accounted entities production sold in 2015 (6.1 and 17.1 mmboe in 2014 and 2013, respectively).

Italy 71 73 69 Rest of Europe 77 93 85 Norway 60 62 57 United Kingdom 17 31 28 North Africa 252 252 272 Algeria 73 83 79 Egypt 93 88 96 Libya 76 73 89 Tunisia 10 8 8 Sub-Saharan Africa 242 231 256 Angola 79 75 96 Congo 90 80 78 Nigeria 73 76 82 Kazakhstan 61 52 56 Rest of Asia 49 37 78 China 7 4 3 Indonesia 2 2 3 Iran 4 1 22 Iraq 22 21 40 Russia 5 Turkmenistan 9 9 10 Americas 71 84 87 Ecuador 13 12 11 United States 48 62 64 Venezuela 10 10 12 Australia and Oceania 10 6 5 Australia 10 6 5 Total outside Italy 762 755 839 833 828 908 of which equity-accounted entities 20 15 17 Indonesia 1 1 1 Russia 5 Tunisia 4 4 4	Liquids production by Country	(kbbl/d)	2013	2014	2015
	Venezuela		10	10	12

Oil and natural gas production available for sale(a)	(kboe/d)	2013	2014	2015
Italy		179	171	161
Rest of Europe		149	184	179
North Africa		528	532	635
Sub-Saharan Africa		307	307	324
Kazakhstan		96	85	92
Rest of Asia		135	91	128
Americas		114	122	144
Australia and Oceania		29	25	25
		1,537	1,517	1,688
of which equity-accounted entities		51	20	33
North Africa		5	4	4
Sub-Saharan Africa		2	2
Rest of Asia		34	4	5
Americas		10	10	24

(a) Do not include natural gas consumed in operation.

Natural gas production by Country(a)	(mmcf/d)	2013	2014	2015
Italy		630.2	583.8	546.6
Rest of Europe		429.6	535.2	551.8
Croatia		43.0	38.2	21.2
Norway		250.5	274.2	264.6
United Kingdom		136.1	222.8	266.0
North Africa		1,674.2	1,724.2	2,143.2
Algeria		81.6	141.3	94.1
Egypt		734.6	649.8	510.1
Libya		836.7	911.2	1,517.3
Tunisia		21.3	21.9	21.7
Sub-Saharan Africa		495.9	517.8	469.2
Angola		46.9	48.6	32.5
Congo		161.8	145.1	136.8
Nigeria		287.2	324.1	299.9
Kazakhstan		213.5	200.7	218.3
Rest of Asia		520.5	333.6	313.9
China		3.4
India		7.2	3.7	2.6
Indonesia		79.2	75.8	78.9
Pakistan		283.1	248.2	226.4
Russia		141.6
Turkmenistan		6.0	5.9	6.0
Americas		245.3	218.6	326.0
Trinidad & Tobago		58.6	60.3	70.4
United States		185.9	157.5	186.7
Venezuela		0.8	0.8	68.9
Australia and Oceania		110.4	110.5	111.8
Australia		110.4	110.5	111.8
Total outside Italy		3,689.4	3,640.6	4,134.2
		4,319.6	4,224.4	4,680.8
of which equity-accounted entities		186.3	39.6	99.1
Angola		14.2	10.3	0.9
Indonesia		24.2	23.2	24.1
Russia		141.6
Tunisia		5.5	5.3	5.2
Venezuela		0.8	0.8	68.9

Natural gas production available for sale(b)	(mmcf/d)	2013	2014	2015
Italy		593	541	503
Rest of Europe		395	498	515
North Africa		1,514	1,536	1,993
Sub-Saharan Africa		356	418	378
Kazakhstan		195	181	199
Rest of Asia		476	297	278
Americas		234	205	311
Australia and Oceania		105	106	107
		3,868	3,782	4,284
of which equity-accounted entities		165	28	90
North Africa		4	3	3
Sub-Saharan Africa		7	7
Rest of Asia		154	18	19
Americas				68

(a) Includes volumes of gas consumed in operations (397, 442 and 451 mmcf/d, in 2015, 2014 and 2013 respectively).

(b) Do not include natural gas consumed in operation.

Average realizations 2013 2014						2015
Liquids	Consolidated subsidiaries	Equity-accounted entities	Consolidated subsidiaries	Equity-accounted entities	Consolidated subsidiaries	Equity-accounted entities
(\$/bbl)
Italy	98.50		87.80		43.46
Rest of Europe	98.97		88.80		45.88
North Africa	100.42	17.96	88.99	17.94	46.66	18.03
Sub-Saharan Africa	105.13		93.45		49.91
Kazakhstan	99.37		91.86		48.26
Rest of Asia	99.69	33.87	77.99	65.90	40.10	27.89
Americas	85.27	93.32	79.13	81.48	43.36	38.18
Australia and Oceania	98.72		91.61		45.84
	100.20	64.92	88.90	70.56	46.46	35.15
Natural gas
(\$/kcf)
Italy	11.65		8.74		6.92
Rest of Europe	10.62		8.49		6.30
North Africa	7.96	6.29	8.08	6.08	4.69	3.78
Sub-Saharan Africa	2.16		2.12		1.49
Kazakhstan	0.64		0.62		0.47
Rest of Asia	5.83	3.49	6.18	15.64	4.83	9.27
Americas	3.37		3.96		2.20	4.24
Australia and Oceania	7.80		7.46		5.07
	7.41	4.00	6.83	14.13	4.54	5.30
Hydrocarbons
(\$/boe)
Italy	77.56		64.80		40.36
Rest of Europe	79.14		67.87		40.21
North Africa	70.51	21.47	65.36	21.43	34.61	18.60
Sub-Saharan Africa	85.08		73.18		40.92
Kazakhstan	62.02		57.20		30.02
Rest of Asia	62.59	21.46	52.75	83.12	35.18	49.42
Americas	57.89	93.32	59.94	81.48	31.71	30.72
Australia and Oceania	61.79		52.46		31.51
	72.97	37.57	65.36	72.19	36.54	31.95
Eni's Group		2013		2014		2015
Liquids (\$/bbl)		99.44		88.71		46.30
Natural gas (\$/kcf)		7.26		6.87		4.55
Hydrocarbons (\$/boe)		71.87		65.49		36.47

Net developed and undeveloped acreage	(square kilometers)	2013	2014	2015
Europe		37,018	44,842	45,123
Italy		17,282	17,297	16,975
Rest of Europe		19,736	27,545	28,148
Africa		137,096	159,341	157,441
North Africa		20,412	21,693	25,699
Sub-Saharan Africa		116,684	137,648	131,742
Asia		79,314	109,237	117,183
Kazakhstan		869	869	869
Rest of Asia		78,445	108,368	116,314
Americas		9,206	7,943	6,628
Australia and Oceania		13,622	13,376	16,333
Total		276,256	334,739	342,708

Principal oil and natural gas interests at December 31, 2015

	Commence	Number	Gross	Net	Gross	Net		Number of	Number of
	ment of operations	of interests	developed(a)(b) acreage	developed(a)(b) acreage	undeveloped(a) acreage	undeveloped(a) acreage	Types of fields/acreage	producing fields	other fields
EUROPE		274	15,873	10,989	52,732	34,134		117	98
Italy	1926	147	10,647	8,924	10,436	8,051	Onshore/Offshore	79	68
Rest of Europe		127	5,226	2,065	42,296	26,083		38	30
Croatia	1996	2	1,975	987			Offshore	10	3
Cyprus	2013	3			12,523	10,018	Offshore
Greenland	2013	2			4,890	1,909	Offshore
Norway	1965	56	2,310	452	7,594	2,662	Offshore	18	24
Portugal	2014	3			9,099	6,370	Offshore
United Kingdom	1964	48	941	626	1,501	1,279	Offshore	10	3
Other countries		13			6,689	3,845	Onshore/Offshore
AFRICA		283	63,142	19,788	260,577	137,653		267	119
North Africa		119	30,392	13,778	26,704	11,921		101	55
Algeria	1981	42	3,222	1,148	187	31	Onshore	33	10
Egypt	1954	57	5,623	2,121	17,829	7,547	Onshore/Offshore	41	22
Libya	1959	10	17,947	8,951	8,688	4,343	Onshore/Offshore	6	20
Tunisia	1961	10	3,600	1,558			Onshore/Offshore	21	3
Sub-Saharan Africa		164	32,750	6,010	233,873	125,732		166	64
Angola	1980	72	7,688	987	13,608	3,417	Onshore/Offshore	56	24
Congo	1968	26	1,794	971	943	383	Onshore/Offshore	28	2
Gabon	2008	6			7,615	7,615	Onshore/Offshore
Ghana	2009	2			226	100	Offshore		1
Ivory Coast	2015	1			1,431	429	Offshore
Kenya	2012	7			61,363	40,426	Offshore
Liberia	2012	3			7,364	1,841	Offshore
Mozambique	2007	6			3,911	1,956	Offshore		6
Nigeria	1962	36	23,268	4,052	8,747	3,380	Onshore/Offshore	82	31
South Africa	2014	1			82,202	32,881	Offshore
Other countries		4			46,463	33,304	Onshore
ASIA		70	17,556	5,803	202,632	111,380		29	22
Kazakhstan	1992	6	2,391	442	2,542	427	Onshore/Offshore	1	5
Rest of Asia		64	15,165	5,361	200,090	110,953		28	17
China	1984	8	77	13	7,056	7,056	Offshore	5
India	2005	11	206	109	16,546	6,058	Onshore/Offshore	4	3
Indonesia	2001	14	3,218	1,217	31,415	23,907	Onshore/Offshore	7	13
Iraq	2009	1	1,074	446			Onshore	1
Myanmar	2014	4			24,080	20,050	Onshore/Offshore
Pakistan	2000	15	10,390	3,396	11,486	5,414	Onshore/Offshore	9	1
Russia	2007	3			62,592	20,862	Offshore
Timor Leste	2006	1			1,538	1,230	Offshore
Turkmenistan	2008	1	200	180			Onshore	2
Vietnam	2013	5			30,777	23,132	Offshore
Other countries		1			14,600	3,244	Offshore
AMERICAS		211	5,245	3,351	9,458	3,277		53	10
Ecuador	1988	1	1,985	1,985			Onshore	1	2
Messico	2015	3			67	67	Offshore
Trinidad & Tobago	1970	1	382	66			Offshore	7
United States	1968	192	1,617	803	2,301	1,315	Onshore/Offshore	42	6
Venezuela	1998	6	1,261	497	1,543	569	Onshore/Offshore	3	1
Other countries		8			5,547	1,326	Offshore		1
AUSTRALIA AND OCEANIA		14	1,140	709	21,679	15,624		3	2
Australia	2001	14	1,140	709	21,679	15,624	Offshore	3	2
Total		852	102,956	40,640	547,078	302,068		469	251

(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.

Capital expenditure	(€ million)	2013	2014	2015
Acquisition of proved and unproved properties		109
North Africa		109
Sub-Saharan Africa
Americas
Exploration		1,669	1,398	820
Italy		32	29	28
Rest of Europe		357	188	176
North Africa		95	227	289
Sub-Saharan Africa		757	635	196
Kazakhstan		1
Rest of Asia		233	160	71
Americas		110	139	54
Australia and Oceania		84	20	6
Development		8,580	9,021	9,341
Italy		743	880	679
Rest of Europe		1,768	1,574	1,264
North Africa		808	832	1,570
Sub-Saharan Africa		2,675	3,085	2,998
Kazakhstan		658	521	835
Rest of Asia		749	1,105	1,333
Americas		1,127	921	637
Australia and Oceania		52	103	25
Other expenditure		117	105	73
		10,475	10,524	10,234

Reserves life index	(years)	2013	2014	2015
Italy		7.3	7.7	7.5
Rest of Europe		9.8	7.8	7.3
North Africa		8.9	8.5	7.1
Sub-Saharan Africa		10.2	11.1	11.0
Kazakhstan		28.8	33.4	34.5
Rest of Asia		5.1	8.1	8.6
Americas		23.0	21.3	20.1
Australia and Oceania		16.0	17.8	16.0
		11.1	11.3	10.7

Reserves replacement ratio	2013		2014		2015
(%)	organic	all sources	organic	all sources	organic	all sources
Italy	62	62	106	106	38	38
Rest of Europe	63	40	77	81	28	28
North Africa	32	34	78	78	80	80
Sub-Saharan Africa	183	183	182	176	153	139
Kazakhstan	83	83	206	206	473	473
Rest of Asia	232		156	156	375	375
Americas	102	102	87	87	324	322
Australia and Oceania	536	536
	105	(7)	112	112	148	145

Exploratory wells activity

		Wells completed(a)						Wells in progress at Dec. 31(b)
	2013		2014		2015		2015
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy				0.6			4.0	2.8
Rest of Europe		3.4		4.3		2.2	9.0	2.3
North Africa	4.9	5.4	3.5	4.3	3.3	5.8	15.0	12.5
Sub-Saharan Africa	3.2	6.6	7.3	7.3	0.6	2.9	34.0	17.8
Kazakhstan		0.4					6.0	1.1
Rest of Asia	4.3	2.7	1.3	4.3		3.4	7.0	2.3
Americas	0.2	1.2	2.0	1.4	1.0	0.3	4.0	2.5
Australia and Oceania		0.5		0.9			1.0	0.3
	12.6	20.2	14.1	23.1	4.9	14.6	80.0	41.6

Development wells activity

		Wells in progress at Dec. 31
	2013		2014		2015		2015
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy	7.4	1.0	12.5		6.0		6.0	3.6
Rest of Europe	6.3		9.8	1.0	10.2	0.1	14.0	3.0
North Africa	61.6	3.3	54.5	1.0	30.5	2.8	17.0	9.2
Sub-Saharan Africa	26.3	1.2	31.6		22.0	2.5	28.0	4.8
Kazakhstan	0.3		1.5		4.7		16.0	3.1
Rest of Asia	61.7	4.3	54.2	1.6	29.7	5.9	6.0	2.3
Americas	13.8		22.1	0.7	17.4	0.1	16.0	9.0
Australia and Oceania			0.1	0.4	0.5
	177.4	9.8	186.3	4.7	121.0	11.4	103.0	35.0

Productive oil and gas wells(d)

		2015
	Oil wells			Natural gas wells
(units)	Gross	Net	Gross	Net
Italy	238.0	192.1	605.0	523.6
Rest of Europe	363.0	59.7	179.0	100.6
North Africa	1,782.0	941.1	211.0	90.7
Sub-Saharan Africa	3,065.0	613.4	344.0	27.2
Kazakhstan	185.0	50.7
Rest of Asia	688.0	457.2	998.0	380.9
Americas	230.0	121.1	328.0	101.6
Australia and Oceania	7.0	3.8	18.0	3.8
	6,558.0	2,439.1	2,683.0	1,228.4

(a) Number of wells net to Eni.

(b) Includes temporary suspended wells pending further evaluation.

(c) 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. (d) Includes 2,135 (744.6 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.

Gas & Power

Key performance indicators

	2013	2014	2015
(No. of accidents per million of worked hours)	1.32	0.46	0.49
(€ million)	79,619	73,434	52,096
	(2,923)	64	(1,258)
	(622)	168	(126)
	(239)	86	(168)
	229	172	154
(bcm)	93.17	89.17	90.88
	12.4	13.3	13.5
(million)	8.00	7.93	7.88
(TWh)	35.05	33.58	34.88
(number)	4,962	4,561	4,484
(mmtonnes CO2 eq)	11.27	10.12	10.57
(scale from 0 to 100)	80.0	81.4	85.6
(cm/kWheq)	0.017	0.017	0.015

(a) Before elimination of intragroup sales.

(b) Include volumes marketed by the Exploration & Production segment of 3.16 bcm (3.06 and 2.61 bcm in 2014 and 2013, respectively).

(c) Refers to LNG sales of the Gas & Power segment (included in worldwide gas sales) and the Exploration & Production segment.

(d) The average evaluation reflects results of customers interviews based on clarity, courtesy and waiting time.

Performance of the year

• ›In 2015, the injury frequency rate of total workforce increased by 6.5% compared to 2014, even if in both years the same number of accidents was recorded (5 injuries).
• ›In 2015 greenhouse gas emissions reported an increase of 4.4%, lower than the power generation increase (up by 5.8%). Furthermore, the energy efficiency initiatives and the start-up of the Bolgiano power plant, allowed to improve all the emission indicators.
• ›The water consumption rate of EniPower's plants decreased by 11.8% due to more efficient water use in the production process at certain sites.
• ›In 2015, adjusted net loss of the Gas & Power segment amounted to €168 million, worsening by €254 million compared to €86 million adjusted net profit reported in 2014. This reflected the one-off economic benefits associated to certain

contract renegotiations recorded in 2014 as well as the negative outcome of a commercial arbitration in the fourth quarter of 2015.

• › Eni worldwide gas sales amounted to 90.88 bcm, up by 1.71 bcm or 1.9% compared to 2014. Eni's sales in Italy increased by 12.9% to 38.44 bcm, due to higher spot sales and more typical winter conditions compared to last year. Sales in the European markets were 38.28 bcm, down by 9.3% from the previous year.
• › Electricity sales were 34.88 TWh, up by 1.30 TWh or 3.9% compared to 2014.
• › Capital expenditure amounting to €154 million mainly concerned the flexibility and upgrading of combined cycle power stations (€69 million) as well as gas marketing initiatives in Italy and abroad (€69 million).

Gas & Power

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 mid and 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. In recent years Eni renegotiated a number of the main long-term supply contracts, thus better aligning gas prices and related trends to market conditions 70% of supply concracts. 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 signed long-term gas supply contracts or holds upstream activities and by access to continental Europe's spot markets. In 2015 Eni consolidated subsidiaries supplied 85.39 bcm of natural gas, up by 2.48 bcm or 3% from 2014. Gas volumes supplied outside Italy (78.66 bcm from consolidated companies), imported in Italy

or sold outside Italy, represented approximately 92% of total supplies, up by 2.67 bcm or 3.5% compared to the previous year, due to higher volumes purchased in Russia (up by 3.65 bcm) and Libya (up by 0.59 bcm), partly offset by lower volumes purchased in the Netherlands (down by 1.73 bcm), Algeria (down by 1.46 bcm) and in the United Kingdom (down by 0.29 bcm). Supplies in Italy (6.73 bcm) registered a slight decrease (down by 0.19 bcm) from 2014 due to mature fields' decline.

Marketing in Italy and Europe

Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers. Overall Eni supplies approximately 1,300 customers including large companies, power generation companies, wholesalers and distributors of natural gas for automotive use. Residential users are approximately 7.88 million amid households, professionals, small and medium-sized enterprises and public bodies located all over Italy, and approximately 2.3 million customers in European countries. In a trading environment characterized by a slight recover in demand (up by 9% in the Italian market compared to the previous year and up by 6.5% in the European Union), a market still depressed mainly compared to the volumes marketed before the crisis and increasing competitive pressure, Eni carried out a number of initiatives (such as renegotiation of supply contracts, efficiency and optimization actions) in order to preserve the business profitability in a weak demand scenario.

Sales and market shares on the Italian gas market	2014 (bcm)			2015
		Volumes sold	Market share (%)	Volumes sold	Market share (%)	% Ch. 2015 vs 2014
Italy to third parties		28.42	45.9	32.56	48.2	14.6
Wholesalers		4.05		4.19		3.5
Italian gas exchange and spot markets		11.96		16.35		36.7
Industries		4.93		4.66		(5.5)
Medium-sized enterprises and services		1.60		1.58		(1.3)
Power generation		1.42		0.88		(38.0)
Residential		4.46		4.90		9.9
Own consumption		5.62		5.88		4.6
TOTAL SALES IN ITALY		34.04	55.0	38.44	56.9	12.9
Gas demand(a)		61.90		67.50		9.0

(a) Source: Italian Ministry of Economic Development.

46 Eni Fact Book

Gas & Power

Gas sales by market	(bcm)	2013	2014	2015
ITALY		35.86	34.04	38.44
Wholesalers		4.58	4.05	4.19
Italian gas exchange and spot markets		10.68	11.96	16.35
Industries		6.07	4.93	4.66
Medium-sized enterprises and services		1.12	1.60	1.58
Power generation		2.11	1.42	0.88
Residential		5.37	4.46	4.90
Own consumption		5.93	5.62	5.88
INTERNATIONAL SALES		57.31	55.13	52.44
Rest of Europe		47.35	46.22	42.89
Importers in Italy		4.67	4.01	4.61
European markets		42.68	42.21	38.28
Iberian Peninsula		4.90	5.31	5.40
Germany/Austria		8.31	7.44	5.82
Benelux		8.68	10.36	7.94
Hungary		1.84	1.55	1.58
UK/Northern Europe		3.51	2.94	1.96
Turkey		6.73	7.12	7.76
France		7.73	7.05	7.11
Other		0.98	0.44	0.71
Extra European markets		7.35	5.85	6.39
E&P in Europe and in the Gulf of Mexico		2.61	3.06	3.16
WORLDWIDE GAS SALES		93.17	89.17	90.88

A review of Eni's presence in key European markets is presented below:

Benelux

Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, by the Belgium Gas & Power branch and its subsidiary Eni Gas&Power NV/SA, in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2015, sales in Benelux were mainly directed to industrial companies, power generation, wholesalers and retail and amounted to 7.94 bcm, down by 2.42 bcm, or 23.4% from 2014, due to lower spot sales.

France

Eni sells natural gas to industrial clients, wholesalers and power generation, as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary Eni Gas & Power France SA. In 2015, sales in the Country amounted to 7.11 bcm, a decrease of 0.06 bcm, or 0.9%, from a year ago.

Germany/Austria

Eni operates in Germany-Austria through Gas & Power branches.

In 2014, Eni divested its 50% stake in EnBW Eni

Verwaltungsgesellschaft (EEV), a joint venture which controls the companies Gasversorgung Süddeutschland (GVS) and Terranets BW operating in the gas marketing and transport, to the partner EnBW. Currently, sales in this market are ensured by Eni's direct sales force. In 2015, total sales in Germany-Austria amounted to 5.82 bcm, a decrease of 1.62 bcm, or 21.8% from the previous year.

Spain

Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and through Unión Fenosa Gas (UFG) (Eni's interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2015, UFG gas sales amounted to 3.16 bcm (1.58 bcm Eni's share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast, and a 7.4% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) regasification plants (42.5% and 18.9%, respectively). In 2015, total sales in the Iberian Peninsula amounted to 5.40 bcm, an increase of 0.09 bcm, or 1.7% from 2014.

Turkey

Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2015, sales amounted to 7.76 bcm, an increase of 0.64 bcm, or 9% from a year ago, mainly due to higher sales to Botas.

United Kingdom

Eni through its subsidiary ETS markets in the United Kingdom the equity gas produced at Eni's fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge and TTF). In 2015, sales amounted to 1.96 bcm, a decrease of 33.3% from a year ago.

1.2 LNG

Eni is present in all phases of the LNG business: liquefaction, gas feeding, shipping, regasification and sale through a direct presence and interests in joint ventures and associates. The LNG business registered a good profitability, leveraging on the growing energy demand in Asia and South America. In the next years Eni intends to increase sales in premium markets, redirecting the availability through portfolio optimization and a higher integration with the upstream segment. In 2015, LNG sales (13.5 bcm) were substantially unchanged from last year (up by 0.2 bcm). In particular, LNG sales of the Gas & Power segment (9 bcm, included in worldwide gas sales) mainly concerned LNG from Qatar, Algeria and Nigeria marketed in Europe and the Far East.

1.3 Power generation

Eni's power generation sites are located in Ferrera Erbognone, Ravenna, Livorno, Mantova, Brindisi, Ferrara and Bolgiano.

In 2015, power generation was 20.69 TWh, up by 1.14 TWh or 5.8% from 2014, mainly due to higher production at Ferrara Erbognone, Ravenna and Brindisi plants following increasing demand. As of December 31, 2015, installed operational capacity was 4.9 GW (4.9 GW as of December 31, 2014). Electricity trading reported a slight increase to 14.19 TWh, due to higher purchases on the spot market (up by 1.1%)

reflecting mainly higher spot sales, almost completely offset by lower electricity sales. In 2015 power sales (34.88 TWh) were directed to the free market (74%), the Italian power exchange (15%), industrial sites (9%) and others (2%). Compared to 2014, a 3.9% increase was attributable to higher sales to wholesalers and residential segment, partially offset by lower volumes traded to small and medium-sized enterprises and to large clients.

2. International transport

Eni, as shipper, has transport rights on a large European and North African networks for transporting natural gas in Italy and Europe, which link key consumption basins with the main producing areas (Russia, Algeria, the North Sea, including the Netherlands, Norway, and Libya). 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, is made up of two lines that are each 370-kilometer long with a transport capacity of 34.3 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 Sicily Channel where it links with the TMPC pipeline;
• 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 Sicily Channel from

Gas & Power

Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;

• the Green Stream pipeline for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y crossing 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 (with a record water depth of more 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. These assets generate a steady operating profit thanks to the sale of transport rights on a long-term basis.

Supply of natural gas	(bcm)	2013	2014	2015
Italy		7.15	6.92	6.73
Outside Italy
Russia		29.59	26.68	30.33
Algeria (including LNG)		9.31	7.51	6.05
Libya		5.78	6.66	7.25
Netherlands		13.06	13.46	11.73
Norway		9.16	8.43	8.40
United Kingdom		3.04	2.64	2.35
Hungary		0.48	0.38	0.21
Qatar (LNG)		2.89	2.98	3.11
Other supplies of natural gas		3.63	5.56	7.21
Other supplies of LNG		1.58	1.69	2.02
		78.52	75.99	78.66
Total supplies of Eni's own companies		85.67	82.91	85.39
Offtake from (input to) storage		(0.58)	(0.20)
Network losses, measurement differences and other changes		(0.31)	(0.25)	(0.34)
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES		84.78	82.46	85.05
AVAILABLE FOR SALE OF ENI'S AFFILIATES		5.78	3.65	2.67
E&P volumes in Europe and Gulf of Mexico		2.61	3.06	3.16
GAS VOLUMES AVAILABLE FOR SALE		93.17	89.17	90.88

Gas & Power

Gas sales by entity	(bcm)	2013	2014	2015
Sales of consolidated companies		83.60	81.73	84.94
Italy (including own consumption)		35.76	34.04	38.44
Rest of Europe		42.3	43.07	41.14
Outside Europe		5.54	4.62	5.36
Sales of Eni's affiliates (net to Eni)		6.96	4.38	2.78
Italy		0.1
Rest of Europe		5.05	3.15	1.75
Outside Europe		1.81	1.23	1.03
E&P in Europe and in the Gulf of Mexico		2.61	3.06	3.16
Worldwide gas sales		93.17	89.17	90.88

LNG sales	(bcm)	2013	2014	2015
G&P sales		8.4	8.9	9.0
Rest of Europe		4.6	5.0	4.8
Extra European markets		3.8	3.9	4.2
E&P sales		4.0	4.4	4.5
Liquefaction plants:
Soyo (Angola)		0.1	0.1
Bontang (Indonesia)		0.5	0.5	0.5
PointFortin (Trinidad & Tobago)		0.6	0.6	0.7
Bonny (Nigeria)		2.4	2.8	2.8
Darwin (Australia)		0.4	0.4	0.5
Total LNG sales		12.4	13.3	13.5

Electricity sales	(TWh)	2013	2014	2015
Free market		28.73	24.86	25.90
Italian Exchange for electricity		1.96	4.71	5.09
Industrial plants		3.31	3.17	3.23
Other(a)		1.05	0.84	0.66
Power sales		35.05	33.58	34.88
Power generation		21.38	19.55	20.69
Trading of electricity(a)		13.67	14.03	14.19

(a) Includes positive and negative network imbalances (difference between electricity placed on the market vs. planned quantities).

	Installed capacity as of	Effective/planned
Power stations	December 31, 2015(a) (MW)	start-up	Technology	Fuel
Brindisi	1,328	2006	CCGT	Gas
Ferrera Erbognone	1,030	2004	CCGT	Gas/syngas
Livorno	200	2000	Power Station	Gas/fuel oil
Mantova	900	2005	CCGT	Gas
Ravenna	1,000	2004	CCGT	Gas
Ferrara(b)	408	2008	Power Station	Gas/fuel oil
Bolgiano	60	2012	CCGT	Gas
Photovoltaic sites	10	2011-2015	Photovoltaic	Photovoltaic
	4,936

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

(b) Eni's share of capacity.

50 Eni Fact Book

Gas & Power

Power generation		2013	2014	2015
Purchases
Purchases of natural gas	(mmcm)	4,295	4,074	4,270
Purchases of other fuels	(ktep)	449	338	313
Production
Power generation	(TWh)	21.38	19.55	20.69
Steam	(ktonnes)	9,907	9,010	9,318
Installed generation capacity	(GW)	4.8	4.9	4.9

Transport infrastructure

Route	Lines	Lenght	Diameter	Transport capacity(a)	Transit capacity(b)	Compression stations
	(units)	(km)	(inch)	(bcm/y)	(bcm/y)	(No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of km 370	740	48	34.3	33.5	5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of 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	(€ million)	2013	2014	2015
Italy		161	128	100
Outside Italy		68	44	54
		229	172	154
Market		206	164	138
Market		87	66	69
Italy		42	30	31
Outside Italy		45	36	38
Power generation		119	98	69
International transport		23	8	16
		229	172	154

Key performance indicators

		2013	2014	2015
Injury frequency rate of total workforce	(No. of accidents per million of worked hours)	1.05	0.89	0.80
Net sales from operations(a)	(€ million)	27,301	24,330	18,458
Operating profit (loss)		(1,534)	(2,107)	(552)
Adjusted operating profit (loss)		(472)	(65)	387
Adjusted net profit (loss)		(246)	(41)	282
Capital expenditure		672	537	408
Refinery throughputs on own account	(mmtonnes)	27.38	25.03	26.41
Conversion index	(%)	62	51	49
Balanced capacity of refineries	(kbbl/d)	787	617	548
Retail sales of petroleum products in Europe	(mmtonnes)	9.69	9.21	8.89
Service stations in Europe at year end	(units)	6,386	6,220	5,846
Average throughput per service station in Europe	(kliters)	1,828	1,725	1,754
Retail efficiency index	(%)	1.28	1.19	1.14
Employees at year end	(units)	8,092	6,441	5,852
Direct GHG emissions	(mmtonnes CO2 eq)	5.20	5.34	5.12
SOx (sulphur oxide) emissions	(ktonnes SO2 eq)	10.80	5.70	5.97
Customer satisfaction index	(likert scale)	8.10	8.20	8.30

(a) Before elimination of intragroup sales.

Performance of the year

• ›In 2015 continued the positive trend in injury frequency rates of total workforce (down by 10.1%).
• › Greenhouse gas emissions reported a decrease of 3.7% in absolute terms. The increase of emissions related to higher volumes processed in the period were offset by the initiatives focused on energy efficiency and reduction of fugitive methane. These actions allowed to reduce the ratio between emissions and throughputs to 17.3%.
• ›In 2015, the Refining & Marketing segment reported an adjusted net profit of €282 million, up by €323 million compared to the adjusted operating loss of €41 million reported in the previous year. This result reflected improved refining margins scenario and restructuring and optimization initiatives, which, together with a better selection of raw materials, reduced refining break-even margin to 5 \$/bl anticipating EBIT break-even to 2015, vs 2017, as expected in the 2015-2018 strategic plan.

• ›In 2015 refining throughputs were 26.41 mmtonnes, up by 1.38 mmtonnes or 5.5% from 2014. On a homogeneous basis, when excluding the impact of the disposal of the refining capacity in Czech Republic and the reconversion shutdown at Gela refinery, Eni's refining throughputs increased by 15%. Volumes processed in Italy increased by 16.4% compared to 2014, reflecting a favorable trading environment.

• ›In 2015 the production of biofuels amounted to 0.20 mmtonnes, up by 53.8% compared to a year ago reflecting the performance of Porto Marghera bio-refinery started-up in 2014.

• › Retail sales in Italy amounted to 5.96 mmtonnes, down by 0.18 mmtonnes or 2.9% from 2014, due to lower volumes marketed in motorway and lease concession networks.
• › Retail sales in the Rest of Europe of 2.93 mmtonnes reported a decrease of 4.6% compared to 2014. This result reflected the disposal of assets in the Czech Republic, Slovakia and Romania, only partially offset by higher volumes marketed in Germany, Switzerland and Austria.
• › Capital expenditure amounting to €408 million mainly related to: (i) refining activities in Italy and outside of Italy (€282 million), aiming mainly at plants maintenance, as well as initiatives in the field of health, security and environment; (ii) enhancement and rebranding of the retail distribution network in Italy (€75 million) and in the Rest of Europe (€51 million).
• ›In 2015, total expenditure in R&D amounted to approximately €27 million. During the year 4 patent applications were filed.

Licensing of EST technology

In September 2015, Eni licensed to Total the use of the Eni's Slurry Technology (EST), as part of the deal, the companies agreed to cooperate in a joint development project for EST, under which Eni will work together with Total to evaluate and tailor the technology to help meet Total's specific requirements. This agreement represents for Eni the first contract of non-exclusive sale of the EST technology user licence and opens the opportunity for a future growth of the new market of own-technology sale, which is possible after the industrial consolidation of the first-world unit operating at Sannazzaro Refinery.

Marketing of Eni Diesel+

Starting from January 2016, the new Eni Diesel+ is available in over 3,500 fuel stations all over Italy. The new fuel has a 15% renewable component, produced from plant oils in Eni's Venice refinery using the Ecofining™ technology. Eni Diesel+ combines the performance features of the latest-generation premium fuels (extends the life of car motors, ensures better performance and reduces consumption by up to 4%) with more care for the environment (reduces CO2 emissions by 5% on average, unburned hydrocarbons by up to 40% and particulate matter by up to 20%).

Refining

1. Refining

Eni is active in the refining segment in Italy and Germany. Furthermore, in Italy, Eni has converted the former Venice refinery into green refinery (the first case in the world of transformation in biorefinery) and also started the green reconversion project in the industrial site of Gela.

In 2015 , the balanced capacity of Eni's refining system was approximately 27.4 mmtonnes (548 kbbl/d) with a conversion index of 49% .

The balanced capacity of owned refineries was 19.4 mmtonnes (388 kbbl/d), with a conversion index of 48% .

In 2015, total throughputs in wholly-owned refineries were 26.41 mmtonnes, up by 1.38 mmtonnes or 5.5% from 2014.

n Italy

Eni's refining system in Italy is composed by three wholly-owned refineries (Sannazzaro, Livorno and Taranto) and a 50% interest in the Milazzo refinery. 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 location with respect to end markets, the integration with Eni's other activities.

Refining system in 2015
	Ownership	Balanced refining capacity (Eni's share)	Utilization rate (Eni's share)	Conversion index(1)	Fluid catalytic cracking (FCC)(2)	Residue conversion(2)	Hydro-cracking(2)	Visbreaking/ Thermal Cracking(2)
	(%)	(kbbl/d)	(kbbl/d)	(%)	(kbbl/d)	(kbbl/d)	(kbbl/d)	(kbbl/d)
Wholly-owned refineries		388	95	48	34	14	90	29
Italy
Sannazzaro	100	200	95	70	34	14	51	29
Taranto	100	104	86	38			39
Livorno	100	84	105	11
Partially-owned refineries		160	96	52	143	25	75	27
Italy
Milazzo	50	100	95	60	45	25	32
Germany
Vohburg/Neustadt (Bayernoil)	20	41	96	36	49		43
Schwedt	8.33	19	104	42	49			27
Total		548	95	49	177	39	165	56

(1) Conversion index: catalytic cracking equivalent capacity/topping capacity (%wt).

(2) Conversion unit capacities are 100%.

Sannazzaro: refinery has a balanced capacity of 200 kbbl/d and a conversion index of 70%. Located in the Po Valley, in the center of the North Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HdC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

Taranto: refinery has a balanced capacity of 104 kbbl/d and a conversion index of 37.6%. Taranto has a strong market position due to the fact that is the only refinery in southern continental Italy, and is upstream integrated with the Val d'Agri fields in Basilicata (Eni 70%) through a pipeline. The main equipments are a topping-vacuum unit, an hydrocracking, a platforming and two desulphurization units.

Livorno: refinery, with a balanced refining capacity of 84 kbbl/d and a conversion index of 11.4%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a toppingvacuum unit, a platforming, two desulphurization units and a dearomatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and dewaxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.

Milazzo: jointly-owned by Eni and Kuwait Petroleum Italy, the refinery has balanced primary refining capacity of 100 kbbl/d (Eni's share) and a conversion rate of 60%. Located on the Northern coast of Sicily, it 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's share in the Schwedt refinery is 8.3% and 20% in Bayernoil, an integrated industrial hub that includes 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 second quarter of 2015 Eni divested its 32.445% interest in the Céska Rafinérská (CRC).

2. Green Refining(*)

Green refineries	Ownership share	Capacity (2015)	Capacity (at regime)	Throughput (2015)
Wholly-owned	(%)	(Ktons/y)	(Ktons/y)	(Ktons/y)
Venice	100	350	560	204
Gela	100	-	750	-
Total		350	1,310	204

Venice: green refinery entered into production in June 2014, with a production capacity of 350 ktonnes/y. The refinery exploits the proprietary EcofiningTM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At regime, the production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing the CO2 emission.

Gela: refinery is located in the Southern coast of Sicily. The refinery was shut-down in March 2014. In November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders a plan to reconvert this plant in a bio-refinery. The front end engineering design is ongoing. The local crude oil production will be exported throughout facilities of the refinery. A Safety Competence Center (SCC), a center of excellence in the security field, has been created on site.

3. Logistics

Eni is a leading operator in the Italian oil and refined products storage and transportation business. It owns an integrated infrastructure consisting of 17 directly managed depots and a network of oil and refined products pipelines. Eni logistic model is organized in three hubs (southern, central and northern Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with other Italian operators to optimize its logistic footprint and increase efficiency. Nine depots are currently operated by seven different joint ventures (Sigemi, Petrolig, Petroven, Petra, Seram, Disma and Toscopetrol). Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network extending approximately 1,462 kilometers. Secondary distribution to retail and wholesale markets is outsourced to independent tanker trucks owners.

4. Oxygenates

Eni, through its subsidiary Ecofuel (100% Eni's share), sells approximately 1 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand), and methanol. About 75% of oxygenates are produced in Eni's plants in Italy (Ravenna) and in Saudi Arabia (in joint venture with Sabic) and the remaining 25% is purchased.

Marketing

1. Retail sales in Italy

Eni is a leader in the Italian retail market of refined products with a 24.5% market share, down by 1 percentage points from 2014. In 2015, retail sales in Italy of 5.96 mmtonnes decreased by approximately 0.18 mmtonnes or 2.9% compared to 2014, driven by increasing competitive pressure. Average gasoline and gasoil throughput (1,569 kliters) decreased by approximately 35 kliters from 2014. As of December 31, 2015, Eni's retail network in Italy consisted of 4,420 service stations, 172 stations less compared to December 31, 2014 (4,592 service stations). This reduction is due to the negative contribution of acquisition/releases concessions (115 units), the closing of service stations with low throughput (56 units) and the lack of renewal of 1 motorway concession. The "you&eni" loyalty program, launched in 2010, finished in January 2015. In April 2016, a new "you&eni" program has been launched, with a 2 years duration, addressed to customers that utilize served modality.

2. Retail Rest of Europe

Retail sales in the Rest of Europe of 2.93 mmtonnes were lower compared to 2014 (down by 4.6%). This result reflected mainly the disposal of assets in the Czech Republic, Slovakia and Romania, only partially offset by higher volumes marketed in Germany, Switzerland and Austria. On a homogeneous basis when excluding the above mentioned disposals, sales increased by 2.7%. At December 31, 2015, Eni's retail network in the Rest of Europe consisted of 1,426 service stations, 202 units less compared to December 31, 2014 mainly due to the assets sale of the East European subsidiaries. Average throughputs (2,272 kliters) were substantially stable comparted to the previous reporting period.

3. Wholesale marketing

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, manufacturing industries, service companies, public utilities and transporters, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers a wide range of products covering all market requirements leveraging on its expertise on fuels' manufacturing. Customer care and product distribution are supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and dealers.

Wholesale sales in Italy were 7.84 mmtonnes, up by approximately 0.27 mmtonnes or 3.6% compared to the previous year, due to higher sales of bunkering fuel oil, gasoil and minor products, partially offset by lower sales of LPG and lubricants. Supplies of feedstock to the petrochemical industry were 1.17 mmtonnes, up by 31.5% compared to the previous reporting period. This reflected higher naptha supply following partial recovery of demand in the industrial segment. Wholesale sales in the Rest of Europe were approximately

3.83 mmtonnes, down by 16.7% from 2014, due to lower sales in the Eastern Europe market following the above-mentioned divestments. Other sales in Italy and outside Italy were 13.08 mmtonnes, up by 1.19 mmtonnes or 10%, mainly due to higher volumes sold to oil companies.

The marketing of LPG in Italy is supported by the Eni's refining production logistic network made of five bottling plants, 1 owned storage site and three storage sites located in the coasts Livorno, Naples and Ravenna. LPG is used as heating and automotive fuel. In 2015, Eni's share of LPG market in Italy was 17.9%. Outside Italy, the main market of Eni is Ecuador, with a market share of 38%.

Eni operates five (owned and co-owned) blending plants, in Italy, Europe, North America, Africa and in 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, manufactured at Eni's refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero. In 2015, Eni share of lubricants market in Italy was 19%.

Supply of oil	(mmtonnes)	2013	2014	2015
Equity crude oil		5.93	5.81	5.04
Other crude oil		19.71	17.21	19.76
Total crude oil purchases		25.64	23.02	24.80
Purchases of intermediate products		2.46	2.02	1.66
Purchases of products		9.62	11.07	10.68
TOTAL PURCHASES		37.72	36.11	37.14
Consumption for power generation		(0.55)	(0.57)	(0.41)
Other changes(a)		(1.59)	(0.62)	(1.22)
		35.58	34.92	35.51

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

Availability of refined products	(mmtonnes)	2013	2014	2015
ITALY
At wholly-owned refineries		18.99	16.24	18.37
Less input on account of third parties		(0.57)	(0.58)	(0.38)
At affiliate refineries		4.14	4.26	4.73
Refinery throughputs on own account		22.56	19.92	22.72
Consumption and losses		(1.23)	(1.33)	(1.52)
Products available for sale		21.33	18.59	21.20
Purchases of refined products and change in inventories		5.73	7.19	6.22
Products transferred to operations outside Italy		(0.83)	(0.73)	(0.48)
Consumption for power generation		(0.55)	(0.57)	(0.41)
Sales of products		25.68	24.48	26.53
OUTSIDE ITALY
Refinery throughputs on own account		4.82	5.11	3.69
Consumption and losses		(0.22)	(0.21)	(0.23)
Products available for sale		4.60	4.90	3.46
Purchases of finished products and change in inventories		4.30	4.48	4.77
Products transferred from Italian operations		0.83	0.73	0.48
Sales of products		9.73	10.11	8.71
Refinery throughputs on own account		27.38	25.03	26.41
Total equity crude input		5.93	5.81	5.04
Total sales of refined products		35.41	34.59	35.24
Crude oil sales		0.18	0.33	0.27
TOTAL SALES		35.59	34.92	35.51

Production and sales by product	(mmtonnes)	2013	2014	2015
Production:
Gasoline		6.17	6.07	6.36
Gasoil		11.31	10.31	10.66
Jet fuel/kerosene		1.41	1.45	1.51
Fuel oil		2.40	2.04	2.46
LPG		0.50	0.49	0.44
Lubricants		0.60	0.54	0.54
Petrochemical feedstock		2.08	1.67	1.86
Other		1.46	0.92	0.84
Total production		25.93	23.49	24.67
Sales:
Italy		25.68	24.48	26.53
Gasoline		2.21	2.00	1.97
Gasoil		8.42	7.61	7.64
Jet fuel/kerosene		1.58	1.59	1.60
Fuel oil		0.24	0.12	0.12
LPG		0.62	0.59	0.58
Lubricants		0.09	0.09	0.08
Petrochemical feedstock		1.24	0.89	1.17
Other		11.28	11.59	13.37
Rest of Europe		9.33	18.76	8.29
Gasoline		1.73	1.80	1.51
Gasoil		4.23	4.48	3.98
Jet fuel/kerosene		0.51	0.55	0.65
Fuel oil		0.22	0.18	0.17
LPG		0.12	0.14	0.10
Lubricants		0.09	0.09	0.09
Other		2.43	11.52	1.79
Extra Europe		0.40	2.89	0.42
Gasoline		0.00	2.23	0.00
LPG		0.39	0.41	0.41
Lubricants		0.01	0.01	0.01
Other		0.00	0.24	0.00
Worldwide
Gasoline		3.94	6.03	3.48
Gasoil		12.65	12.09	11.62
Jet fuel/kerosene		2.09	2.14	2.25
Fuel oil		0.46	0.30	0.29
LPG		1.13	1.14	1.09
Lubricants		0.19	0.19	0.18
Petrochemical feedstock		1.24	0.97	1.17
Other		13.71	21.55	15.16
Total sales		35.41	44.41	35.24

Sales in Italy and outside Italy by market	(mmtonnes)	2013	2014	2015
Retail		6.64	6.14	5.96
Wholesale		8.37	7.57	7.84
		15.01	13.71	13.80
Petrochemicals		1.24	0.89	1.17
Other markets		9.43	9.89	11.56
Sales in Italy		25.68	24.49	26.53
Retail rest of Europe		3.05	3.07	2.93
Wholesale rest of Europe		4.56	4.60	3.83
Wholesale outside Europe		0.10	0.43	0.43
Retail and wholesale sales outside Italy		7.71	8.10	7.19
Other markets		2.02	2.00	1.52
Sales outside Italy		9.73	10.10	8.71
Total sales		35.41	34.59	35.24

Retail and wholesale sales of refined products	(mmtonnes)	2013	2014	2015
Italy		15.01	13.71	13.80
Retail sales		6.64	6.14	5.96
Gasoline		1.96	1.71	1.60
Gasoil		4.33	4.07	3.96
LPG		0.32	0.32	0.36
Other		0.03	0.04	0.04
Wholesale sales		8.37	7.57	7.84
Gasoil		4.09	3.54	3.69
Fuel oil		0.24	0.12	0.12
LPG		0.30	0.28	0.22
Gasoline		0.25	0.30	0.38
Lubricants		0.09	0.09	0.07
Bunker		1.00	0.91	1.07
Jet fuel		1.58	1.59	1.60
Other		0.82	0.74	0.69
Outside Italy (retail + wholesale)		7.71	8.10	7.19
Gasoline		1.73	1.80	1.51
Gasoil		4.23	4.48	3.98
Jet fuel		0.51	0.56	0.65
Fuel oil		0.22	0.18	0.17
Lubricants		0.10	0.10	0.10
LPG		0.51	0.55	0.51
Other		0.41	0.43	0.27
Total		22.72	21.81	20.99

Number of service stations	2013	2014	2015
Italy (units)	4,762	4,592	4,420
Ordinary stations	4,636	4,468	4,297
Highway stations	126	124	123
Outside Italy	1,624	1,628	1,426
Germany	460	469	472
France	169	160	154
Austria/Switzerland	585	591	604
Eastern Europe	410	408	196
Service stations selling Blu products	5,021	5,749	4,466
"Multi-Energy" service stations	6	6	6
Service stations selling LPG and natural gas	1,024	1,206	1,176
Non-oil sales (€ million)	151	151	143

60 Eni Fact Book

Refining & Marketing

Average throughput	(kliters/No. of service stations)	2013	2014	2015
Italy		1,657	1,534	1,569
Germany		3,279	3,299	3,351
France		2,194	2,139	2,244
Austria/Switzerland		1,890	1,891	1,923
Eastern Europe		2,044	1,979	1,802
Average throughput		1,828	1,725	1,754

Market shares in Italy	(%)	2013	2014	2015
Retail		27.5	25.6	24.5
Gasoline		24.8	22.3	21.1
Gasoil		29.6	27.9	26.5
LPG (automotive)		20.8	20.1	22.2
Lubricants		30.4	25.1	24.5
Wholesale		28.8	26.4	27.5
Gasoil		32.7	27.1	27.1
Fuel oil		17.5	13.6	11.1
Bunker		39.4	39.1	40.8
Lubricants		23.5	23.2	19.4
Domestic market share		28.3	26.3	26.2

Retail market shares outside Italy	(%)	2013	2014	2015
Central Europe
Austria		11.9	12.1	12.6
Switzerland		7.3	7.3	8.3
Germany		3.2	3.2	3.3
France		0.9	0.8	0.8
Eastern Europe
Hungary		11.7	11.9	12.1
Czech Republic		9.8	8.9	8.5
Slovakia		9.7	9.5	9.1
Slovenia		2.3	2.4	2.4

Capital expenditure	(€ million)	2013	2014	2015
Italy		598	466	349
Outside Italy		74	71	59
		672	537	408
Refining, supply and logistic		497	362	282
Italy		491	357	274
Outside Italy		6	5	8
Marketing		175	175	126
Italy		107	109	75
Outside Italy		68	66	51
		672	537	408

Profit and loss account (€ million)	2013	2014	2015
Net sales from operations	98,547	93,187	67,740
Other income and revenues	1,117	1,039	1,205
Total revenues	99,664	94,226	68,945
Purchases, services and other	(78,108)	(74,067)	(53,983)
Payroll and related costs	(2,657)	(2,572)	(2,778)
Total operating expenses	(80,765)	(76,639)	(56,761)
Other operating income (expense)	(71)	145	(485)
Depreciation, depletion, amortization and impairments	(10,961)	(10,147)	(14,480)
Operating profit (loss)	7,867	7,585	(2,781)
Finance (expense) income	(999)	(1,181)	(1,323)
Net income from investments	6,083	469	124
Profit (loss) before income taxes	12,951	6,873	(3,980)
Income taxes	(9,055)	(6,681)	(3,147)
Tax rate (%)	69.9	97.2
Net profit (loss) - continuing operations	3,896	192	(7,127)
Attributable to:
- Eni's shareholders	3,472	101	(7,680)
- Non-controlling interest	424	91	553
Net profit (loss) - discontinued operations	1,063	658	(2,251)
Attributable to:
- Eni's shareholders	1,688	1,190	(1,103)
- Non-controlling interest	(625)	(532)	(1,148)
Net profit (loss)	4,959	850	(9,378)
Attributable to:
- Eni's shareholders	5,160	1,291	(8,783)
- Non-controlling interest	(201)	(441)	(595)
Net profit (loss) attributable to Eni's shareholders - continuing operations	3,472	101	(7,680)
Exclusion of inventory holding (gains) losses	291	890	561
Exclusion of special items	(1,264)	1,209	6,421
Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations	2,499	2,200	(698)
Adjusted net profit (loss) attributable to Eni's shareholders - discontinued operations	1,931	1,507	1,134
Adjusted net profit (loss) attributable to Eni's shareholders	4,430	3,707	436

Performance on a standalone basis	(€ million)	2013	2014	2015
Operating profit (loss) - continuing operations		7,867	7,585	(2,781)
Exclusion of inventory holding (gains) losses		503	1,290	814
Exclusion of special items		2,910	1,572	5,762
Adjusted operating profit (loss) - continuing operations		11,280	10,447	3,795
Reinstatement of intercompany transactions vs. discontinued operations		1,856	995	309
Adjusted operating profit (loss) - continuing operations on a standalone basis		13,136	11,442	4,104
Net profit (loss) attributable to Eni's shareholders - continuing operations		3,472	101	(7,680)
Exclusion of inventory holding (gains) losses		291	890	561
Exclusion of special items		(1,264)	1,209	6,421
Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations		2,499	2,200	(698)
Reinstatement of intercompany transactions vs. discontinued operations		1,355	1,654	1,032
Adjusted net profit (loss) attributable to Eni's shareholders on a standalone basis		3,854	3,854	334
Tax Rate (%)		63.2	65.3	93.0

Summarized Group Balance Sheet	(€ million)	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2015
Fixed assets
Property, plant and equipment		63,763	71,962	63,795
Inventories - Compulsory stock		2,573	1,581	909
Intangible assets		3,876	3,645	2,433
Equity-accounted investments and other investments		6,180	5,130	3,263
Receivables and securities held for operating purposes		1,339	1,861	2,026
Net payables related to capital expenditure		(1,255)	(1,971)	(1,276)
		76,476	82,208	71,150
Net working capital
Inventories		7,939	7,555	3,910
Trade receivables		21,212	19,709	12,022
Trade payables		(15,584)	(15,015)	(9,345)
Tax payables and provisions for net deferred tax liabilities		(3,062)	(1,865)	(3,133)
Provisions		(13,120)	(15,898)	(15,266)
Other current assets and liabilities		1,274	222	1,804
		(1,341)	(5,292)	(10,008)
Provisions for employee post-retirement benefits		(1,279)	(1,313)	(1,056)
Discontinued operations and assets held for sale including related liabilities		2,156	291	10,446
CAPITAL EMPLOYED, NET		76,012	75,894	70,532
Shareholders' equity
attributable to: - Eni's shareholders		58,210	59,754	51,753
- Non-controlling interest		2,839	2,455	1,916
		61,049	62,209	53,669
Net borrowings		14,963	13,685	16,863
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		76,012	75,894	70,532

Summarized Group Cash Flow Statement	(€ million)	2013	2014	2015
Net profit (loss) - continuing operations		3,896	192	(7,127)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other non monetary items		8,917	10,919	15,521
- net gains on disposal of assets		(3,877)	(99)	(559)
- dividends, interest, taxes and other changes		9,203	6,822	3,259
Changes in working capital related to operations		121	2,148	4,450
Dividends received, taxes paid, interest (paid) received during the period		(9,128)	(6,820)	(4,363)
Net cash provided by operating activities - continuing operations		9,132	13,162	11,181
Net cash provided by operating activities - discontinued operations		1,894	1,948	722
Net cash provided by operating activities		11,026	15,110	11,903
Capital expenditure - continuing operations		(11,584)	(11,264)	(10,775)
Capital expenditure - discontinued operations		(1,216)	(976)	(781)
Capital expenditure		(12,800)	(12,240)	(11,556)
Investments and purchase of consolidated subsidiaries and businesses		(317)	(408)	(228)
Disposals		6,360	3,684	2,258
Other cash flow related to capital expenditure, investments and disposals		(243)	435	(1,351)
Free cash flow		4,026	6,581	1,026
Borrowings (repayment) of debt related to financing activities		(3,981)	(414)	(300)
Changes in short and long-term financial debt		1,715	(628)	2,126
Dividends paid and changes in non-controlling interests and reserves		(4,225)	(4,434)	(3,477)
Effect of changes in consolidation, exchange differences and cash and cash equivalent related to discontinued operations		(40)	78	(789)
NET CASH FLOW		(2,505)	1,183	(1,414)
NET CASH PROVIDED BY OPERATING ACTIVITIES ON STANDALONE BASIS		10,818	14,378	12,189

Changes in net borrowings	(€ million)	2013	2014	2015
Free cash flow		4,026	6,581	1,026
Net borrowings of acquired companies		(21)	(19)
Net borrowings of divested companies		(23)		83
Exchange differences on net borrowings and other changes		349	(850)	(810)
Dividends paid and changes in non-controlling interest and reserves		(4,225)	(4,434)	(3,477)
CHANGE IN NET BORROWINGS		106	1,278	(3,178)

Net sales from operations	(€ million)	2013	2014	2015
Exploration & Production		31,264	28,488	21,436
Gas & Power		79,619	73,434	52,096
Refining & Marketing		27,201	24,330	18,458
Corporate and other activities		1,496	1,429	1,468
Impact of unrealized intragroup profit elimination		18	54
Consolidation adjustment		(41,051)	(34,548)	(25,718)
		98,547	93,187	67,740

Net sales to customers	(€ million)	2013	2014	2015
Exploration & Production		13,046	11,870	9,321
Gas & Power		61,476	59,183	42,179
Refining & Marketing		23,852	21,921	16,086
Corporate and other activities		155	159	154
Impact of unrealized intragroup profit elimination		18	54
		98,547	93,187	67,740

Net sales by geographic area of destination	(€ million)	2013	2014	2015
Italy		29,049	26,921	22,366
Other EU Countries		28,966	27,112	18,637
Rest of Europe		10,849	11,729	6,934
Americas		5,259	5,658	4,156
Asia		13,886	12,683	8,936
Africa		9,990	8,776	6,470
Other areas		548	308	241
Total outside Italy		69,498	66,266	45,374
		98,547	93,187	67,740

Net sales by geographic area of origin	(€ million)	2013	2014	2015
Italy		65,527	63,057	43,851
Other EU Countries		12,495	11,210	8,943
Rest of Europe		3,194	3,215	2,561
Africa		11,069	10,023	7,629
Americas		3,783	3,528	2,893
Asia		2,135	1,848	1,631
Other areas		344	306	232
Total outside Italy		33,020	30,130	23,889
		98,547	93,187	67,740

64 Eni Fact Book

Purchases, services and other	(€ million)	2013	2014	2015
Production costs - raw, ancillary and consumable materials and goods		62,226	58,655	37,801
Production costs - services		12,044	11,443	12,389
Operating leases and other		2,606	2,635	2,189
Net provisions		709	312	634
Other expenses		904	1,349	1,387
less:
capitalized direct costs associated with self-constructed tangible and intangible assets		(381)	(327)	(417)
		78,108	74,067	53,983

Principal accountant fees and services	(€ thousand)	2013	2014	2015
Audit fees		28,023	27,607	33,752
Audit-related fees		1,574	1,287	1,138
Tax fees		21	11	3
		29,618	28,905	34,893

Payroll and related costs	(€ million)	2013	2014	2015
Wages and salaries		2,112	2,319	2,391
Social security contributions		372	367	378
Cost related to defined benefit plans and defined contribution plans		62	69	82
Other costs		335	144	166
less:
capitalized direct costs associated with self-constructed tangible and intangible assets		(224)	(327)	(239)
		2,657	2,572	2,778

Depreciation, depletion, amortization and impairments	(€ million)	2013	2014	2015
Exploration & Production		7,810	8,473	8,902
Gas & Power		413	335	363
Refining & Marketing		345	282	346
Corporate and other activities		62	70	71
Impact of unrealized intragroup profit elimination		(25)	(26)	(28)
Total depreciation, depletion and amortization		8,605	9,134	9,654
Exploration & Production		19	690	4,502
Gas & Power		1,685	25	152
Refining & Marketing		633	284	152
Corporate and other activities		19	14	20
Total Impairment charges		2,356	1,013	4,826
		10,961	10,147	14,480

Operating profit by segment	(€ million)	2013	2014	2015
Exploration & Production		14,868	10,766	(144)
Gas & Power		(2,923)	64	(1,258)
Refining & Marketing		(1,534)	(2,107)	(552)
Corporate and other activities		(736)	(518)	(497)
Impact of unrealized intragroup profit elimination		(1,808)	(620)	(330)
		7,867	7,585	(2,781)

Non-GAAP measure

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. 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 allow to allocate to future reporting periods gains and losses on re-measurement at fair value of certain non hedging commodity derivatives and exchange rate derivatives relating to commercial exposures, lacking the criteria to be designed as hedges, including the ineffective portion of cash flow hedges and certain derivative financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production segment.

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 segmentoperated 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 segment).

In consideration of the relevance of the discontinued operations on 2015 financial accounting, in order to remove the misrepresentation of IFRS 5 the adjusted performances exclude the above mentioned inventory holding gain or loss and the special items as well as gains and losses of the discontinued operations earned from both third parties and the Group's continuing operations, actually determining the derecognition of the two disposal group. These measures are: standalone adjusted operating profit, standalone adjusted net profit and standalone cash flow from operations. In the following tables are represented: operating profit and adjusted net profit on a standalone basis and on single segment basis as well as the reconciliation of net profit attributable to Eni's shareholders of continuing operations. It is also provided the reconciliation of operating cash flow.

2013

Discontinued operations Impact of unrealized intragroup profit & Construction & Construction Consolidation and Chemicals other activities Corporate and & Production adjustments Gas & Power Chemicals (a) & Marketing Engineering Engineering Exploration elimination	discontinued operations OPERATIONS - on standalone basis Reinstatement of transactions vs. intercompany CONTINUING OPERATIONS CONTINUING
Refining Group TOTAL (€ million)
Reported operating profit (loss) 14,868 (2,923) (1,534) (736) (98) (727) 38 8,888 825 (1,846) (1,021) 7,867	9,713
Exclusion of inventory holding (gains) losses 192 220 213 91 716 (213) (213) 503	503
Exclusion of special items:
environmental charges (1) 93 52 61 205 (61) (61) 144	144
asset impairments 19 1,685 633 19 44 2,400 (44) (44) 2,356	2,356
gains on disposal of assets (283) 1 (9) (3) 107 (187) (107) (107) (294)	(294)
risk provisions 7 292 31 4 334 (4) (4) 330	330
provision for redundancy incentives 52 10 91 92 2 23 270 (25) (25) 245	245
commodity derivatives (2) 317 1 (1) 315 1 (1) 315	316
exchange rate differences
and derivatives (2) (218) 30 (5) (195) 5 (9) (4) (199)	(190)
other (16) 23 3 3 (109) (96) 109 109 13	13
Special items of operating profit (loss) (225) 2,109 842 194 (1) 127 3,046 (126) (10) (136) 2,910	2,920
Adjusted operating profit (loss) 14,643 (622) (472) (542) (99) (387) 129 12,650 486 (1,856) (1,370) 11,280 1,856	13,136
Net finance (expense) income(b) (264) 14 (6) (567) (5) (2) (830) 7 16 23 (807)	(823)
Net income(expense) from
investments(b) 367 70 56 291 2 786 (2) (2) 784	784
Income taxes(b) (8,796) 299 176 129 (151) 51 (90) (8,382) 100 (53) 47 (8,335)	(8,282)
Tax rate (%) 59.7 66.5 74.0	63.2
Adjusted net profit (loss) 5,950 (239) (246) (689) (253) (338) 39 4,224 591 (1,893) (1,302) 2,922 1,893	4,815
of which attributable to:
- non-controlling interest (206) 629 423 538	961
- Eni's shareholders 4,430 (1,931) 2,499 1,355	3,854
Reported net profit (loss) attributable to Eni's shareholders 5,160 (1,688) 3,472	3,472
Exclusion of inventory holding (gains)losses 438 (147) 291	291
Exclusion of special items (1,168) (96) (1,264)	(1,264)
Reinstatement of intercompany transactions vs. discontinued operations	1,355
Adjusted net profit (loss) attributable to Eni's shareholders 4,430 (1,931) 2,499	3,854

(a) Following the announced divestment plan, Chemicals results previously consolidated in the "R&M and Chemicals" sector, are presented separately and accounted as discontinued operations. (b) Excluding special items.

	2014

										Discontinued operations
(€ million)	& Production Exploration	Gas & Power	& Marketing Refining	other activities Corporate and	& Construction Engineering	Chemicals (a)	Impact of unrealized intragroup profit elimination	Group	& Construction and Chemicals Engineering	Consolidation adjustments	TOTAL	CONTINUING OPERATIONS	discontinued operations Reinstatement of transactions vs. intercompany	standalone basis OPERATIONS - on CONTINUING
Reported operating profit (loss)	10,766		64 (2,107)	(518)	18	(704)	398	7,917		686 (1,018)	(332)	7,585		8,603
Exclusion of inventory holding (gains) losses		(119)	1,576			170	(167)	1,460	(170)		(170)	1,290		1,290
Exclusion of special items:
environmental charges			111	41		27		179	(27)		(27)	152		152
asset impairments	692	25	284	14	420	96		1,531	(516)		(516)	1,015		1,015
gains on disposal of assets	(76)		(2)	3	2	45		(28)	(47)		(47)	(75)		(75)
risk provisions	(5)	(42)		12	25			(10)	(25)		(25)	(35)		(35)
provision for redundancy incentives	24	9	(4)	(25)	5			9	(5)		(5)	4		4
commodity derivatives	(28)	(38)	38		9	3		(16)	(12)	12		(16)		(28)
exchange rate differences and derivatives	6	205	14			4		229	(4)	11	7	236		225
other	172	64	25	30		12		303	(12)		(12)	291		291
Special items of operating profit (loss)	785	223	466	75	461	187		2,197	(648)	23	(625)	1,572		1,549
Adjusted operating profit (loss)	11,551	168	(65)	(443)	479	(347)	231	11,574	(132)		(995) (1,127)	10,447	995	11,442
Net finance (expense) income(b)	(287)	7	(9)	(564)	(6)	(3)		(862)	9	30	39	(823)		(853)
Net income(expense) from investments(b)	323	49	67	(156)	21	(3)		301	(18)		(18)	283		283
Income taxes(b)	(7,164) (138)		(34)		311 (185)	75		(79) (7,214)	110	(60)	50	(7,164)		(7,104)
Tax rate (%)	61.8	61.6			37.4			65.5				72.3		65.3
Adjusted net profit (loss)	4,423	86	(41)	(852)	309	(278)	152	3,799		(31) (1,025) (1,056)		2,743	1,025	3,768
of which attributable to:
- non-controlling interest								92			451	543	(629)	(86)
- Eni's shareholders								3,707			(1,507)	2,200	1,654	3,854
Reported net profit (loss) attributable to Eni's shareholders								1,291			(1,190)	101		101
Exclusion of inventory holding (gains) losses								1,008			(118)	890		890
Exclusion of special items								1,408			(199)	1,209		1,209
Reinstatement of intercompany transactions vs. discontinued operations														1,654
Adjusted net profit (loss) attributable to Eni's shareholders								3,707			(1,507)	2,200		3,854

(a) Following the announced divestment plan, Chemicals results previously consolidated in the "R&M and Chemicals" sector, are presented separately and accounted as discontinued operations. (b) Excluding special items.

2015

									Discontinued operations
(€ million)	& Production Exploration	Gas & Power	& Marketing Refining	other activities Corporate and	& Construction Engineering	Chemicals (a)	Impact of unrealized intragroup profit elimination	Group	& Construction and Chemicals Engineering	Consolidation adjustments	TOTAL	CONTINUING OPERATIONS	discontinued operations Reinstatement of transactions vs. intercompany	standalone basis OPERATIONS - on CONTINUING
Reported operating profit (loss)		(144) (1,258)	(552)			(497) (694) (1,393)		(23) (4,561)	2,087	(307)		1,780 (2,781)		(2,474)
Exclusion of inventory holding (gains) losses		132	555			322	127	1,136	(322)		(322)	814		814
Exclusion of special items:
environmental charges			116	88		21		225	(21)		(21)	204		204
asset impairments	4,502	152	152	20	590	1,376		6,792	(1,966)		(1,966)	4,826		4,826
gains on disposal of assets	(414)		(5)	4	1	(3)		(417)	2		2	(415)		(415)
risk provisions		226	7	(10)		(12)		211	12		12	223		223
provision for redundancy incentives	15	6	5	1	12	3		42	(15)		(15)	27		27
commodity derivatives	12	90	72		(6)	(4)		164	10	(10)		164		174
exchange rate differences
and derivatives	(59)	(9)				5		(63)	(5)	8	3	(60)		(68)
other	196	535	37	25		(7)		786	7		7	793		793
Special items of operating profit (loss)	4,252	1,000	384	128	597	1,379		7,740	(1,976)		(2) (1,978)	5,762		5,764
Adjusted operating profit (loss)	4,108	(126)	387	(369)	(97)	308	104	4,315	(211)	(309)	(520)	3,795	309	4,104
Net finance (expense) income(b)	(286)	11	(12)	(686)	(5)	10		(968)	(5)	18	13	(955)		(973)
Net income(expense) from investments(b)	253	(2)	72	285	17	(3)		622	(14)		(14)	608		608
Income taxes(b)	(3,323)	(51)	(165)		107 (212)	(85)		(47) (3,776)	297	(62)		235 (3,541)		(3,479)
Tax rate (%)	81.5		36.9					95.1						93.0
Adjusted net profit (loss)	752	(168)	282		(663) (297)	230	57	193	67	(353)	(286)	(93)	353	260
of which attributable to:
- non-controlling interest								(243)			848	605	(679)	(74)(*)
- Eni's shareholders								436			(1,134)	(698)	1,032	334
Reported net profit (loss) attributable to Eni's shareholders								(8,783)				1,103 (7,680)		(7,680)
Exclusion of inventory holding (gains) losses								782			(221)	561		561
Exclusion of special items								8,437			(2,016)	6,421		6,421
Reinstatement of intercompany transactions vs. discontinued operations														1,032
Adjusted net profit (loss) attributable to Eni's shareholders								436			(1,134)	(698)		334

(a) Following the announced divestment plan, Chemicals results previously consolidated in the "R&M and Chemicals" sector, are presented separately and accounted as discontinued operations.

(b) Excluding special items.

(*) Represents the reinstatement of fiscal impacts and does not refer to non-controlling interests.

(€ million)	2013	2014	2015
Net cash provided by operating activities	11,026	15,110	11,903
Net cash provided by operating activities - discontinued operations	1,894	1,948	722
Net cash provided by operating activities - continuing operations	9,132	13,162	11,181
Reinstatement of intercompany transactions vs. discontinued operations	1,686	1,225	1,008
Net cash provided by operating activities on a standalone basis	10,818	14,387	12,189

Financial Data

Breakdown of special items	(€ million)	2013	2014	2015
Special items of operating profit (loss)		3,046	2,197	7,740
- environmental charges		205	179	225
- asset impairments		2,400	1,531	6,792
- gains on disposal of assets		(187)	(28)	(417)
- risk provisions		334	(10)	211
- provision for redundancy incentives		270	9	42
- commodity derivatives		315	(16)	164
- exchange rate differences and derivatives		(195)	229	(63)
- other		(96)	303	786
Net finance (income) expense		179	203	282
of which:
exchange rate differences and derivatives		195	(229)	63
Net income (expense) from investments		(5,299)	(189)	471
of which:
gains on disposals of assets		(3,599)	(159)	(33)
impairments/revaluation of equity investments		(1,682)	(38)	489
Income taxes		901	(270)	297
of which:
impairment of deferred tax assets of Italian subsidiaries		954	976	851
other net tax refund			(824)
deferred tax adjustment on PSAs		490	69
impairment of deferred tax assets of upstream business				860
taxes on special items of operating profit (loss) and other special items		(543)	(491)	(1,414)
Total special items of net profit (loss)		(1,173)	1,941	8,790
attributable to:
- Non-controlling interest		(5)	533	353
- Eni's shareholders		(1,168)	1,408	8,437
of which:
Total special items of discontinued operations		96	199	2,016
impairment due to FV evaluation				1,969
financial derivative on the disposal of 12.5% interest in Saipem				49
other net special items		96	199	(2)

Adjusted operating profit by segment	(€ million)	2013	2014	2015
Exploration & Production		14,643	11,551	4,108
Gas & Power		(622)	168	(126)
Refining & Marketing		(472)	(65)	387
Corporate and other activities		(542)	(443)	(369)
Impact of unrealized intragroup profit elimination		(1,727)	(764)	(205)
		11,280	10,447	3,795

Adjusted net profit by segment	(€ million)	2013	2014	2015
Exploration & Production		5,950	4,423	752
Gas & Power		(239)	86	(168)
Refining & Marketing		(246)	(41)	282
Corporate and other activities		(689)	(852)	(663)
Impact of unrealized intragroup profit elimination		(1,854)	(873)	(296)
		2,922	2,743	(93)
of which attributable to:
Non-controlling interest		423	543	605
Eni's shareholders		2,499	2,200	(698)

70 Eni Fact Book

Finance income (expense)	(€ million)	2013	2014	2015
Exchange differences, net		24	(408)	(351)
Finance income (expense) related to net borrowings and other		(865)	(812)	(1,009)
Net income from securities		8	9	9
Financial expense due to the passage of time (accretion discount)		(240)	(292)	(291)
Income (expense) on derivatives		(92)	165	160
less:
Finance expense capitalized		166	157	159
		(999)	(1,181)	(1,323)
of which, net income from receivables and securities held for financing operating activities and interest on tax credits		57	110	105

Income (expense on) from investments	(€ million)	2013	2014	2015
Share of profit of equity-accounted investments		294	188	146
Share of loss of equity-accounted investments		(84)	(79)	(591)
Gains on disposals		3,598	160	164
Dividends		400	384	402
Decreases (increases) in the provision for losses on investments		10	(5)	(7)
Other income (expense), net		1,865	(179)	10
		6,083	469	124

Property, plant and equipment by segment	(€ million)	2013	2014	2015
Property, plant and equipment, gross
Exploration & Production		107,329	129,331	147,553
Gas & Power		5,763	5,985	6,169
Refining & Marketing		17,383	17,355	17,629
Chemicals		5,898	6,070
Engineering & Construction		12,774	13,657
Corporate and other activities		2,111	2,201	1,854
Impact of unrealized intragroup profit elimination		(490)	(572)	(656)
		150,768	174,027	172,549
Property, plant and equipment, net
Exploration & Production		48,134	56,654	57,608
Gas & Power		1,969	1,985	1,882
Refining & Marketing		4,575	4,460	4,341
Chemicals		1,105	1,193
Engineering & Construction		7,928	7,616
Corporate and other activities		394	452	418
Impact of unrealized intragroup profit elimination		(342)	(398)	(454)
		63,763	71,962	63,795

Capital expenditure by segment	(€ million)	2013	2014	2015
Exploration & Production		10,475	10,524	10,234
Gas & Power		229	172	154
Refining & Marketing		672	537	408
Corporate and other activities		211	113	64
Impact of unrealized intragroup profit elimination		(3)	(82)	(85)
Capital expenditure - continuing operations		11,584	11,264	10,775
Capital expenditure - discontinued operations		1,216	976	781
Capital expenditure		12,800	12,240	11,556
Investments		317	408	228
Capital expenditure and investments		13,117	12,648	11,784

Capital expenditure by geographic area of origin	(€ million)	2013	2014	2015
Italy		1,763	1,544	1,152
Other European Union Countries		875	530	423
Rest of Europe		1,419	1,375	1,124
Africa		4,528	4,832	5,103
Americas		1,248	1,070	699
Asia		1,612	1,787	2,242
Other areas		139	126	32
Total outside Italy		9,821	9,720	9,623
Capital expenditure - continuing operations		11,584	11,264	10,775
Italy		281	241	196
Other European Union Countries		214	323	306
Rest of Europe		134	32	49
Africa		28	32	11
Americas		258	126	53
Asia		187	187	140
Other areas		114	35	26
Total outside Italy		935	735	585
Capital expenditure - discontinued operations		1,216	976	781
Capital expenditure		12,800	12,240	11,556

Net borrowings	(€ million)
	Debt and bonds	Cash and cash equivalents	Securities held for trading and other securities held for non-operating purposes	Financing receivables held for non-operating purposes	Total
2013
Short-term debt	4,685	(5,431)	(5,037)	(129)	(5,912)
Long-term debt	20,875				20,875
	25,560	(5,431)	(5,037)	(129)	14,963
2014
Short-term debt	6,575	(6,614)	(5,037)	(555)	(5,631)
Long-term debt	19,316				19,316
	25,891	(6,614)	(5,037)	(555)	13,685
2015
Short-term debt	8,383	(5,200)	(5,028)	(685)	(2,530)
Long-term debt	19,393				19,393
	27,776	(5,200)	(5,028)	(685)	16,863

Employees

Employees

Employees at year end(*)	(units)	2013	2014	2015
Exploration & Production	Italy	4,133	4,534	4,572
	Outside Italy	8,219	8,243	8,249
		12,352	12,777	12,821
Gas & Power	Italy	2,310	2,067	2,023
	Outside Italy	2,652	2,494	2,461
		4,962	4,561	4,484
Refining & Marketing	Italy	5,777	4,810	4,475
	Outside Italy	2,315	1,631	1,377
		8,092	6,441	5,852
Corporate and other activities	Italy	5,407	5,320	5,650
	Outside Italy	157	304	246
		5,564	5,624	5,896
Total employees at year end	Italy	17,627	16,731	16,720
	Outside Italy	13,343	12,672	12,333
		30,970	29,403	29,053
of which: senior managers		970	958	947

(*) The number of employees at period end differs from the number reported in the tables "2015 performance" at pages 14-16, because the latters do not include equity accounted entities.

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 US Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil & Gas (Topic 932).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an 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 2015, the average price for the marker Brent crude oil was \$54 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report1 . In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs 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 2015, Ryder Scott Company, DeGolyer and MacNaughton and Gaffney, Cline & Associates2 provided an independent evaluation of about 31% of Eni's total proved reserves as of December 31, 20153 , confirming, as in previous years, the reasonableness of Eni's internal evaluations. In the three-year period from 2013 to 2015, 86% of Eni's total proved reserves were subject to independent evaluation.

As of December 31, 2015, the principal properties not subjected to independent evaluation in the last three years are Kashagan (Kazakhstan) and Cafc-Mle (Algeria). Eni operates under production sharing agreements, 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 PSAs 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 51%, 50% and 52% of total proved reserves as of December 31, 2013, 2014 and 2015, 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%, 3% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2013, 2014 and 2015, respectively. Oil and gas reserves 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. Reserves volumes associated with oil and gas deriving from such obligation represent 1%, 0.6% and 0.6% of total proved reserves as of December 31, 2013, 2014 and 2015, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; and (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 crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2013, 2014 and 2015.

• (2) The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2015.
• (3) Including reserves of equity-accounted entities.

⁽¹⁾ From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott and from 2015 also Gaffney, Cline&Associates.

Supplemental oil and gas information

Movements in net proved hydrocarbons reserves

		Rest of Europe						Australia and
(mmboe)	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
2013
Consolidated subsidiaries
Reserves at December 31, 2012	524	591	1,915	1,048	1,041	184	236	128	5,667
of which: developed	406	349	1,080	716	458	108	170	107	3,394
undeveloped	118	242	835	332	583	76	66	21	2,273
Purchase of minerals in place			4						4
Revisions of previous estimates	38	35	59	169	30	81	37	59	508
Improved recovery				5					5
Extensions and discoveries	4	1	6	53		38	6		108
Production	(67)	(57)	(201)	(120)	(36)	(40)	(39)	(11)	(571)
Sales of minerals in place		(13)							(13)
Reserves at December 31, 2013	499	557	1,783	1,155	1,035	263	240	176	5,708
Equity-accounted entities
Reserves at December 31, 2012			20	81		668	730		1,499
of which: developed			20			82	20		122
undeveloped				81		586	710		1,377
Purchase of minerals in place
Revisions of previous estimates			1	(5)		4
Improved recovery
Extensions and discoveries
Production			(2)	(1)		(13)	(4)		(20)
Sales of minerals in place						(652)			(652)
Reserves at December 31, 2013			19	75		7	726		827
Reserves at December 31, 2013	499	557	1,802	1,230	1,035	270	966	176	6,535
Developed	408	343	1,022	701	566	93	171	123	3,427
consolidated subsidiaries	408	343	1,003	701	566	90	153	123	3,387
equity-accounted entities			19			3	18		40
Undeveloped	91	214	780	529	469	177	795	53	3,108
consolidated subsidiaries	91	214	780	454	469	173	87	53	2,321
equity-accounted entities				75		4	708		787

Movements in net proved hydrocarbons reserves

		Rest of Europe		Sub-Saharan				Australia and
			North Africa		Kazakhstan	Rest of Asia	Americas	Oceania
(mmboe)	Italy			Africa					Total
2014
Consolidated subsidiaries
Reserves at December 31, 2013	499	557	1,783	1,155	1,035	263	240	176	5,708
of which: developed	408	343	1,003	701	566	90	153	123	3,387
undeveloped	91	214	780	454	469	173	87	53	2,321
Purchase of minerals in place		4							4
Revisions of previous estimates	68	53	154	110	64	45	26	(7)	513
Improved recovery			3	1	2				6
Extensions and discoveries	1	1	5	98		11	8		124
Production	(65)	(70)	(205)	(118)	(32)	(34)	(42)	(9)	(575)
Sales of minerals in place		(1)		(7)					(8)
Reserves at December 31, 2014	503	544	1,740	1,239	1,069	285	232	160	5,772
Equity-accounted entities
Reserves at December 31, 2013			19	75		7	726		827
of which: developed			19			3	18		40
undeveloped				75		4	708		787
Purchase of minerals in place
Revisions of previous estimates			(1)	7			5		11
Improved recovery
Extensions and discoveries
Production			(2)	(1)		(2)	(3)		(8)
Sales of minerals in place
Reserves at December 31, 2014			16	81		5	728		830
Reserves at December 31, 2014	503	544	1,756	1,320	1,069	290	960	160	6,602
Developed	401	335	919	725	589	115	214	135	3,433
consolidated subsidiaries	401	335	904	702	589	112	188	135	3,366
equity-accounted entities			15	23		3	26		67
Undeveloped	102	209	837	595	480	175	746	25	3,169
consolidated subsidiaries	102	209	836	537	480	173	44	25	2,406
equity-accounted entities			1	58		2	702		763

Supplemental oil and gas information

Movements in net proved hydrocarbons reserves

		Rest of Europe						Australia and
	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
(mmboe) 2015
Consolidated subsidiaries
Reserves at December 31, 2014	503	544	1,740	1,239	1,069	285	232	160	5,772
of which: developed	401	335	904	702	589	112	188	135	3,366
undeveloped	102	209	836	537	480	173	44	25	2,406
Purchase of minerals in place
Revisions of previous estimates	23	19	168	169	164	163	76	(1)	781
Improved recovery			2						2
Extensions and discoveries	1		24	14		21	6		66
Production	(62)	(68)	(240)	(124)	(35)	(47)	(44)	(9)	(629)
Sales of minerals in place				(16)			(1)		(17)
Reserves at December 31, 2015	465	495	1,694	1,282	1,198	422	269	150	5,975
Equity-accounted entities
Reserves at December 31, 2014			16	81		5	728		830
of which: developed			15	23		3	26		67
undeveloped			1	58		2	702		763
Purchase of minerals in place
Revisions of previous estimates				6		1	91		98
Improved recovery
Extensions and discoveries
Production			(2)			(2)	(9)		(13)
Sales of minerals in place
Reserves at December 31, 2015			14	87		4	810		915
Reserves at December 31, 2015	465	495	1,708	1,369	1,198	426	1,079	150	6,890
Developed	362	404	1,024	786	689	161	482	115	4,023
consolidated subsidiaries	362	404	1,010	764	689	159	217	115	3,720
equity-accounted entities			14	22		2	265		303
Undeveloped	103	91	684	583	509	265	597	35	2,867
consolidated subsidiaries	103	91	684	518	509	263	52	35	2,255
equity-accounted entities				65		2	545		612

Eni Fact Book 77

Movements in net proved liquids reserves

		Rest of Europe						Australia and
	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
(mmbbl) 2013
Consolidated subsidiaries
Reserves at December 31, 2012	227	351	904	672	670	82	154	24	3,084
of which: developed	165	180	584	456	203	41	109	24	1,762
undeveloped	62	171	320	216	467	41	45		1,322
Purchase of minerals in place			3						3
Revisions of previous estimates	19	16	12	83	31	62	11	2	236
Improved recovery				5					5
Extensions and discoveries		1	2	51			4		58
Production	(26)	(28)	(91)	(88)	(22)	(16)	(22)	(4)	(297)
Sales of minerals in place		(10)							(10)
Reserves at December 31, 2013	220	330	830	723	679	128	147	22	3,079
Equity-accounted entities
Reserves at December 31, 2012			17	16		114	119		266
of which: developed			17			8	19		44
undeveloped				16		106	100		222
Purchase of minerals in place
Revisions of previous estimates				(1)			1
Improved recovery
Extensions and discoveries
Production			(1)			(2)	(4)		(7)
Sales of minerals in place						(111)			(111)
Reserves at December 31, 2013			16	15		1	116		148
Reserves at December 31, 2013	220	330	846	738	679	129	263	22	3,227
Developed	177	179	577	465	295	38	115	20	1,866
consolidated subsidiaries	177	179	561	465	295	38	96	20	1,831
equity-accounted entities			16				19		35
Undeveloped	43	151	269	273	384	91	148	2	1,361
consolidated subsidiaries	43	151	269	258	384	90	51	2	1,248
equity-accounted entities				15		1	97		113

Supplemental oil and gas information

Movements in net proved liquids reserves

		Rest of Europe						Australia and
	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
(mmbbl) 2014
Consolidated subsidiaries
Reserves at December 31, 2013	220	330	830	723	679	128	147	22	3,079
of which: developed	177	179	561	465	295	38	96	20	1,831
undeveloped	43	151	269	258	384	90	51	2	1,248
Purchase of minerals in place		1							1
Revisions of previous estimates	49	35	32	70	35	16	22	(7)	252
Improved recovery			3	1	2				6
Extensions and discoveries	1		2	36			5		44
Production	(27)	(34)	(91)	(84)	(19)	(13)	(27)	(2)	(297)
Sales of minerals in place		(1)		(7)					(8)
Reserves at December 31, 2014	243	331	776	739	697	131	147	13	3,077
Equity-accounted entities
Reserves at December 31, 2013			16	15		1	116		148
of which: developed			16				19		35
undeveloped				15		1	97		113
Purchase of minerals in place
Revisions of previous estimates			(1)	3			5		7
Improved recovery
Extensions and discoveries
Production			(1)	(1)			(4)		(6)
Sales of minerals in place
Reserves at December 31, 2014			14	17		1	117		149
Reserves at December 31, 2014	243	331	790	756	697	132	264	13	3,226
Developed	184	174	534	477	306	64	142	12	1,893
consolidated subsidiaries	184	174	521	470	306	64	116	12	1,847
equity-accounted entities			13	7			26		46
Undeveloped	59	157	256	279	391	68	122	1	1,333
consolidated subsidiaries	59	157	255	269	391	67	31	1	1,230
equity-accounted entities			1	10		1	91		103

Movements in net proved liquids reserves

		Rest of Europe						Australia and
(mmbbl)	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
2015
Consolidated subsidiaries
Reserves at December 31, 2014	243	331	776	739	697	131	147	13	3,077
of which: developed	184	174	521	470	306	64	116	12	1,847
undeveloped	59	157	255	269	391	67	31	1	1,230
Purchase of minerals in place
Revisions of previous estimates	10	5	139	143	94	159	64	(2)	612
Improved recovery			2						2
Extensions and discoveries			2	14			6		22
Production	(25)	(31)	(98)	(93)	(20)	(28)	(28)	(2)	(325)
Sales of minerals in place				(16)					(16)
Reserves at December 31, 2015	228	305	821	787	771	262	189	9	3,372
Equity-accounted entities
Reserves at December 31, 2014			14	17		1	117		149
of which: developed			13	7			26		46
undeveloped			1	10		1	91		103
Purchase of minerals in place
Revisions of previous estimates				(1)			45		44
Improved recovery
Extensions and discoveries
Production			(1)			(1)	(4)		(6)
Sales of minerals in place
Reserves at December 31, 2015			13	16			158		187
Reserves at December 31, 2015	228	305	834	803	771	262	347	9	3,559
Developed	171	237	555	517	355	126	178	9	2,148
consolidated subsidiaries	171	237	542	511	355	126	149	9	2,100
equity-accounted entities			13	6			29		48
Undeveloped	57	68	279	286	416	136	169		1,411
consolidated subsidiaries	57	68	279	276	416	136	40		1,272
equity-accounted entities				10			129		139

Supplemental oil and gas information

Movements in net proved natural gas reserves(a)

		Rest of Europe						Australia and
	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Oceania	Total
(bcf) 2013
Consolidated subsidiaries
Reserves at December 31, 2012	1,633	1,317	5,558	2,061	2,038	562	449	572	14,190
of which: developed	1,325	925	2,720	1,429	1,401	372	334	459	8,965
undeveloped	308	392	2,838	632	637	190	115	113	5,225
Purchase of minerals in place			5						5
Revisions of previous estimates	105	103	253	475	(3)	104	142	316	1,495
Improved recovery
Extensions and discoveries	24	1	24	14		208	7		278
Production	(230)	(157)	(609)	(176)	(78)	(130)	(89)	(40)	(1,509)
Sales of minerals in place		(17)							(17)
Reserves at December 31, 2013	1,532	1,247	5,231	2,374	1,957	744	509	848	14,442
Equity-accounted entities
Reserves at December 31, 2012			16	353		3,043	3,355		6,767
of which: developed			16			402	6		424
undeveloped				353		2,641	3,349		6,343
Purchase of minerals in place
Revisions of previous estimates			1	(18)		16	(2)		(3)
Improved recovery
Extensions and discoveries
Production			(2)	(5)		(60)			(67)
Sales of minerals in place						(2,971)			(2,971)
Reserves at December 31, 2013			15	330		28	3,353		3,726
Reserves at December 31, 2013	1,532	1,247	5,246	2,704	1,957	772	3,862	848	18,168
Developed	1,266	904	2,447	1,295	1,488	300	315	561	8,576
consolidated subsidiaries	1,266	904	2,432	1,295	1,488	286	310	561	8,542
equity-accounted entities			15			14	5		34
Undeveloped	266	343	2,799	1,409	469	472	3,547	287	9,592
consolidated subsidiaries	266	343	2,799	1,079	469	458	199	287	5,900
equity-accounted entities				330		14	3,348		3,692

(a) Values lower than 1 BCF are not disclosed in this table.

		Rest of Europe		Sub-Saharan				Australia and
			North Africa		Kazakhstan	Rest of Asia	Americas	Oceania
(bcf)	Italy			Africa					Total
2014
Consolidated subsidiaries
Reserves at December 31, 2013	1,532	1,247	5,231	2,374	1,957	744	509	848	14,442
of which: developed	1,266	904	2,432	1,295	1,488	286	310	561	8,542
undeveloped	266	343	2,799	1,079	469	458	199	287	5,900
Purchase of minerals in place		21							21
Revisions of previous estimates	113	99	668	214	165	156	23	(1)	1,437
Improved recovery
Extensions and discoveries			19	341		59	16		435
Production	(213)	(195)	(627)	(185)	(73)	(113)	(80)	(40)	(1,526)
Sales of minerals in place		(1)							(1)
Reserves at December 31, 2014	1,432	1,171	5,291	2,744	2,049	846	468	807	14,808
Equity-accounted entities
Reserves at December 31, 2013			15	330		28	3,353		3,726
of which: developed			15			14	5		34
undeveloped				330		14	3,348		3,692
Purchase of minerals in place
Revisions of previous estimates			2	25		(2)			25
Improved recovery
Extensions and discoveries
Production			(2)	(4)		(8)			(14)
Sales of minerals in place
Reserves at December 31, 2014			15	351		18	3,353		3,737
Reserves at December 31, 2014	1,432	1,171	5,306	3,095	2,049	864	3,821	807	18,545
Developed	1,192	887	2,125	1,360	1,553	271	399	675	8,462
consolidated subsidiaries	1,192	887	2,110	1,271	1,553	261	393	675	8,342
equity-accounted entities			15	89		10	6		120
Undeveloped	240	284	3,181	1,735	496	593	3,422	132	10,083
consolidated subsidiaries	240	284	3,181	1,473	496	585	75	132	6,466
equity-accounted entities				262		8	3,347		3,617

(a) Values lower than 1 BCF are not disclosed in this table.

Supplemental oil and gas information

Movements in net proved natural gas reserves(a)

		Rest of Europe						Australia and
			North Africa		Kazakhstan	Rest of Asia
(bcf)	Italy			Sub-Saharan Africa			Americas	Oceania	Total
2015
Consolidated subsidiaries
Reserves at December 31, 2014	1,432	1,171	5,291	2,744	2,049	846	468	807	14,808
of which: developed	1,192	887	2,110	1,271	1,553	261	393	675	8,342
undeveloped	240	284	3,181	1,473	496	585	75	132	6,466
Purchase of minerals in place
Revisions of previous estimates	68	74	163	145	385	24	69	5	933
Improved recovery
Extensions and discoveries	4		124			114			242
Production	(200)	(201)	(780)	(171)	(80)	(106)	(94)	(41)	(1,673)
Sales of minerals in place				(4)			(4)		(8)
Reserves at December 31, 2015	1,304	1,044	4,798	2,714	2,354	878	439	771	14,302
Equity-accounted entities
Reserves at December 31, 2014			15	351		18	3,353		3,737
of which: developed			15	89		10	6		120
undeveloped				262		8	3,347		3,617
Purchase of minerals in place
Revisions of previous estimates				36		3	253		292
Improved recovery
Extensions and discoveries
Production			(2)			(9)	(25)		(36)
Sales of minerals in place
Reserves at December 31, 2015			13	387		12	3,581		3,993
Reserves at December 31, 2015	1,304	1,044	4,811	3,101	2,354	890	4,020	771	18,295
Developed	1,051	919	2,579	1,475	1,830	194	1,668	585	10,301
consolidated subsidiaries	1,051	919	2,566	1,390	1,830	185	373	585	8,899
equity-accounted entities			13	85		9	1,295		1,402
Undeveloped	253	125	2,232	1,626	524	696	2,352	186	7,994
consolidated subsidiaries	253	125	2,232	1,324	524	693	66	186	5,403
equity-accounted entities				302		3	2,286		2,591

(a) Values lower than 1 BCF are not disclosed in this table.

Results of operations from oil and gas producing activities

	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
(€ million) 2013
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	3,784	2,468	2,341	5,264	396	870	1,537	146	16,806
- sales to third parties		704	7,723	1,855	1,175	864	93	338	12,752
Total revenues	3,784	3,172	10,064	7,119	1,571	1,734	1,630	484	29,558
Operations costs	(391)	(717)	(649)	(932)	(192)	(224)	(342)	(119)	(3,566)
Production taxes	(326)		(317)	(710)		(38)		(25)	(1,416)
Exploration expenses	(32)	(288)	(95)	(869)	(1)	(205)	(136)	(110)	(1,736)
D.D. & A. and Provision for abandonment(a)	(907)	(573)	(1,192)	(1,882)	(111)	(524)	(848)	43	(5,994)
Other income (expenses)	(277)	161	(1,009)	(519)	(105)	(140)	20	(11)	(1,880)
Pretax income from producing activities	1,851	1,755	6,802	2,207	1,162	603	324	262	14,966
Income taxes	(872)	(1,006)	(4,281)	(1,702)	(396)	(178)	(117)	(149)	(8,701)
Results of operations from E&P activities of consolidated subsidiaries(b)	979	749	2,521	505	766	425	207	113	6,265
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			20	26		199	243		488
Total revenues			20	26		199	243		488
Operations costs			(11)	(44)		(18)	(23)		(96)
Production taxes			(4)			(14)	(113)		(131)
Exploration expenses		(8)	(3)			(25)	(1)		(37)
D.D. & A. and Provision for abandonment		(1)	(1)			(65)	(40)		(107)
Other income (expenses)		(4)	5	(12)		(13)	(38)		(62)
Pretax income from producing activities		(13)	6	(30)		64	28		55
Income taxes			(4)	(10)		(35)	30		(19)
Results of operations from E&P activities of equity-accounted entities(b)		(13)	2	(40)		29	58		36

(a) Includes asset impairments amounting to €15 million in 2013.

(b) The "Successful Effort Method" application would have led to an increase of result of operations of €295 million in 2013 for the consolidated subsidiaries and a decrease of €6 million in 2013 for equity-accounted entities.

Supplemental oil and gas information

Results of operations from oil and gas producing activities

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2014
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	3,028	2,721	2,010	4,716	346	589	1,691	67	15,168
- sales to third parties		596	7,415	1,369	976	774	129	299	11,558
Total revenues	3,028	3,317	9,425	6,085	1,322	1,363	1,820	366	26,726
Operations costs	(423)	(687)	(694)	(935)	(208)	(223)	(357)	(124)	(3,651)
Production taxes	(293)		(291)	(648)		(33)		(15)	(1,280)
Exploration expenses	(29)	(227)	(207)	(706)		(185)	(189)	(46)	(1,589)
D.D. & A. and Provision for abandonment(a)	(818)	(1,083)	(1,288)	(2,010)	(91)	(850)	(1,181)	(172)	(7,493)
Other income (expenses)	(184)	(96)	(773)	(358)	(251)	(117)	(78)	(30)	(1,887)
Pretax income from producing activities	1,281	1,224	6,172	1,428	772	(45)	15	(21)	10,826
Income taxes	(351)	(803)	(3,928)	(1,273)	(291)	(112)	(6)	(16)	(6,780)
Results of operations from E&P activities of consolidated subsidiaries(b)	930	421	2,244	155	481	(157)	9	(37)	4,046
Equity-accounted entities Revenues: - sales to consolidated entities
- sales to third parties			19			87	232		338
Total revenues			19			87	232		338
Operations costs			(11)			(11)	(27)		(49)
Production taxes			(3)				(94)		(97)
Exploration expenses		(8)				(45)	(1)		(54)
D.D. & A. and Provision for abandonment		(1)	(1)			(44)	(60)		(106)
Other income (expenses)		(1)	1	(32)		(3)	(42)		(77)
Pretax income from producing activities		(10)	5	(32)		(16)	8		(45)
Income taxes			(4)			(23)	(17)		(44)
Results of operations from E&P activities of equity-accounted entities(b)		(10)	1	(32)		(39)	(9)		(89)

(a) Includes asset impairments amounting to €690 million in 2014.

(b) The "Successful Effort Method" application would have led to a decrease of result of operations of €15 million in 2014 for the consolidated subsidiaries and an increase of €24 million in 2014 for equity-accounted entities.

Eni Fact Book 85

Results of operations from oil and gas producing activities

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2015
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	2,124	1,828	1,403	3,514	231	628	1,118	29	10,875
- sales to third parties		501	5,681	914	659	854	131	226	8,966
Total revenues	2,124	2,329	7,084	4,428	890	1,482	1,249	255	19,841
Operations costs	(403)	(642)	(948)	(1,099)	(239)	(235)	(453)	(108)	(4,127)
Production taxes	(184)		(240)	(405)		(30)		(9)	(868)
Exploration expenses	(28)	(214)	(295)	(226)		(81)	(86)	(25)	(955)
D.D. & A. and Provision for abandonment(a)	(734)	(1,825)	(2,878)	(3,384)	(111)	(1,453)	(1,702)	(110)	(12,197)
Other income (expenses)	(215)	(138)	(565)	(233)	(155)	(277)	(9)	(24)	(1,616)
Pretax income from producing activities	560	(490)	2,158	(919)	385	(594)	(1,001)	(21)	78
Income taxes	(190)	413	(2,165)	7	(155)	60	406	(26)	(1,650)
Results of operations from E&P activities of consolidated subsidiaries(b)	370	(77)	(7)	(912)	230	(534)	(595)	(47)	(1,572)
Equity-accounted entities Revenues:
- sales to consolidated entities
- sales to third parties			19			68	248		335
Total revenues			19			68	248		335
Operations costs			(9)			(13)	(49)		(71)
Production taxes			(3)				(82)		(85)
Exploration expenses		(1)				(30)	(1)		(32)
D.D. & A. and Provision for abandonment		(2)	(2)	(432)		(78)	(76)		(590)
Other income (expenses)		(3)	(1)	(35)		(6)	(48)		(93)
Pretax income from producing activities		(6)	4	(467)		(59)	(8)		(536)
Income taxes			(3)			8	(29)		(24)
Results of operations from E&P activities of equity-accounted entities(b)		(6)	1	(467)		(51)	(37)		(560)

(a) Includes asset impairments amounting to €4,341 million in 2015.

(b) The "Successful Effort Method" application would have led to a decrease of result of operations of €378 million in 2015 for the consolidated subsidiaries and an increase of €15 million in 2015 for equity-accounted entities.

Supplemental oil and gas information

Capitalized cost

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	Australia and Oceania	Total
2014
Consolidated subsidiaries
Proved mineral interests	14,862	13,754	21,549	27,697	2,917	8,827	13,050	1,825	104,481
Unproved mineral interests	31	399	493	3,263	43	1,590	1,588	214	7,621
Support equipment and facilities	346	42	1,569	1,164	94	35	66	13	3,329
Incomplete wells and other	816	3,527	1,411	2,988	7,140	690	819	120	17,511
Gross Capitalized Costs	16,055	17,722	25,022	35,112	10,194	11,142	15,523	2,172	132,942
Accumulated depreciation, depletion and amortization	(11,154)	(9,519)	(14,335)	(20,039)	(1,241)	(8,042)	(10,605)	(1,009)	(75,944)
Net Capitalized Costs consolidated subsidiaries(a)(b)	4,901	8,203	10,687	15,073	8,953	3,100	4,918	1,163	56,998
Equity-accounted entities
Proved mineral interests		2	77	24		539	549		1,191
Unproved mineral interests		31				84			115
Support equipment and facilities			7			1	4		12
Incomplete wells and other		12	5	1,241			776		2,034
Gross Capitalized Costs		45	89	1,265		624	1,329		3,352
Accumulated depreciation, depletion and amortization		(39)	(69)			(522)	(230)		(860)
Net Capitalized Costs equity-accounted entities(a)(b)		6	20	1,265		102	1,099		2,492
2015
Consolidated subsidiaries
Proved mineral interests	14,945	14,921	25,329	34,294	3,352	10,179	14,927	1,962	119,909
Unproved mineral interests	31	402	497	3,502	48	1,712	1,657	237	8,086
Support equipment and facilities	355	42	1,758	1,318	112	34	74	15	3,708
Incomplete wells and other	954	3,189	1,858	2,911	8,708	1,375	670	92	19,757
Gross Capitalized Costs	16,285	18,554	29,442	42,025	12,220	13,300	17,328	2,306	151,460
Accumulated depreciation, depletion and amortization	(11,887)	(11,402)	(18,934)	(25,747)	(1,504)	(9,985)	(12,932)	(1,223)	(93,614)
Net Capitalized Costs consolidated subsidiaries(a)(b)	4,398	7,152	10,508	16,278	10,716	3,315	4,396	1,083	57,846
Equity-accounted entities
Proved mineral interests		3	79	23		635	1,930		2,670
Unproved mineral interests		23				93			116
Support equipment and facilities			8				6		14
Incomplete wells and other		9	5	1,503		1	112		1,630
Gross Capitalized Costs		35	92	1,526		729	2,048		4,430
Accumulated depreciation, depletion and amortization		(31)	(72)	(441)		(676)	(336)		(1,556)
Net Capitalized Costs equity-accounted entities(a)(b)		4	20	1,085		53	1,712		2,874

(a) The amounts include net capitalized financial charges totalling €868 million in 2014 and €1,029 million in 2015 for the consolidated subsidiaries €46 million in 2014 and €92 million in 2015 for equity-accounted entities.

(b) The amounts do not include costs associated with exploration activities which are capitalized in order to reflect their investment nature and amortized in full when incurred. The "Successful Effort Method" application according to eni accounting policy would have led to an increase in net capitalized costs, mainly in relation to exploration cost, of €4,804 million

in 2014 and €4,434 million in 2015 for the consolidated subsidiaries and €123 million in 2014 and €150 million in 2015 for equity-accounted entities.

Eni Fact Book 87

Cost incurred

		Rest of Europe	North Africa	Sub-Saharan	Kazakhstan	Rest of Asia	Americas	Australia and Oceania
(€ million)	Italy			Africa					Total
2013
Consolidated subsidiaries
Proved property acquisitions			64						64
Unproved property acquisitions			45						45
Exploration	32	357	95	757	1	233	110	84	1,669
Development(a)	697	1,855	765	2,617	600	719	1,141	57	8,451
Total costs incurred consolidated
subsidiaries	729	2,212	969	3,374	601	952	1,251	141	10,229
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		5	3			81	1		90
Development(b)		1	5	39		353	318		716
Total costs incurred equity-accounted entities		6	8	39		434	319		806
2014
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	29	188	227	635		160	139	20	1,398
Development(a)	1,382	2,395	955	3,479	572	1,118	1,169	122	11,192
Total costs incurred consolidated
subsidiaries	1,411	2,583	1,182	4,114	572	1,278	1,308	142	12,590
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		2				33	1		36
Development(b)			1	22		38	375		436
Total costs incurred
equity-accounted entities		2	1	22		71	376		472
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	28	176	289	196		71	54	6	820
Development(a)	207	1,006	1,574	2,957	819	1,332	745	18	8,658
Total costs incurred consolidated subsidiaries	235	1,182	1,863	3,153	819	1,403	799	24	9,478
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		1				14	1		16
Development(b)		1	1	112		35	554		703
Total costs incurred
equity-accounted entities		2	1	112		49	555		719

(a) Includes the abandonment costs of the assets for negative for €191 million in 2013, costs for €2,062 million in 2014 and negative for €817 million in 2015. (b) Includes the abandonment costs of the assets for €10 million in 2013, negative €47 million in 2014 and costs for €54 million in 2015.

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 the yearend 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.

Standardized measure of discounted future net cash flows

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	and Oceania Australia	Total
December 31, 2013
Consolidated subsidiaries
Future cash inflows	28,829	33,319	92,661	58,252	50,754	12,487	10,227	5,294	291,823
Future production costs	(6,250)	(6,836)	(16,611)	(15,986)	(9,072)	(3,876)	(2,379)		(1,417) (62,427)
Future development and abandonment costs	(4,593)	(6,202)	(8,083)	(7,061)	(3,445)	(3,960)	(1,561)		(279) (35,184)
Future net inflow before income tax	17,986	20,281	67,967	35,205	38,237	4,651	6,287	3,598	194,212
Future income tax	(5,776)	(12,746)	(35,887)	(20,491)	(9,939)	(1,391)	(2,387)	(1,093)	(89,710)
Future net cash flows	12,210	7,535	32,080	14,714	28,298	3,260	3,900	2,505	104,502
10% discount factor	(5,048)	(2,110)	(14,327)	(5,619)	(16,984)	(1,683)	(1,353)		(1,201) (48,325)
Standardized measure of discounted future net cash flows	7,162	5,425	17,753	9,095	11,314	1,577	2,547	1,304	56,177
Equity-accounted entities
Future cash inflows			524	4,041		262	17,239		22,066
Future production costs			(164)	(1,465)		(38)	(5,467)		(7,134)
Future development and abandonment costs			(17)	(85)		(73)	(2,299)		(2,474)
Future net inflow before income tax			343	2,491		151	9,473		12,458
Future income tax			(20)	(1,617)		(61)	(4,156)		(5,854)
Future net cash flows			323	874		90	5,317		6,604
10% discount factor			(175)	(401)		(20)	(3,681)		(4,277)
Standardized measure of discounted future net cash flows			148	473		70	1,636		2,327
Total	7,162	5,425	17,901	9,568	11,314	1,647	4,183	1,304	58,504

Supplemental oil and gas information

Standardized measure of discounted future net cash flows

	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	and Oceania Australia	Total
(€ million)
December 31, 2014
Consolidated subsidiaries
Future cash inflows	24,951	29,140	96,372	65,853	55,740	13,664	10,955	4,849	301,524
Future production costs	(6,374)	(6,856)	(19,906)	(18,236)	(9,878)	(4,158)	(2,680)		(1,092) (69,180)
Future development and abandonment costs	(4,698)	(5,292)	(9,673)	(9,139)	(4,576)	(4,600)	(1,892)		(356) (40,226)
Future net inflow before income tax	13,879	16,992	66,793	38,478	41,286	4,906	6,383	3,401	192,118
Future income tax	(3,583)	(10,595)	(35,484)	(20,514)	(10,400)	(1,462)	(2,401)	(989)	(85,428)
Future net cash flows	10,296	6,397	31,309	17,964	30,886	3,444	3,982	2,412	106,690
10% discount factor	(4,064)	(1,464)	(13,905)	(7,164)	(19,699)	(1,900)	(1,353)		(1,106) (50,655)
Standardized measure of discounted future net cash flows	6,232	4,933	17,404	10,800	11,187	1,544	2,629	1,306	56,035
Equity-accounted entities
Future cash inflows			485	3,861		200	18,871		23,417
Future production costs			(165)	(692)		(33)	(5,724)		(6,614)
Future development
and abandonment costs			(18)	(104)		(51)	(2,032)		(2,205)
Future net inflow before income tax			302	3,065		116	11,115		14,598
Future income tax			(23)	(426)		(45)	(4,608)		(5,102)
Future net cash flows			279	2,639		71	6,507		9,496
10% discount factor			(158)	(1,442)		(11)	(4,327)		(5,938)
Standardized measure of discounted future net cash flows			121	1,197		60	2,180		3,558
Total	6,232	4,933	17,525	11,997	11,187	1,604	4,809	1,306	59,593

Standardized measure of discounted future net cash flows

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	Americas	and Oceania Australia	Total
December 31, 2015
Consolidated subsidiaries
Future cash inflows	16,760	18,692	58,390	44,114	34,589	13,027	8,101	3,519	197,192
Future production costs	(4,995)	(5,554)	(13,481)	(14,645)	(8,846)	(4,585)	(3,091)		(804) (56,001)
Future development and abandonment costs	(4,299)	(4,379)	(9,457)	(9,359)	(4,108)	(4,964)	(1,644)		(218) (38,428)
Future net inflow before income tax	7,466	8,759	35,452	20,110	21,635	3,478	3,366	2,497	102,763
Future income tax	(1,657)	(4,349)	(17,195)	(8,222)	(4,682)	(1,230)	(933)	(604)	(38,872)
Future net cash flows	5,809	4,410	18,257	11,888	16,953	2,248	2,433	1,893	63,891
10% discount factor	(2,077)	(817)	(7,844)	(4,976)	(10,561)	(1,276)	(970)		(901) (29,422)
Standardized measure of discounted future net cash flows	3,732	3,593	10,413	6,912	6,392	972	1,463	992	34,469
Equity-accounted entities
Future cash inflows			313	3,047		85	18,519		21,964
Future production costs			(177)	(1,021)		(32)	(5,370)		(6,600)
Future development and abandonment costs			(5)	(95)		(22)	(2,118)		(2,240)
Future net inflow before income tax			131	1,931		31	11,031		13,124
Future income tax			(8)	(251)		(10)	(4,088)		(4,357)
Future net cash flows			123	1,680		21	6,943		8,767
10% discount factor			(70)	(1,016)		(2)	(4,358)		(5,446)
Standardized measure of discounted future net cash flows			53	664		19	2,585		3,321
Total	3,732	3,593	10,466	7,576	6,392	991	4,048	992	37,790

Changes in standardized measure of discounted future net cash flows

(€ million)	Consolidated subsidiaries	accounted entities Equity	Total
Standardized measure of discounted future net cash flows at December 31, 2012	61,292	2,946	64,238
Increase (decrease):
- sales, net of production costs	(24,576)	(261)	(24,837)
- net changes in sales and transfer prices, net of production costs	(3,632)	(223)	(3,855)
- extensions, discoveries and improved recovery, net of future production and development costs	1,699	3	1,702
- changes in estimated future development and abandonment costs	(6,821)	(427)	(7,248)
- development costs incurred during the period that reduced future development costs	8,456	665	9,121
- revisions of quantity estimates	6,385	(298)	6,087
- accretion of discount	11,937	521	12,458
- net change in income taxes	5,587	379	5,966
- purchase of reserves in-place	74		74
- sale of reserves in-place	(252)	(770)	(1,022)
- changes in production rates (timing) and other	(3,972)	(208)	(4,180)
Net increase (decrease)	(5,115)	(619)	(5,734)
Standardized measure of discounted future net cash flows at December 31, 2013	56,177	2,327	58,504
Increase (decrease):
- sales, net of production costs	(21,795)	(192)	(21,987)
- net changes in sales and transfer prices, net of production costs	(12,053)	(500)	(12,553)
- extensions, discoveries and improved recovery, net of future production and development costs	1,667		1,667
- changes in estimated future development and abandonment costs	(6,047)	223	(5,824)
- development costs incurred during the period that reduced future development costs	8,745	451	9,196
- revisions of quantity estimates	8,085	(325)	7,760
- accretion of discount	11,064	512	11,576
- net change in income taxes	7,049	704	7,753
- purchase of reserves in-place	67		67
- sale of reserves in-place	(271)		(271)
- changes in production rates (timing) and other	3,347	358	3,705
Net increase (decrease)	(142)	1,231	1,089
Standardized measure of discounted future net cash flows at December 31, 2014	56,035	3,558	59,593
Increase (decrease):
- sales, net of production costs	(14,846)	(179)	(15,025)
- net changes in sales and transfer prices, net of production costs	(70,909)	(2,858)	(73,767)
- extensions, discoveries and improved recovery, net of future production and development costs	524		524
- changes in estimated future development and abandonment costs	(1,711)	(241)	(1,952)
- development costs incurred during the period that reduced future development costs	8,960	604	9,564
- revisions of quantity estimates	12,322	915	13,237
- accretion of discount	11,288	629	11,917
- net change in income taxes	29,530	530	30,060
- purchase of reserves in-place
- sale of reserves in-place	(114)		(114)
- changes in production rates (timing) and other	3,390	363	3,753
Net increase (decrease)	(21,566)	(237)	(21,803)
Standardized measure of discounted future net cash flows at December 31, 2015	34,469	3,321	37,790

Quarterly information

Main financial data of continuing operations(a)

			2014					2015
(€ million)	I quarter		II quarter III quarter IV quarter			I quarter		II quarter III quarter IV quarter
Net sales from operations	25,188	23,182	22,217	22,600	93,187	19,988	19,046	14,817	13,889	67,740
Operating profit (loss)	3,263	1,958	2,270	94	7,585	1,484	1,164	(421)	(5,008)	(2,781)
Adjusted operating profit (loss)	3,070	2,364	2,709	2,304	10,447	1,293	1,307	215	980	3,795
Exploration & Production	3,450	2,981	3,088	2,032	11,551	955	1,533	757	863	4,108
Gas & Power	242	14	(180)	92	168	294	31	(469)	18	(126)
Refining & Marketing	(223)	(164)	111	211	(65)	92	39	163	93	387
Corporate and other activities	(126)	(101)	(107)	(109)	(443)	(89)	(123)	(56)	(101)	(369)
Unrealized profit intragroup elimination and consolidation adjustments	(273)	(366)	(203)	78	(764)	41	(173)	(180)	107	(205)
Net (loss) profit(b)	1,303	658	1,714	(2,384)	1,291	704	(113)	(952)	(8,422)	(8,783)
- continuing operations	851	276	1,268	(2,294)	101	489	34	(1,425)	(6,778)	(7,680)
- discontinued operations	452	382	446	(90)	1,190	215	(147)	473	(1,644)	(1,103)
Capital expenditure	2,283	2,787	2,863	3,331	11,264	2,719	3,150	2,225	2,681	10,775
Investments	60	133	91	124	408	61	47	63	57	228
Net borrowings at period end	13,799	14,601	15,837	13,685	13,685	15,140	16,477	18,414	16,863	16,863

(a) Quarterly data are unaudited.

(b) Net profit attributable to Eni's shareholders.

Key market indicators

	2014					2015
	I quarter		II quarter III quarter IV quarter			I quarter		II quarter III quarter IV quarter
Average price of Brent dated crude oil(a)	108.20	109.63	101.85	76.27	98.99	53.97	61.92	50.26	43.69	52.46
Average EUR/USD exchange rate(b)	1.370	1.371	1.325	1.249	1.329	1.126	1.105	1.112	1.095	1.110
Average price in euro of Brent dated crude oil	78.98	79.96	76.87	61.06	74.48	47.93	56.04	45.20	39.90	47.26
Standard Eni Refining Margin (SERM)(c)	1.17	2.29	4.39	4.97	3.21	7.57	9.13	10.04	6.56	8.32
Price of NBP gas(d)	9.95	7.55	7.03	8.37	8.22	7.27	6.84	6.42	5.56	6.52
Euribor - three-month euro rate (%)	0.30	0.30	0.20	0.08	0.21	0.05	(0.01)	0.00	(0.09)	(0.02)
Libor - three-month dollar rate (%)	0.24	0.20	0.20	0.24	0.23	0.26	0.28	0.31	0.41	0.32

(a) In US\$ per barrel. Source: Platt's Oilgram.

(b) Source: ECB.

(c) In US\$ per barrel. Source: Eni calculations. It gauges the profitability of Eni's refineries against the typical raw material slate and yields.

(d) In US\$ per million BTU (British Thermal Unit). Source: Platt's Oilgram.

Main operating data

		2014					2015
				I quarter II quarter III quarter IV quarter					I quarter II quarter III quarter IV quarter
Liquids production	(kbbl/d)	822	813	812	868	828	860	903	868	998	908
Natural gas production	(mmcf/d)	4,182	4,234	4,197	4,284	4,224	4,596	4,676	4,582	4,868	4,681
Hydrocarbons production	(kboe/d)	1,583	1,584	1,576	1,648	1,598	1,697	1,754	1,703	1,884	1,760
Italy		182	179	174	182	179	165	173	168	169	169
Rest of Europe		192	195	179	196	190	186	181	182	192	185
North Africa		542	549	584	590	567	638	681	647	684	662
Sub-Saharan Africa		324	321	317	339	325	342	343	336	343	341
Kazakhstan		102	90	76	85	88	100	98	82	100	95
Rest of Asia		96	104	93	97	98	109	113	117	201	135
Americas		117	120	131	131	125	128	140	148	170	147
Australia and Oceania		28	26	22	28	26	29	25	23	25	26
Production sold	(mmboe)	134.7	133.0	138.5	143.3	549.5	144.5	153.6	149.8	166.2	614.1
Sales of natural gas to third parties	(bcm)	23.56	16.64	17.50	21.47	79.17	23.47	20.38	18.30	20.07	82.22
Own consumption of natural gas		1.48	1.27	1.44	1.43	5.62	1.54	1.28	1.51	1.55	5.88
Sales to third parties and own concumption		25.04	17.91	18.94	22.90	84.79	25.01	21.66	19.81	21.62	88.10
Sales of natural gas of Eni's affiliates (net to Eni)		1.72	1.18	0.68	0.80	4.38	0.61	0.73	0.68	0.76	2.78
Total sales and own consumption
of natural gas		26.76	19.09	19.62	23.70	89.17	25.62	22.39	20.49	22.38	90.88
Electricity sales	(TWh)	8.25	7.75	8.26	9.32	33.58	8.47	8.35	9.00	9.06	34.88
Sales of refined products	(mmtonnes)	8.06	8.35	9.23	8.95	34.59	8.36	9.43	8.85	8.60	35.24
Retail sales in Italy		1.45	1.60	1.58	1.51	6.14	1.36	1.51	1.58	1.51	5.96
Wholesale sales in Italy		1.68	1.79	2.12	1.98	7.57	1.69	1.99	2.17	1.99	7.84
Retail sales Rest of Europe		0.71	0.78	0.83	0.75	3.07	0.69	0.79	0.77	0.68	2.93
Wholesale sales Rest of Europe		1.01	1.17	1.23	1.19	4.60	1.08	0.98	0.90	0.87	3.83
Wholesale sales outside Europe		0.10	0.11	0.11	0.11	0.43	0.10	0.11	0.11	0.11	0.43
Other markets		3.11	2.90	3.36	3.41	12.78	3.44	4.05	3.33	3.43	14.25

Energy conversion table

Oil (average reference density 32.35 f API, relative density 0.8636)
1 barrel	(bbl)	158.987		l oil(a) 0.159 m3 oil	162.602	m3 gas			5,492	ft3 gas
					5,800,000	btu
1 barrel/d	(bbl/d)	~50	t/y
1 cubic meter	(m3 )	1,000		l oil 6.43 bbl	1,033	m3 gas			36,481	ft3 gas
1 tonne oil equivalent	(toe)	1,160.49		l oil 7.299 bbl	1.161	m3 oil	1,187	m3 gas	41,911	ft3 gas
Gas
1 cubic meter	(m3 )	0.976		l oil 0.00643 bbl	35,314.67	btu			35,315	ft3 gas
1,000 cubic feet	(ft3 )	27.637		l oil 0.1742 bbl	1,000,000	btu	27.317	m3 gas	0.02386	toe
1,000,000 British thermal unit	(btu)	27.4	l oil	0.17 bbl	0.027	m3 oil	28.3	m3 gas	1,000	ft3 gas
1 tonne LNG	(tLNG)	1.2	toe	8.9 bbl	52,000,000	btu			52,000	ft3 gas
Electricity
1 megawatthour=1,000 kWh	(MWh)	93.532		l oil 0.5883 bbl	0.0955	m3 oil	94.448	m3 gas	3,412.14	ft3 gas
1 terajoule	(TJ)	25,981.45		l oil 163.42 bbl	25.9814	m3 oil	26,939.46	m3 gas	947,826.7	ft3 gas
1,000,000 kilocalories	(kcal)	108.8		l oil 0.68 bbl	0.109	m3 oil	112.4	m3 gas	3,968.3	ft3 gas
(a) l oil: liters of oil

Conversion of mass

	kilogram (kg)	pound (lb)	metric ton (t)
kg	1	2.2046	0.001
lb	0.4536	1	0.0004536
t	1,000	22,046	1

Conversion of length

	meter (m)	inch (in)	foot (ft)	yard (yd)
m	1	39.37	3.281	1.093
in	0.0254	1	0.0833	0.0278
ft	0.3048	12	1	0.3333
yd	0.9144	36	3	1

Conversion of volumes

	cubic foot (ft3 )	barrel (bbl)	liter (lt)	cubic meter (m3 )
ft3	1	0	28.32	0.02832
bbl	5.492	1	159	0.158984
l	0.035315	0.0063	1	0.001
m3	35.31485	6.2898	10 3	1

Investor Relations

Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com

Eni SpA

Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital Stock as of December 31, 2015: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1

Publications

Financial Statement pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 Integrated Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Fact Book (in Italian and English) Eni in 2015 (in English) Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 Corporate Governance Report pursuant to rule 123-bis of Legislative Decree No. 58/1998 (in Italian and English) Remuneration Report pursuant to rule 123-ter of Legislative Decree No. 58/1998 (in Italian and English)

Internet home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com

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