Eni

Annual Report • May 12, 2016

Integrated Annual Report 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.

Eni sells in the European market basing on the portfolio availability of equity gas and long-term contracts; sells LNG on a global scale. Produces and sells electricity through gas plants.

Through refineries, Eni processes crude oil to produce fuels, lubricants that are supplied to wholesalers or through retail networks or distributors. Eni engages in the trading of oil, natural gas, LNG and electricity.

		E&P	G&P	R&M
	Austria
Europe	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
	Algeria
Africa	Angola
	Congo
	Egypt
	Gabon
	Ghana
	Ivory Coast
	Kenya
	Liberia
	Libya
	Mozambique
	Nigeria
	South Africa
	Tunisia
	Australia
	China
	India
	Indonesia
	Iraq
	Japan
	Kazakhstan
Asia and Oceania	Kuwait
	Malaysia
	Myanmar
	Oman
	Pakistan
	Russia
	Saudi Arabia
	Singapore
	South Korea
	Taiwan
	the United Arab Emirates
	Timor Leste
	Turkmenistan
	Vietnam
	Argentina
America	Canada
	Ecuador
	Mexico
	the United States
	Trinidad & Tobago Venezuela

Eni's activities

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 our shareholders and, more generally, to all of our stakeholders, respecting the Countries where the company operates and the people who work for and with Eni.

Our way of doing business, based on operating excellence, focus on health, safety and the environment, is committed to preventing and mitigating operational risks.

Integrated Annual Report 2015

Eni's 2015 integrated annual report is prepared in accordance with principles included in the "International Framework", published by International Integrated Reporting Council (IIRC). It is aimed at representing financial and sustainability performance, underlining the existing connections between competitive environment, group strategy, business model, integrated risk management and a stringent corporate governance system. Since 2011, Eni takes part in the IIRC Pilot Program, whose aim is to define an international framework for integrated reporting.

Disclaimer

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

Ordinary Shareholders' Meeting of May 12, 2016. The extract of the notice convening the meeting was published on "Il Sole 24 Ore" and the "Financial Times" of April 7, 2016.

Integrated Annual Report

4 Letter to shareholders

8	Profile of the year
13	Materiality and stakeholder engagement
16	Business model
18	Targets and performance drivers
20	Connectivity of performances
21	Strategy
22	Competitive environment
24	Risk Management
28	Governance
	Operating review
32	Exploration & Production
49	Gas & Power
54	Refining & Marketing
59	Discontinued operations
	Financial review and other information
62	Financial review
66	Profit and loss account
72	Summarized Group Balance sheet
74	Summarized Group Cash Flow Statement
75	Risk factors and uncertainties
92	Outlook
93	Other information
94	Integrated performances
99	Glossary

Letter to shareholders

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 the core oil&gas business, restructuring the industrial setup in other businesses and by improving organizational efficiency.

Among the achieved results, the Saipem transaction was finalized on February 26, 2016. In addition to the deconsolidation of Eni's interest, the reimbursement of intercompany loans has freed important financial sources to be reinvested in the development of the considerable mineral resources recently discovered, while maintaining a strong capital structure.

Exploration has been once again a driver of value creation. Significant discoveries have been made in Indonesia, Congo, Gabon and, above all, in the deep Egyptian offshore with the super giant Zohr gas field. The asset with a potential of up to 30 trillion cubic feet of gas in place represents the largest ever discovery of the Mediterranean Sea. All the discoveries will be developed with competitive time-to-market; in particular Zohr is expected to come on stream by the end of 2017. In 2015, the total additions to the Company's reserve backlog amounted to 1.4 billion of boe, at a unit cost of less than one dollar per barrel.

2015 production averaged 1.76 million of barrel per day, representing an increase of 10% that was the highest rate of growth since 2001. Production was started-up at 10 major fields, among which West Hub in Block 15/06 in Angola and the super giant gas field Perla in Venezuela. These results leveraged on our growth model which envisages, when applicable: i) a phased approach so as to mitigate geological risks and reduce financial exposure; ii) modular and standard solutions which ensure cheaper and quicker availability; and iii) direct supervision of Eni personnel on crucial activities of construction and

commissioning. Consistently with this model, our resources will be even more concentrated on operated projects, preserving our leadership position in project management.

The production replacement rate was 148% thanks to additions from ongoing development projects. New reserves additions were particularly significant in Venezuela, Congo, Ghana and Egypt. At the end of 2015, the Company's proved hydrocarbon reserves amounted to about 7 billion barrels, all conventional, with a life index of 11 years.

In the Refining & Marketing business (R&M), we started a number of initiatives to restructure the industrial setup: the green refinery project at the Venice plant is currently in an advanced phase, while it has started at the Gela site. Widespread actions progressed to upgrade plants and improve energy efficiency and yields at plants with traditional feedstock. These initiatives, along with an improved scenario and steady marketing performance, allowed the segment to achieve positive adjusted operating profit and free cash flow earlier than forecasted.

The Gas & Power (G&P) reported an adjusted operating profit almost at break-even while cash generation was excellent due to almost full recovery of take-or-pay volumes.

These goals were achieved taking into consideration the importance of environmental risk management as well as health and safety of our employees and all those who work at the Company's industrial sites.

Emma Marcegaglia Chairman

Claudio Descalzi Chief Executive Officer and General Manager

In terms of safety and carbon footprint we achieved outstanding results in the year, leveraging on our operating model of excellence standard, strict control of industrial processes and sustainability of our value chain.

In safety we have been the best performer in the industry for the last three years. In 2014, total recordable injury rate was 0.7, 43% lower than the peer average of 1.24. In 2015, we further reduced this rate by 37% to 0.45, confirming our commitment to improving our safety performance, targeting a zero level of injuries every year.

In the 2010-2014 period, we reduced greenhouse gas emissions by 27%, from 59 to 43 million tons, thus reaching a level of unitary emission of 0.2 CO2 per ton of oil equivalent produced. For the future, we plan to further improve these levels, targeting a 43% reduction of emissions by 2025.

These results were made and will be possible thanks to our action plan, able to reconcile short and long-term targets.

This plan is mainly based on: i) focus of our portfolio on conventional projects, featured by lower emission level; ii) increasing exposure to natural gas; iii) flaring down and energy efficiency projects; iv) the green reconversion of part of the downstream business' capacity to produce renewable fuels. Furthermore, this year we set up the Energy Solutions business unit with the purpose of identifying and implementing growth opportunities in the business of renewable energies. In addition, we started to consider in our investment decisions a figurative additional cost of emissions equal to \$40 per ton, so as to enhance energy efficiency among the requisites of projects profitability.

Finally, neither blow-outs nor well accidents have occurred in the last twelve years.

Leveraging on this strategy Eni achieved robust financial results in 20151 .

First of all, cash flow from operations. Cash generation of €12.2 billion, only 15% down from last year, while Brent price has fallen by approximately 50%. This result placed Eni among the

(1) The results described below exclude Saipem and Versalis contributions which are in the disposal phase.

best players in the oil&gas industry. This result was mainly achieved due to the performance of the E&P segment which, with about €9 billion, was confirmed to be the main driver of cash generation. Working capital optimization initiatives in all businesses have also underpinned this result. Capital expenditures decreased by 17% compared to last year, at homogeneous exchange rates, and were funded at 100% with operating cash flow, reducing our target Brent price for organic capex coverage to 50 \$/bl from 63 \$/bl initially foreseen. Dividend cash-out was €3.46 billion. The pro-forma effects of Saipem transaction at December 31, 2015 reduced net debt by €4.8 billion and yielded reduction in leverage to 0.22, compared to 0.31 as of the reporting date.

Adjusted operating profit of €4.1 billion was negatively affected by the commodity scenario, down by about €9 billion, partially offset by €2 billion gains from production growth as well as efficiency and optimization initiatives. Adjusted net profit was positive at €0.3 billion.

Looking ahead, we expect that market imbalances due to the prolonged oversupply and uncertainty on world energy demand will generate a slower recovery in Brent prices. Therefore, we revised downward the Brent scenario in the long-term to 65 \$/bl, compared to 90 \$/bl of the previous plan.

Thus, the strategy was defined taking into account three different time horizons: i) in the short term, financial solidity will be pursued by means of cash flow maximization, leveraging on further efficiency gains and the acceleration of renegotiations of contracts for oilfield services and assets; ii) in the medium term, the focus will be on capex to develop material resources in the Company's portfolio, characterized by a low break even, so as to guarantee reserves' replacement and production growth; iii) in the long-term, we plan to lay foundations for the company in order to get ready for the low-carbon energy era.

In the 2016-2019 period, we estimated an investment plan of €37 billion (net of capex associated with the disposal program), that will be directed for 90% to the upstream, down by 21% compared to the previous plan at constant exchange rates. In spite of the expenditures to develop the new giant project of Zohr, the reduction of total capex will be achieved through the rescheduling/reconfiguration of a number of

development projects and the renegotiation of supply contracts in the upstream segment.

While lowering capital expenditure in the E&P business, we confirm an average annual growth rate of hydrocarbon production higher than 3% for the next four years, thanks to the contribution of several start-ups in addition to the ramp-up of fields started-up in 2015. Start-ups and ramp-ups will add more than 800 kboe/d by 2019. Among the main projects, it is worth mentioning Zohr in Egypt, whose final investment decision was taken at the beginning of 2016, Jangkrik in Indonesia, with the related gas contracts signed in 2015, the East Hub project in the Block 15/06 in Angola, while the West Hub project is in the ramp-up phase. Furthermore, final investment decision for the OCTP project in Ghana was taken in 2015. Among the start-ups of 2016, it is worth mentioning Goliat in Norway started up in March, as well as the re-start of Kashagan, expected in the fourth quarter. Production profitability will be underpinned by lower operating costs and, in some cases, by the revision of petroleum contracts.

The exploration activity will continue to be focused on near-field high-value projects with accelerated returns, in addition to better delineation of recent discoveries. We target to discover 1.6 billion boe of new resources at a unit cost of \$2.3 per barrel in the 2016-2019 period.

In Mozambique, the final investment decision for the Coral development is expected to be taken by the end of 2016, having already obtained government authorization for the development plan and finalized the main terms of the sale of entire gas production.

In the Gas & Power segment, the priority is to consolidate the profitability on the back of an unfavorable scenario featured by weak demand recovery, competitive pressure and institutional uncertainties which hold back the re-launch of the role of gas in the European energy mix. The main drivers will be the renegotiation of long-term contracts to align supply costs to the market conditions, rationalization of logistics, the focus on segments with high added value (such as LNG and retail markets) and, in the long-term, the synergies which will be achieved by the better valorization of gas reserves in the upstream segment thanks to

competences in trading activities. Such actions make us foresee an operating profit structurally positive starting from 2017.

In the Refining & Marketing segment, we expect a gradual worsening of the refining margins, in light of structural weakness of the European refining system due to overcapacity and competitive pressure. The defined actions are aimed to face these expectations, further reducing the break-even margin by upgrading refinery conversion plant, optimization and logistics rationalization as well as by refocusing our portfolio on green fuels. In Marketing activity, profitability will be underpinned by supply differentiation, service quality and innovation, in addition to reduced cost per liter of fuel. Taking into accounts all these drivers, Eni management envisages positive results and cash generation in the next four-year period.

The industrial actions defined in the plan will allow us to preserve cash generation and to grow selectively, creating value for our shareholders. The implementation of a €7 billion disposal program to be carried out in the early years of the plan will provide additional financial resources to support healthy financial ratios across the lows of the cycle. Such disposals will mainly relate to the dilution of our substantial interests in exploration assets, where sizable exploration success was recently achieved (Eni's strategy of "dual exploration model").

Efficiency improvements, contract renegotiations and further flexibility provided by our oil&gas assets portfolio will allow us to lower our threshold for Brent break-even price.

For the year 2016, cash neutrality is expected to be reached at around 50 \$/bl, including disposals, vs the previous guidance of approximately 60 \$/bl, while for the year 2017 the price of cash neutrality, excluding disposals, has been reduced to 60 \$/bl compared to the previous guidance of <75 \$/bl.

We are aware of reach and complexity of the future challenges which will require full engagement, Group identity and commitment of Eni's women and men so as to enable the Company to continue progressing in value creation.

At the same time, we are confident that 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.

We believe that 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.

In light of the achieved results and Company's outlook, we intend to propose to the Annual Shareholders' Meeting a dividend of €0.8 per share, of which €0.4 per share paid as interim dividend in September 2015.

March 17, 2016

In representation of the Board of Directors

Emma Marcegaglia Chairman

Claudio Descalzi Chief Executive Officer and General Manager

Cost optimization
-17% Capex
-13% Upstream opex
- €0.6 bln G&A

Overview › In 2015, on the back of a weak Brent price scenario, Eni achieved remarkable results leveraging on its refocused portfolio, profitable growth in the upstream segment and cost efficiency programs.

Adjusted results from continuing operations on a standalone basis¹ › Adjusted 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.

Cost optimization › Efficiency programs, rationalization and rephasing of costs exceeded our expectations with capex reduced by 17% (vs. an initial guidance of 14%), opex per boe reduced by 13% (vs. an initial guidance of 7%) and G&A down by €0.6 billion (vs. an initial guidance of €0.5 billion).

Mid-downstream business consolidation › The R&M business achieved positive adjusted operating profit and free cash flow earlier than forecasted in our strategic plan. The G&P segment reported an adjusted operating profit almost at break-even, in line with our guidance.

Net result from continuing operations › Net loss of €7.68 billion due to the recognition of impairment losses driven by Eni's outlook for Brent crude oil price.

Cash flow › 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).

Self-financing › Better performance in self-financed capex achieved in 2015 at a Brent price scenario of 50 \$/bl vs an initial guidance of 63 \$/bl for the 2015-2016 period.

Leverage › 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.

Dividend › The Company's robust results and strong fundamentals underpin a dividend distribution of €0.8 per share of which €0.4 per share paid as interim dividend in September 2015.

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

(1) 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.

Eni's transformation process 12.5%

Saipem disposal

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' startups 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.

Zohr discovery › Made a world-class gas discovery at the Zohr exploration prospect in the deep waters of the Egyptian section 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 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.

Proved reserves › Hydrocarbon proved reserves were 6.89 billion boe, with an organic reserve replacement ratio of 148% (135% on average since 2010). Life index was 10.7 years.

Development of new fields › As planned, Eni achieved the start-up of 10 relevant fields among which the giant gas field Perla located offshore Venezuela, retaining a potential of 17 trillion cubic feet of gas in place (or 3.1 billion boe) and has been developed in just 5 years, an industry-leading time-tomarket. The development plan targets a long-term production plateau of approximately 1,200 mmcf/d through a third phase of development.

Furthermore the other relevant ones related to: (i) the Cinguvu field, part of the West Hub Development project in Block 15/06 (Eni operator with a 35% interest) offshore Angola. In addition, early in 2016 the third M'Pungi satellite field came on stream achieving an overall production of 25 kbbl/d net to Eni; (ii) Nené Marine in Congo in early production, just 8 months after obtaining authorization and sixteen months following the discovery; (iii) the Kizomba project off Angola, Lucius and Hadrian off the United States in the Gulf of Mexico, Nooros in Egypt and West Franklin phase 2 in the United Kingdom.

Proved reserves
6.9 bln boe
at year end

Start-up of Goliat › In March 2016, production was started-up at the Goliat field, located within the Production License 229, off Norway. Goliat, the first oil field to start production in the Barents Sea, was developed through the largest and most sophisticated floating cylindrical production and storage vessel (FPSO) in the world. The Unit has a capacity of 1 million barrels of oil. The daily output will reach 100 kboe/d (65 kboe/d net to Eni). The field is estimated to contain reserves amounting to about 180 million barrels of oil.

Mozambique › Approved the development plan of the Coral discovery targeting to put into production 5 trillion cubic feet of gas. The unitization was set out for the development of the natural gas reservoirs straddling Areas 4 (operated by Eni) and 1 (operated by Anadarko).

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.

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 distinguished by their excellent performance in all the fields of sustainability. Eni's inclusion was also confirmed for the ninth consecutive year 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.

Injury frequency rate

Financial highlights(*)
Continuing operations		2013	2014	2015
Net sales from operations	(€ million) 98,547		93,187	67,740
Operating profit (loss)		7,867	7,585	(2,781)
Adjusted operating profit (loss)on a standalone basis(b)		13,136	11,442	4,104
Net profit (loss)(a)		3,472	101	(7,680)
Adjusted net profit (loss) on a standalone basis(a)(b)		3,854	3,854	334
Net profit (loss) - discontinued operations(a)		1,688	1,190	(1,103)
Group net profit (loss)(a) - (continuing + discontinued operations)		5,160	1,291	(8,783)
Comprehensive income(a)		3,164	5,996	(4,503)
Net cash flow from operating activities on a standalone basis(b)		10,818	14,387	12,189
Capital expenditure		11,584	11,264	10,775
of which: exploration		1,669	1,398	820
development of hydrocarbon reserves		8,580	9,021	9,341
Dividends to Eni's shareholders pertaining to the year (c)		3,979	4,037	2,857
Cash dividends to Eni's shareholders		3,949	4,006	3,457
Total assets at year end		138,341	146,207	134,792
Shareholders' equity including non-controlling interests at year end		61,049	62,209	53,669
Net borrowings at year end		14,963	13,685	16,863
Net capital employed at year end		76,012	75,894	70,532
of which: Exploration & Production		45,699	47,629	50,522
Gas & Power		8,462	9,031	5,803
Refining & Marketing		8,737	6,738	5,492
Share price at year end	(€)	17.5	14.5	13.8
Weighted average number of shares outstanding		(million) 3,622.8	3,610.4	3,601.1
Market capitalization(d)	(€ billion)	63	52	50

Summary financial data
		2013	2014	2015
Net profit (loss) - continuing operations
- per share(a)	(€)	0.96	0.03	(2.13)
- per ADR(a) (b)	(\$)	2.55	0.08	(4.73)
Adjusted net profit (loss) - continuing operations
- per share(a)	(€)	0.69	0.61	(0.19)
- per ADR(a)(b)	(\$)	1.83	1.62	(0.42)
Cash flow - continuing operations
- per share(a)	(€)	3.20	3.65	3.10
- per ADR(a)(b)	(\$)	8.49	9.69	6.89
Adjusted return on average capital employed (ROACE)	(%)	8.2	6.6	1.2
Leverage		0.25	0.22	0.31
Current ratio		1.5	1.5	1.4
Debt coverage		77.4	96.2	66.3
Dividends pertaining to the year	(€ per share)	1.10	1.12	0.80
Pay-out	(%)	80	313	(33)
Dividend yield(c)	(%)	6.5	7.6	5.7

(*) 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. The comparative reporting periods have been restated consistently.

(a) Attributable to Eni's shareholders.

(b) Non-GAAP measures. This performance is measured by excluding gains and losses of the discontinued operations earned from both third parties and the Group's continuing operations, determining the deconsolidation of Saipem and Versalis.

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

(d) Number of outstanding shares by reference price at year end.

(a) Fully diluted. Ratio of net profit (loss)/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by ECB for the period presented.

(b) One American Depositary Receipt (ADR) is equal to two Eni ordinary shares.

(c) Ratio of dividend for the period and the average price of Eni shares as recorded in December.

Operating and sustainability data(a)
		2013	2014	2015
Employees at year end	(number) 30,970		29,403	29,053
of which: - women(*)		7,504	7,370	7,254
- outside Italy		13,343	12,672	12,333
Female managers(*)	(%)	23.5	23.8	24.2
Training hours	(thousand hours) 1,493		1,032	915
Employees injury frequency rate	(No. of accidents per million of worked hours)	0.28	0.29	0.21
Contractors injury frequency rate		0.49	0.35	0.18
Fatality index	(Fatal injuries per one hundred millions of worked hours)	0.00	1.08	0.39
Total recordable injury rate of workforce	(Total recordable injuries/ worked hours) x 1,000,000	0.75	0.62	0.40
Oil spills due to operations	(barrels)	1,762	1,161	1,603
Direct GHG emissions	(mmtonnes CO2 eq)	43.9	38.9	38.5
R&D expenditure(b)	(€ million)	142	134	139
Expenditure for the territory(c)		100	96	97
Exploration & Production
Net proved reserves of hydrocarbon	(mmboe)	6,535	6,602	6,890
Average reserve life index	(years)	11.1	11.3	10.7
Hydrocarbon production	(kboe/d)	1,619	1,598	1,760
Profit per boe(d)(e)	(\$/boe)	16.1	13.8	7.4
Opex per boe(d)		8.3	8.4	7.2
Cash flow per boe		31.9	30.1	20.1
Finding & Development cost per boe(e)		19.2	21.5	19.3
Direct GHG emissions	(mmtonnes CO2 eq)	27.4	23.4	22.8
Produced water re-injected	(%)	55	56	56
Community investment	(€ million)	53	63	71
Gas & Power
Worldwide gas sales	(bcm)	93.17	89.17	90.88
- Italy		35.86	34.04	38.44
- outside Italy		57.31	55.13	52.44
Customers in Italy	(million)	8.00	7.93	7.88
Electricity sold	(TWh)	35.05	33.58	34.88
Water withdrawals per KWheq produced	(cm/KWheq)	0.017	0.017	0.015
Customer satisfaction rate(f)	(scale from 0 to 100)	80.0	81.4	85.6
Refining & Marketing
Refinery throughputs on own account	(mmtonnes)	27.38	25.03	26.41
Retail market share in Italy	(%)	27.5	25.5	24.5
Retail sales of refined products in Europe	(mmtonnes)	9.69	9.21	8.89
Service stations in Europe at year end	(number)	6,386	6,220	5,846
Average throughput of service stations in Europe	(kliters)	1,828	1,725	1,754
SOx emissions (sulphur oxide)	(ktonnes SO2 eq)	10.80	5.70	5.97

Customer satisfaction index (likert scale) 8.1 8.2 8.3

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

(a) Pertaining to continuing operations.

(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.

(d) Related to consolidated subsidiaries.

(e) Three-year average.

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

Materiality and stakeholder engagement

Eni's materiality definition process

Materiality is the result of the identification and prioritization of the relevant sustainability issues that impact significantly the company's ability to create value.

Eni's materiality definition process aims to ensure that the relevant issues are both shared with the highest decision levels and also taken into account in all the company processes starting from the integrated risk management process, strategy planning, stakeholder engagement, reporting and internal/external communication, to the implementation of operational decisions.

The first step of the materiality definition process is the identification of relevant issues implemented on the base of the top management's strategic vision, the results of the risk assessment and the stakeholders' perspective.

In 2015, the vision of top management has arisen in the phase of the definition of four-year strategic plan: in the guidelines defined by the Chief Executive Officer, preceding the definition of the four-year plan, were highlighted the most important sustainability issues for the business.

Through the risk assessment carried out in 2015 the sustainability issues on which could emerge environmental, social and governance potential risks (ESG) were highlighted. Finally, the stakeholders' perspective has been defined through the collection of their expectations, gathered and managed by using a specific web-based platform, designed to monitor the relevant issues for stakeholders but also to define their attitude towards the corporate activity, to facilitate their management and to monitor relationships. Following the identification of the most relevant issues, the assessment of their relative importance has been performed on the basis of specific criteria for each field considered. The strategic vision of the top management took into account the importance of each issue in the process of value creation for the company. The risk assessment has determined the impact and likelihood of occurrence of potential risks arising from each single theme. The stakeholders' perspective has highlighted the importance of each issue as perceived by the different types of corporate stakeholders.

The combination of the results of the three previous assessments has allowed to prioritize the relevant issues.

At the end of this review, sustainability issues identified as material are:

• Integrity in business management (transparency, anti-corruption, human rights);
• Safety and asset integrity;
• Equal opportunities for all people;
• Combating climate change (GHG reduction, energy efficiency) and reduction of environmental impact (protection of water resources and biodiversity, oil spill prevention and response);
• Local development / Local content and promoting access to energy;
• Technological Innovation.

Stakeholder engagement

Eni believes that the participation and involvement of stakeholders in the business choices are the key elements which contribute to the development of the territories where Eni

Stakeholder	Engagement procedures and actions
Eni's people	Workshop (i.e. compliance and integrity projects to support the accordance of Eni's activities to company's values and culture); Strategy and annual performance sharing through the HR Ambassador Project and the Engagement Programme; Communication plan through MyEni and MyEni International Portal; Brand activation initiatives; cascade e-mailing for topic business projects; Training programmes and on-the-job training also through distance-learning methods; Welfare initiatives; Information campaign and health screening; Dialogue with the European Works Council (EWC) on Eni's policies within the European framework and with the representatives of the European Observatory for Safety and Health at Work.
Financial community	Conference call on quarterly results and strategy presentation; Road Shows with institutional investors in Europe, North America and Asia; Participation in brokers Conferences; Field-trip in Norway addressed to sell-side analysts; Engagement of main investors skilled on Environmental, Social and Governance (ESG) issues and engagement of investors as well as proxy advisors relating to Shareholders' Meeting.
Local communities	• Issuing of the Operational Procedures for local stakeholders management and collection and handling of warnings, relating to Eni's upstream structures in the world. • Transposition of the Operational Procedures in 9 countries: Egypt, Ecuador, Italy (Northern-Center District, Enimed), Libya, Gabon, Ghana, Indonesia, Myanmar, Nigeria, for a total of 14 countries that have upgraded system for stakeholders management. • Activity of consultation of the local communities within the activities of livelihood restoration in Kazakhstan and Ghana. • Public consultations on business projects in Mozambique, Italy, Myanmar. • Multi-stakeholder committees for planning, management and implementation of social projects (i.e. sectorial committees in Pakistan, technical and management committees for the Hinda project in Congo, local committees in Ecuador and committee for the development of the Green River Project in Nigeria). • Workshop for the sharing of Local Report "Eni in Basilicata" with local stakeholders.
Domestic institutions, European and international institutions, international organizations	Information, awareness-raising and technical in-depth initiatives; Regular meetings with political and local, National, European institutional representatives and with the foreign diplomatic representations in Italy; Inspections and institutional visits at the production sites; Support in authorization procedures at national and local level; national, European and International meetings with representatives of public and private organisms and bodies and main think tanks; Active participation in service conferences, technical tables, political-institutional focus at local, national, European and international level, for energy and climatic issues; Meetings with the institutional delegations of the main countries during the Universal Exposition (Expo Milan 2015).

operates; these factors, in fact, create mutual trust between the actors of the territory, promote consensus and strengthen Eni's reputation as a reliable partner.

Stakeholder	Engagement procedures and actions
The United Nations system	Participation in the main meetings between the United Nations and companies (Private Sector Forum, Annual Forum on Business and Human Rights, Lead Symposium); Participation in Global Compact LEAD Board pilot programme for the Board training programme on sustainability issues; Participation in working groups on anti-corruption under the auspices of the Global Compact, on national and international level; Development of collaboration with World Bank/IFC; Participation in the Italy/UN "Ministerial Meeting of the African LDCs on Structural Transformation, Graduation and the Post-2015 Development Agenda" in Expo Milano 2015.
National and international NGOs	Continuing dialogue with main Italian NGOs (WWF, Greenpeace, Legambiente) on oil&gas environmental issues; Dialogue with Amnesty International on the activities in Nigeria and the protection of Human Rights of populations living near the extraction sites.
Suppliers	Development of suppliers' organizational, technical, quality, HSE and Human Rights skills during the rating process and assessments/audits carried out among the providers; Support on improvement following negative ratings resulting from audits; Verifying observance of Human Rights in the supply chain; Participation in Road Show in order to reinforce the dialogue with local suppliers about prevention issues and the sharing of Vendor Management processes; Participation in the Safety Day on HSE issues in Vendor Management processes; Memorandum of understanding to relaunch certain geographical areas; Focus on supply profiles in the field of Market Intelligence activities.
Customers and consumers	Consolidation of the model for relations with Consumer Associations in order to enforce the attention on core issues: energy saving and sustainable value in our products and services (bio-fuels, smart mobility); Local meetings and workshops with members of Consumer Associations in order to plan remediation actions and synergy addressed the retail customers' expectations, in the increasingly competitive gas and electricity market; Alignment of "Conciliazione paritetica" Model to European legislation; Development and reinforcement of telephone channel dedicated to Consumer Associations for a ready solution of criticalities about gas and electricity offer; Targeted activities addressed to the Consumer Associations to let them gradually use digital and social platforms.
Universities and research centers	Extension of the Framework Agreement with "Politecnico di Milano" signing a Memorandum of understanding between Eni and PoliMi; Definition of a new Agreement with "Politecnico di Torino"; Continuation of the collaboration agreement with the Massachusetts Institute of Technology on upstream, solar and HSE issues and with Stanford University on core oil&gas technologies and on environmental restoration.
Other sustainability organizations	Participation, as founding member, in oil&gas Climate Initiative; Active role within the anti-corruption working group of the G20 ; Participation in the working groups of the WBCSD and IPIECA, the O&G constituency of EITI, the working group within the PACI.

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.

For detailed information on results associated to each capital and to the way by which each strategic target is achieved see this Integrated Annual Report and the Integrated Performance tables.

Business model

	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
capital natura	- 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 and performance drivers

	- Fuel value and increase explorative resources - Growth in upstream cash generation	- Profitability and sustainable cash generation in the Gas & Power segment
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
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
intellectua 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
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
social and 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
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	- Energy efficiency initiatives - Promotion of energy efficiency among customers

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. For further details on financial and non-financial KPI's see the Annex of Integrated performances.

See the next page "connectivity of performances" for a deep focus on connections between upstream actions (first column of matrix), employed capitals and financial/ non financial results reported in 2015.

- Ebit adjusted and free cash flow steadily positive in the R&M segment	- Focus on efficiency
- Investment selectivity - Opex reduction	- Capex reduction - G&A costs reduction - Working capital optimization
- Critical sites reconversion/rationalization	- Process optimization
- Promotion of energy efficiency	- Lean Organization
- R&D investments - Business innovation - Research applied in the green business	- Proprietary technologies development and patents management - Continuous improvement - Change management
- Safety in the workplace	- Safety in the workplace
- Internal know-how enhancement	- Involvement of employees
- Job rotation	- Internal know-how enhancement
- Development of new skills	- Activity insourcing
- Dialogue with trade unions	- Dialogue with trade unions
- Local stakeholders management	- Stakeholders management
- Investments in biorefining	- Promotion of energy efficiency
- Promotion of energy efficiency	- Efficient use of resources

Connectivity of performances

The following cause-effect map graphically shows the connections/effects of specific actions taken in the upstream business, in line with the main strategic guidelines defined by management in response to deteriorated oil scenario. The connections between each action which affects the conduct of business and produces financial results,

generating value for stakeholders, are graphically illustrated below. In particular are highlighted one or more correlations between non-financial and financial results as well as the main risks managed. The efficient use of capital, financial and non-financial, contributes to the value generation and the achievement of the market declared targets.

Strategy

Industrial plan

Starting from the second part 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 discoveries as 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.

Exploration & Production

Fuelling value and increase of explorative resources

• Production growth in the four-year plan 2016-19, at an annual average rate higher than 3%, maintaining a great portion of projects in core areas, also leveraging on negotiations with NOCs and strict control of non-operated activities;
• Efficiency increase through a wide range of actions aimed to reduce G&A, drilling and operating costs, pursued also through the renegotiation of supply contracts following the deteriorated scenario;
• Focusing on working capital through the optimisation of third-party and JV receivables and minimization of stock;
• Selective investments to optimize/reduce expenditures in a low Brent price scenario;
• In exploration, focus on appraisal of recent discoveries, near-field activities in legacy areas and in proximity to on-stream fields as well as, on research of new gas resources in Countries with favourable contractual conditions and more mature sales markets;
• Carbon footprint reduction leveraging on gas issues and development of renewable sources;
• Valorisation of resources through monetization of discoveries with relevant equity;
• Fast track development of discovered resources, through the optimization of the time-to-market and modular approach on project development.

Profitability and sustainable cash generation

• Full alignment of supply portfolio to market conditions and recovery of take-or-pay volumes;
• Recovery of profitability/optimization of B2B contracts;
• Simplification of operations and logistic cost optimization;
• Development of trading activities and support of monetization of recent upstream discoveries;
• Enhancement of customer base.

Gas & Power

Refining & Marketing

Ebit adjusted and free cash flow steadily positive

Progressive reduction of break-even refining margin through:

• Increasing of conversion capacity (EST technology);
• Reconversion of Venice and Gela plants to green refineries in order to produce premium biofuels;
• Productive asset optimization and efficiency;
• Raw materials diversification and higher utilization of extra-heavy crude oil;
• Increasing of marketing profitability through diversification of supply, product and service innovation, efficiency in commercial and distribution processes.

Competitive environment

Eni's actions	Performance of the year	2016-2019 Targets
	Cash flow from operations
- Focus on core business upstream and gas issues - Selection of more suitable resources among new discoveries, to be developed in the trading environment	€12.2 bln self financed investments at 53\$/bl Brent scenario	2016 investments self financed at around $50$ \$/bl Brent scenario
- Enhancement of conventional production in fields	Discovered resources
with low break-even - Enhancement of experiences gained in established areas	$1.4$ bln boe	$1.6$ bln boe
- Minimize time-to-market to support growth	Total capital expenditure
	€10.8 bln (-17% vs 2014)	$\epsilon$ 37 bln, -21% vs previous plan on constant currency rate
	Disposal of assets
	€7 $_{bin}$ (including Saipem transaction)	€7 $_{bin}$
	Hydrocarbon production growth
- Implementation of efficiency programs aimed at reduction of G&A costs	$1.76$ mln bl/d $+10\%$	$>3\%$ year
- Efficiency in the upstream segment by reducing CAPEX and OPEX	OPEX per boe
- Using the financial leverage through the disposal of non-strategic assets	$7.2$ \$/boe, -13% vs 2014	$< 7$ \$/boe
- Increase in self-financing ratio
- Supply diversification to catch the opportunity of cost deflation	G&A cost reduction
- Leveraging on technological excellence to increase efficiency in all Eni's industrial processes	€0.6 bln	€2.5 bln in the four-year plan
	Renegotiation of gas supply portfolio
- Alignment of the gas supply portfolio to market conditions - Optimization of logistic costs	70% of supply contracts indexed to market conditions	Complete portfolio alignment to market conditions
- Development and growth in the value added market segments - Enhancement of LNG, taking advantage of premium markets	Reduction of refining break-even margin
and integration with upstream - Increased system interconnections to manage shortages and	€5/bl	around $\epsilon$ 3/bl from 2018
surplus - Increase of conversion grade and flexibility of refining process,	Green economy
assets' optimization and efficiency - Conversion of less profitable businesses through development of green economy initiatives	Green throughputs at Venice refinery: 0.20 mln ton	Start-up of green production at the Gela Refinery
	Total recordable inijury rate
- Participation in the oil&gas Climate Initiative for the promotion of all measures aimed at reducting $CO2$ emissions	$0.45$ No. of TRI/million of worked hours	Continuous improvement targeting zero level of injuries
Adoption of strict internal policies on climate change risk	Hydrocarbon flared in upstream
management - Use of Carbon Pricing for investment evaluation	4.28 mmcm/d	$-25%$
- Enhancement of new gas discoveries in Mozambique and Egypt	GHG emissions in upstream
Continuous reduction of flaring and venting	$0.2$ tonnes CO 2 eq/toe	$-43\%$ to 2025

Risk Management

Eni has developed and adopted a model for Integrated Risk Management (IRM) that targets to achieve an organic and comprehensive view of the Company's main risks1 , greater consistency among internally-developed methodologies and tools to manage risks and a strengthening of the organization awareness, at any level, that suitable risk evaluation and mitigation may influence the delivery of Corporate targets and value.

Integrated Risk Management Model

The IRM Model has been defined and updated consistently with international principles and best practices. It is an integral part of the Internal Control and Risk Management System (see page 31) and is structured on three control levels.

Risk Management

Risk governance attributes a central role to the Board of Directors which, with the support of the Control and Risk Committee outlines the guidelines for risk management, so as to ensure that the main corporate risks are properly identified and adequately assessed, managed and monitored.

In addition, the Eni Board of Directors, in fulfilling its responsibilities and its role of direction and with the support of the Control and Risk Committee, defines the degree of compatibility of these risks with the company management consistent with its strategic targets. For this purpose, Eni's CEO, through the process of integrated risk management, presents every three months a review of the Eni's main risks to the Board of Directors. The analysis is based on the scope of the work and risks specific of each business area and processes aiming at defining an integrated risk management policy; the CEO also ensures the evolution of the IRM process consistently with business dynamics and the regulatory environment. Furthermore, the Risk Committee, chaired by the CEO, holds the role of consulting body for the latter with regards to major risks. For this purpose, the Risk Committee evaluates and expresses opinions, at the instance of CEO, related to the main results of the integrated risk management process.

Integrated Risk Management Process

The IRM Model is implemented through a process of integrated management which is both continuous and dynamic and leverages on the risk management systems already adopted by each business unit and corporate processes, promoting harmonization with methodologies and specific tools of the IRM model.

The commencement of the risk assessment process includes the definition of its scope, basing on the guidelines defined by the Board of Directors, i.e. the identification of the processes and the organizational functions/units/management of the Parent company and its subsidiaries to be involved in the IRM process, which might significantly impact the achievement of corporate objectives.

In 2015, two-assessment session were performed: the yearly risk assessment performed in the first half of the year involving 60 subsidiaries and the interim top risk assessment performed in the second half of the year, relating to the update and in-depth identification, evaluation and treatment of top risks. The second assessment also revaluated certain main risks to the business level. The two-assessment results were submitted to the management and control bodies in July and December 2015.

In addition, three monitoring processes were performed on the Eni's top risks. The monitoring of such risks and the relevant treatment plans through update of appropriate indicators (Key Risk Indicator, Key Control Indicator, Key Performance Indicator) allow to analyze the risks evolution, the progress in implementation of specific treatment measures decided by the management and identify possible improvement areas in the risks management. The monitoring results were submitted to the management and control bodies in April, July and October 2015. It was also provided a contribution to the 2016-2019 strategic plan process through the identification of specific de-risking objectives of the main corporate and business risks, issued as part of the 2016-19 Guidelines by CEO. Based on the corporate objectives, specific treatments have been identified, as an integrated part of the strategic plan.

The following table represents Eni's main risks in relation to corporate targets. For further details on these risks, as well as minors uncertainty factors, see the section "Risk factors and uncertainties".

Risk Management

Company targets	Risk category	Main risk events	Rif. Risk factors and uncertainties section	Treatment measures
Company profitability	Commodity risk	A continuing weakness in the macro-economic scenario and excessing oil supply.	Page 89	Revision of capital expenditure plans; dismissal procedures; reduction of project break-even price; portfolio optimization with new developments from exploration discoveries and lower exposition; widespread efficency initiatives.
Company profitability	Operational risks, accidents	Blow-out risks and other relevant accidents at extractive infrastructures, refineries and petrochemical plants, in the transportation of hydrocarbons by sea and land (i.e. fires/explosions, etc.) may affect results, cash flow, reputation and strategies.	Pages 77-78	Geologic "Real time monitoring" of wells drilling phases and pre-drill and real time evaluation of geohazards and geopressions risks, specific technological development and emergency management plans; specific HSE audit and plants monitoring; management and continuous monitoring of shipping operation and third operators, vetting activities.
Company profitability	Country risk	Political and social instability in the countries of operations may lead to acts of internal conflicts. civil unrests, violence, sabotage and attacks, with consequent production interruptions and losses as well as interruptions in gas supplies via pipe.	Pages 82-83	Implementation of the security management system with the analysis of the preventive measures specific for site, keeping efficient and long-lasting relationships with producing countries and local stakeholders even throughout local social development and sustainability projects; leverage on the activities portfolio to reduce the presence in high risks countries.
Corporate Reputation	Compliance risk	Negative impact on the company reputation and business outlook caused by the lack of compliance (real or perceived) with the law and rules in particular on anti-corruption themes, on behalf of management, employers and contractors, with negative effects on profitability strategies, and shareholder returns.	Pages 85-86	Continuing training for compliance/anti-corruption and higher management awareness on the culture of company ethic and integrity; the control on the adequacy of the design and correct application of the model 231 (Watch structure), continues update of the internal procedures (Code of Ethics, MSG, etc.), process of analysis and notices treatment, audit activity, continuing control on the management of legal proceedings performed by dedicated organizational structures.
Company profitability and Corporate Reputation	Operatioral risk	Environmental and health legal proceedings as well as evolution in the HSE legislation may trigger contingent liabilities, higher operating costs and extra costs relating to remediation activities.	Pages 85-86	Integrated system of HSE management. Transversal organizational unit dedicated to legal assistance to HSE matters; constituted and interfunctional committee for the management of work-related diseases, ad hoc defensive strategies for any single litigation, actions aimed at improve the work-related diseases; monitoring of authorization processes of the remediation projects throughout a continuous dialogue with the competent Authorities for the remediation activities.
Company profitability and Corporate Reputation	External risk, evolution in the legislation	The impact of climate change and associated economic and financial implications such as restrictions or hindrances to operations in specific geographic areas, increase of operating costs, higher capex and costs of insurance, higher cost of compliance, reduction of demand for gas and refined products.	Page 87	Units and methodologies dedicated to emerging risks evaluation, management and reduction of gas flaring; participation in the international context dedicated to the implementation of best practice of the oil&gas sector and participation in international initiatives.

Company targets	Risk category	Main risk events	Rif. Risk factors and uncertainties section	Treatment measures
Relationship with stakeholders, Local development and Corporate Reputation	Strategic risk	Negative perception by a number of local and international stakeholders of the oil&gas industry activities, affecting also media.	Pages 77-78	Dialogue and transparency towards stakeholders, both on national and international level in implementing business activity and local development projects even throughout working groups. Development of sustainability initiatives and the model of stakeholder management, communication of Eni strategies and activities.
Company profitability	Strategic risk	Failure in renegotiation of long-term gas supply and sale contracts and failure in recovery of logistic costs due to oversupply and pressure on selling prices.	Page 84	Evaluation of the option to recur to international arbitration proceedings in case of unsuccessful renegotiations; use of the diversified portfolio of supply sources aimed at optimize the negotiation strategies; gas sales contracts revision throughout commercial agreements and option to recur to arbitration.
Company profitability	Strategic risk	Complex finalization of oil and commercial negotiations as well as negotiations related to assets trade, due to institutional and regulatory changes in the countries of operations and in the market scenarios.	Pages 78-82	Existence of a central organizational structure aimed at manage extraordinary portfolio operations, evaluate alternative deal structures, further dismissal targets, Eni portfolio analysis, in consideration of Eni sectors.
Company profitability	Counterparty risk	Default risk of NOC's countries and solvency of state-owned companies and JV partners. Commercial credit risk.	Page 82	Internal structures and rules dedicated to credit risks, specific initiatives/projects for the process optimization and recourse to the factoring operations. Commercial and oil contracts including securitization formulas, default clauses, carry agreement, in kind payments; institutional relations and negotiations.
Company profitability	Evolution in the legislation	Regulatory risk of the oil&gas sector.	Pages 85-86	Continuous monitoring of the evolution of the legislation and commitment with relevant authorities, evaluation of the option to recur to legal proceedings against new legislation/regulation introduced by relevant authorities. Evaluation and implementation of initiatives to obtain adjustment and optimization of the costs of the gas logistics.
Company profitability	Operational risk	Cyber security and industrial espionage.	Page 88	Internal structures and rules dedicated to IT security management and information protection, operating plans aimed at increasing security of industrial sites, training and awareness initiatives dedicated to personnel.

Integrity and transparency are the principles that have inspired Eni in designing its corporate governance system1 , a key pillar of the Company's business model. The governance system, flanking our business strategy, is intended to support the relationship of trust between Eni and its stakeholders and to help achieve our business goals, creating sustainable value for the long-term. Eni is committed to building a corporate governance system founded on excellence in our open dialogue with the market and all our stakeholders.

Ongoing, transparent communication with stakeholders is an essential tool for better understanding their needs. It is part of our efforts to ensure the effective exercise of shareholder rights.

With this in mind, in continuity with previous initiatives in 2013-2014, Eni has responded to the need for a deeper dialogue with the market and, with the participation of the Chairman of the Board of Directors, held a new cycle of meetings with institutional investors to foster a comprehensive understanding of the Company's governance system and main initiatives in the fields of sustainability and corporate social responsibility. The initiative was welcomed by the investors, who confirmed that Eni's corporate governance is very well structured and among the most effective. In particular, the investors expressed their appreciation of the composition of the Board of Directors, including its diversity, the governance measures adopted (e.g. the establishment of the Sustainability and Scenarios Committee and the induction process and on-going training) and the completeness and transparency of the information provided to shareholders and the market as a whole. In addition, during the meetings the investors displayed considerable interest in the risk governance approach adopted by Eni and the extent of the associated monitoring performed by the Board. In its corporate and governance decisions, such as the adoption of the recommendations of the Corporate Governance Code of Italian listed companies, the Eni Board of Directors ensures the transparency of its actions to the market, which must be explained and documented in a timely manner to enable easy comprehension and evaluation.

The Eni Corporate Governance structure

Eni's Corporate Governance structure is based on the traditional Italian model, which – without prejudice to the role of the Shareholders' Meeting – assigns the management of the Company to the Board of Directors, supervisory functions to the Board of Statutory Auditors and statutory auditing to the Audit Firm.

Eni's Board of Directors and Board of Statutory Auditors, and their respective Chairmen, are elected by the Shareholders' Meeting using a slate voting mechanism. Three directors and two statutory auditors, including the Chairman of the Board of Statutory Auditors, are elected by non-controlling shareholders, thereby giving minority shareholders a larger number of representatives than that provided for under law. The number of independent directors provided for in the Eni By-laws is also greater than the number required by law. In May 2014, the end of the terms of the corporate boards led to a major renewal of the Board of Directors and the Board of Statutory Auditors. In deciding the composition of the Board of Directors, the Shareholders' Meeting was able to take account of the guidance provided to investors by the previous Board with regard to diversity, professionalism, management experience and international representation. The outcome was a balanced and diversified Board of Directors, one that also exceeds statutory mandates on gender diversity. Following the election, the number of independent directors on the Board of Directors (72 of the 9 serving directors, of whom 8 are non-executive directors) was still greater than the number provided for in the By-laws and in the Corporate Governance Code, and exceeded the average for Italian listed companies3 . The Board of Directors appointed a Chief Executive Officer and established four internal committees

(1) For more detailed information on the Eni Corporate Governance system, please see the Report on corporate governance and ownership structure, which is published on the Company's website in the Governance section.

(2) Independence as defined by applicable law, to which the Eni By-laws refer. Under the Corporate Governance Code, 6 of the 9 serving directors are independent.

(3) Under law and the Corporate Governance Code, the number of independent directors was unchanged even after the appointment by the Board of a director on July 29, 2015, in replacement of a resigning director appointed by the Shareholders' Meeting (see the chart at the end of the section).

with advisory and recommendation functions: the Control and Risk Committee4 , the Compensation Committee5 , the Nomination Committee and the Sustainability and Scenarios Committee. The committees report, through their Chairmen, on the main issues they address at each meeting of the Board of Directors. More specifically, the Board of Directors created the Sustainability and Scenarios Committee to strengthen the attention devoted to sustainability issues.

The Board of Directors has also given the Chairman a major role in internal controls, with specific regard to the Internal Audit unit. The Chairman proposes the appointment and remuneration of its head and the resources available to it, and also directly manages relations with the unit on behalf of the Board of Directors (without prejudice to the unit's functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director responsible for the internal control and risk management system). The Chairman is also involved in the appointment of the primary Eni officers responsible for internal controls and risk management, including the Head of Integrated Risk Management, as described in the next section.

Finally, the Board of Directors, acting on a recommendation of the Chairman, appointed a Secretary, who was also designated the Corporate Governance Counsel, charged with providing assistance and advice to the Board of Directors and the directors, reporting annually to the Board of Directors on the functioning of Eni's corporate governance system. In view of this role, the Secretary must also meet appropriate independence requirements and reports to the Board of Directors itself and, on its behalf, to the Chairman.

The following chart summarises the Company's corporate governance structure at December 31, 2015:

(5) The rules of the Compensation Committee require that at least one member shall have adequate expertise and experience in finance or compensation policies. These qualifications are assessed by the Board of Directors at the time of appointment.

Decision making

The Board of Directors entrusts the management of the Company to the Chief Executive Officer, while retaining key strategic, operational and organizational powers for itself, especially as regards governance, sustainability6 , internal control and risk management. Among the Board of Directors' most important duties is the appointment of people to key management and control positions in the Company, such as the officer in charge of preparing financial reports, the head of Internal Audit, the members of the Watch Structure and the Guarantor of the Eni Code of Ethics. In performing these duties, the Board of Directors may draw on the support of the Nomination Committee.

In order for the Board of Directors to perform its duties as effectively as possible, the directors must be in a position to assess the decisions they are called upon to make, possessing appropriate expertise and information. The current members of the Board of Directors, who have a diversified range of skills and experience, including on the international stage, are well qualified to conduct comprehensive assessments of the variety of issues they face from multiple perspectives. The directors also receive timely, complete briefings on the issues on the agenda of the meetings of the Board of Directors. To ensure this operates smoothly, Board meetings are governed by specific procedures that establish deadlines for providing members with documentation, and the Chairman ensures that each director can contribute effectively to Board discussions.

On an annual basis, the Board of Directors, with the support of an external advisor and the oversight of the Nomination Committee, conducts a self-assessment (the Board Review), for which benchmarking against national and international best practices and an examination of Board dynamics are essential elements. Following the Board Review, the Board of Directors develops an action plan, if necessary, to improve the operation of the Board and its committees. In addition, in 2015 the Eni Board conducted a peer review of the directors, in which each director expressed his or her view of the contribution made by the other directors to the work of the Board. The peer review, the third performed in recent years, is an important innovation among Italian listed companies. For a number of years now, Eni has supported the Board of Directors and the Board of Statutory Auditors with an induction programme, which involves the presentation of the activities and organization of Eni by top management. More specifically, during the year, in continuity with previous initiatives, additional training sessions were held on corporate topics (such as corporate governance, compliance, internal control and risk management) and business issues (in particular, exploration and drilling), with visits to operating sites in Italy and abroad. The Board also completed the "UN Global Compact LEAD Board Programme7 ", which is dedicated to training directors in sustainability issues.

With the support of an international facilitator who is an expert in sustainability, integrated reporting and management, in September 2015 the Board of Directors conducted a second session of the programme dedicated to "The role of the Board", which examines issues concerning the role of the Board in integrating sustainability into corporate strategy and management, with a special focus on climate change. The first session of the programme in October 2014 was devoted to "The Materiality of Sustainability", in order to enhance awareness of the importance of sustainability for an enterprises' strategy and business. The programme was held under the supervision of the Sustainability and Scenarios Committee.

Remuneration Policy

Eni's Remuneration Policy for its Directors and top management is established in accordance with the Governance model adopted by the Company and the recommendations of the Corporate Governance Code. The Policy seeks to retain with high-level professionals

(6) More specifically, the Board of Directors has reserved for itself decisions concerning the establishment of sustainability policies, the results of which are reported together with financial results in an integrated manner in the Annual Report, as well as the examination and approval of reports covering areas not included in the integrated reporting framework.

(7) Eni is a member of the UN Global Compact Lead Group.

and skilled managers and to align the interests of management with the priority objective of creating value for shareholders over the medium/long-term. For this purpose, the remuneration of Eni's top management is established on the basis of the position and the responsibilities assigned, with due consideration given to market benchmarks for similar positions in companies similar to Eni in dimension and complexity. Remuneration is composed of a balanced mix of fixed and variable elements.

Under Eni Remuneration Policy, considerable importance is given to the variable component, which is linked to the achievement of preset performance and financial targets, business development and operational objectives, also considering the long-term sustainability of the results, in line with the Company's Strategic Plan.

The variable remuneration of Eni's executive officers having a greater influence on the business performance is characterized by a significant percentage of long-term incentive components, to be paid at the end of a three-year vesting period to reflect the long-term nature of the business and the related risk profiles.

With regard to sustainability issues, the CEO objectives set for the year 2016, are focused on environmental matters as well as on human capital aspects.

The objectives of the Chief Officers of Eni business segments and other Managers with strategic responsibilities are assigned on the base of those assigned to top management focused for each business area on financial, operating and industrial performance, internal efficiency and sustainability aspects (in terms of health and safety, environmental protection, relations with stakeholders) as well as on individual objectives assigned in relation to the responsibilities inherent the single managerial position, under the provisions of Company's Strategic Plan.

The Remuneration Policy is described in the first section of the "Remuneration Report", available on the Company's website (www.eni.com) and is presented, on an annual basis, for an advisory vote at the Shareholders Meeting8 .

The internal control and risk management system

Eni has adopted an integrated and comprehensive internal control and risk management system based on reporting tools and flows that, involving all Eni personnel, reach all the way up to the top management of the Company and its subsidiaries. The members of the Board, as well as the members of the other corporate bodies and all Eni personnel, are required to comply with Eni's Code of Ethics (as an essential part of the Company's Model 231), which sets out the rules of conduct for the fair and proper management of the Company's business. Eni adopted a regulatory instrument for the integrated governance of the internal control and risk management system, the guidelines of which, approved by the Board, set out the duties, responsibilities and procedures for coordinating between the primary system actors. An integral part of the Eni internal control system is the internal control system for financial reporting, the objective of which is to provide reasonable certainty of the reliability of financial reporting and the ability of the financial report preparation process to generate such reporting in compliance with generally accepted international accounting standards. Eni's CEO and Chief Financial and Risk Management Officer (CFRO) are responsible for planning, establishing and maintaining the internal control system for financial reporting. The CFRO also serves as the officer in charge of preparing financial reports (Financial Reporting Officer – FRO).

Pay Mix - Managers with strategic responsibilities

(*) amount of the remuneration package versus the fixed remuneration

(8) In particular, in 2015, 93.4% of voting shareholders, expressed a favorable vote on Eni's remuneration policies, this confirming the large consent registered in 2014.

Exploration & Production

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.

Exploration & Production Operating review

›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).

Upstream growth model will continue to focus on conventional assets, which will be organically developed, with a large resource base and a competitive cost structure, which make them profitable even in a low price environment. The sizeable exploration successes of the last years have increased the Company's resource base, contributing to the Company's

value generation through the early monetization of the discovered resources in excess of the target replacement ratio. Eni's top priorities are the increase and valorisation of discovered resources and a growing cash generation. Strategy

The drivers to target the increase and valorisation of discovered resources are: (i) re-balancing of exploration activities with a focus on appraisal programmes on the recent discoveries (Egypt, Congo, Indonesia and Angola), near-field initiatives and incremental activities in legacy areas and nearby to fields already under development, with the objective of delivering 1.6 billion boe of discovered resources at a competitive cost of \$2.3 per boe; (ii) renewal of the portfolio of exploration leases by focusing on high materiality play; and (iii) fast-track development of discovered resources by optimizing the time-to-market and exercising tight control on project execution.

Cash generation will be driven by: (i) production growth at an annual average rate higher than 3% leveraging on a robust pipeline of projects in core areas, including also contractual revisions with oil-producing countries and strictly monitoring of non-operated activities. This new production together with the ramp-ups at fields started up in 2015 will add more than 800 kboe/d in 2019. Main start-ups are the Goliat field (Eni operator with a 65% interest) in the Barents Sea in Norway, the Jangkrik project (Eni operator with a 55% interest) in Indonesia, the oil and gas development of the Offshore Cape Three Points project (Eni operator with a 47.22% interest) in Ghana, the re-start of the Kashagan field (Eni's interest 16.81%) by the end of 2016 as well as accelerated start-up of the giant Zohr discovery (Eni's interest 100%) in the offshore Egypt and phased start-up of the discoveries in the Block 15/06 (Eni's operator with a 35% interest) in Angola; (ii) project modularization and phasing which will enable the Company to reduce financial exposure and to accelerate production start-ups; (iii) strengthened efficiency by means of several initiatives to reduce operating costs, to be achieved also by renegotiating the supply of field services and goods; (iv) focusing on working capital driven by an optimised exposure to third parties and joint venture partners and decreasing products inventories; and (v) early monetization of part of discovered volumes.

Eni acknowledges that the upstream performance could be adversely impacted in the short-to-medium term by a number of risks: (i) the commodity risk related to current trends in crude oil prices. Eni is planning to mitigate this risk by implementing initiatives of rationalization and optimization, the renegotiation of contractual terms with contractors to align costs of field services and goods to the changed market conditions. In 2016-19 plan period, Eni estimates a decrease of approximately 18% of capital expenditure net of exchange rate effects versus the previous four-year plan due to a reduction in exploration expenditure which will be focused on near-field and appraisal activities, the re-phasing of projects yet to be sanctioned and service contract renegotiations. In addition, Eni intends to reduce operating costs by 12% net of exchange rate effects versus the old plan; (ii) the political risk due to social and political instability in certain countries of operations. A major part of Eni's activities are currently located in countries that are far from high-risk areas and Eni plans to grow mainly in countries with low-mid political risk (approximately 90% of the capital expenditure of the four-year plan); (iii) risk related to the growing complexity of certain projects due to technological and logistic issues. Eni plans to counteract those risks by strict selection of adequate contractors, tight control of the time-to market and the retaining of the operatorship in a large number of projects (75% of production related to projects portfolio in 2019 with an average growth rate of 4.3% in the plan period); and (iv) the technical risk related to the execution of drilling activities at high pressure/high temperature wells and deep waters wells (down 24% in the plan period). Eni plans to increase operatorship of critical projects ensuring better direct control and deploying its high operational standards. The business sustainability in the short-to-long term remains a key factor to achieve the strategic goals also through the increasing stakeholders engagement and continuous relations with local authorities and including: (i) a decrease of 30% of process flaring in 2019 versus 2014, in line with target of zero routine flaring in 2025; (ii) the carbon footprint reduction focusing on gas initiatives, energy savings and the development of renewable energy projects.

Reserves

Overview

The Company adopts comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable US Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geo-science and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt's Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.

Engineering estimates of the Company's oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni's share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and on the Profit Oil set contractually (Profit Oil). A similar scheme applies to service contracts.

Reserves Governance

Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company's guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the SEC rules1 . D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by others entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; (v) the Reserves Department, through the Headquarter Reserves Evaluators (HRE), provides independent reviews of fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserves data. The head of the Reserves Department attended the "Università degli Studi di Milano" and received a Master of Science degree in Physics in 1988. He has more than 25 years of experience in the oil and gas industry and more than 15 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies2 to carry out an independent evaluation of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third party audit report3 . In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/ gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni's equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third party evaluators. In 2015 an independent evaluation of Ryder Scott Company, DeGolyer and MacNaughton and Gaffney, Cline & Associates3 confirmed, as in previous years, the fairness of Eni internal evaluation. In particular, in 20154 approximately 31% of Eni's total proved reserves were subject to independent evaluation at December 31, 2015 . In the 2013-2015 three-year period, 86% of Eni total proved reserves were subject to independent evaluation. As of December 31, 2015, the principal Eni properties which did not undergo an independent evaluation in the last three years were Kashagan (Kazakhstan) and CAFC-MLE (Algeria).

(3) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2015.

⁽¹⁾ The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2009.

⁽²⁾ From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott and in 2015, also Gaffney, Cline & Associates.

⁽⁴⁾ Includes Eni's share of proved reserves of equity accounted entities.

Exploration & Production Operating review

Movements in estimated net proved reserves

Eni's estimated proved reserves were determined taking into account Eni's share of proved reserves of equity-accounted entities. Movements in Eni's 2015 estimated proved reserves were as follows:

(mmboe)	Consolidated subsidiaries	Equity-accounted entities	Total
Estimated net proved reserves at December 31, 2014	5,772	830	6,602
Extensions, discoveries, revisions of previous estimates and improved recovery excluding price effect Price effect	571 278	98	669 278
Reserve additions, total	849	98	947
Sales of minerals-in-place	(17)		(17)
Production of the year	(629)	(13)	(642)
Estimated net proved reserves at December 31, 2015	5,975	915	6,890
Reserves replacement ratio, organic (%)			148

Additions to proved reserves booked in 2015 were 947 mmboe and derived from: (i) revisions of previous estimates were up by 879 mmboe mainly reported in Kazakhstan, Iraq, Egypt, Congo and Venezuela; (ii) extensions and discoveries were up by 66 mmboe, with major increases booked in Egypt and Indonesia; (iii) improved recovery were 2 mmboe mainly reported in Egypt. These increases compared to production of the year yielded an organic reserves replacement ratio5 of 148%.

All sources additions were impacted by favourable price effect, leading to an upward revision of 278 mmboe, due to a lowered Brent price used in the reserves estimation process down to \$54 per barrel in 2015 compared to \$101 per barrel in 2014.

Sales of mineral-in-place mainly related to the divestment of assets in Nigeria (down by 16 mmboe) and the United States (down by 1 mmboe).

In 2015 Eni achieved an all sources reserves replacement ratio of 145%. Reserves life index was 10.7 years (11.3 years in 2014).

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2015 totalled 2,867 mmboe, of which 1,411 mmboe of liquids mainly concentrated in Africa and Kazakhstan and 7,994 bcf of natural gas mainly located in Africa and Americas. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,272 mmbbl of liquids and 5,403 bcf of natural gas.

In 2015, total proved undeveloped reserves decreased by 302 mmboe mainly due to: (i) reclassification to proved developed reserves (down by 550 mmboe); (ii) divestments (down by 5 mmboe) in Nigeria; (iii) revisions of previous estimates (up by 204 mmboe) mainly reported in Venezuela, Iraq and Egypt; (iv) extensions and discoveries (up by 48 mmboe), in particular in Indonesia, Egypt and Ghana; and (v) improved recovery (up by 1 mmboe) in particular in Egypt. During 2015, Eni converted 550 mmboe of proved undeveloped reserves to proved developed reserves due to the progress of the development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Perla (Venezuela), Goliat and Midgard (Norway), Litchendjili (Congo) and M'Pungi (Angola). In 2015, capital expenditure amounted to approximately €9 billion.

Most proved undeveloped reserves are converted to proved developed reserves within five years. Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 0.8 bboe of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (approximately 0.5 bboe), which will be progressively reclassified to proved developed reserves as a result of hooking-up new producing wells which are currently being completed and plant capacity expansion as a part of the sanctioned Phase 1 of the global development plan of the Kashagan field; (ii) certain Libyan gas fields (0.2 bboe) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force; and (iii) other minor projects where development activities are progressing.

Delivery commitments

Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities.

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 479 mmboe from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria, Norway and Venezuela.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company's proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 86% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2015.

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

Estimated net proved hydrocarbons reserves

	(mmbbl) Liquids	Natural gas (bcf)	Hydrocarbons (mmboe)	(mmbbl) Liquids	Natural gas (bcf)	Hydrocarbons (mmboe)	(mmbbl) Liquids	Natural gas (bcf)	Hydrocarbons (mmboe)
Consolidated subsidiaries		2013			2014			2015
Italy	220	1,532	499	243	1,432	503	228	1,304	465
Developed	177	1,266	408	184	1,192	401	171	1,051	362
Undeveloped	43	266	91	59	240	102	57	253	103
Rest of Europe	330	1,247	557	331	1,171	544	305	1,044	495
Developed	179	904	343	174	887	335	237	919	404
Undeveloped	151	343	214	157	284	209	68	125	91
North Africa	830	5,231	1,783	776	5,291	1,740	821	4,798	1,694
Developed	561	2,432	1,003	521	2,110	904	542	2,566	1,010
Undeveloped	269	2,799	780	255	3,181	836	279	2,232	684
Sub-Saharan Africa	723	2,374	1,155	739	2,744	1,239	787	2,714	1,282
Developed	465	1,295	701	470	1,271	702	511	1,390	764
Undeveloped	258	1,079	454	269	1,473	537	276	1,324	518
Kazakhstan	679	1,957	1,035	697	2,049	1,069	771	2,354	1,198
Developed	295	1,488	566	306	1,553	589	355	1,830	689
Undeveloped	384	469	469	391	496	480	416	524	509
Rest of Asia	128	744	263	131	846	285	262	878	422
Developed	38	286	90	64	261	112	126	185	159
Undeveloped	90	458	173	67	585	173	136	693	263
Americas	147	509	240	147	468	232	189	439	269
Developed	96	310	153	116	393	188	149	373	217
Undeveloped	51	199	87	31	75	44	40	66	52
Australia and Oceania	22	848	176	13	807	160	9	771	150
Developed Undeveloped	20 2	561 287	123 53	12 1	675 132	135 25	9	585 186	115 35
Total consolidated subsidiaries	3,079	14,442	5,708	3,077	14,808	5,772	3,372	14,302	5,975
Developed	1,831	8,542	3,387	1,847	8,342	3,366	2,100	8,899	3,720
Undeveloped	1,248	5,900	2,321	1,230	6,466	2,406	1,272	5,403	2,255
Equity-accounted entities
North Africa	16	15	19	14	15	16	13	13	14
Developed	16	15	19	13	15	15	13	13	14
Undeveloped				1		1
Sub-Saharan Africa	15	330	75	17	351	81	16	387	87
Developed				7	89	23	6	85	22
Undeveloped	15	330	75	10	262	58	10	302	65
Rest of Asia	1	28	7	1	18	5		12	4
Developed		14	3		10	3		9	2
Undeveloped	1	14	4	1	8	2		3	2
Americas	116	3,353	726	117	3,353	728	158	3,581	810
Developed	19	5	18	26	6	26	29	1,295	265
Undeveloped	97	3,348	708	91	3,347	702	129	2,286	545
Total equity-accounted entities	148	3,726	827	149	3,737	830	187	3,993	915
Developed	35	34	40	46	120	67	48	1,402	303
Undeveloped	113	3,692	787	103	3,617	763	139	2,591	612
Total including equity-accounted entities	3,227	18,168	6,535	3,226	18,545	6,602	3,559	18,295	6,890
Developed	1,866	8,576	3,427	1,893	8,462	3,433	2,148	10,301	4,023
Undeveloped	1,361	9,592	3,108	1,333	10,083	3,169	1,411	7,994	2,867

Oil and natural gas production

In 2015, Eni's hydrocarbon production was 1.760 million boe/d, up by 10.1% from 2014. Excluding the price effects reported in Production Sharing Agreements, production increased by 6.3%. The increase was driven by new field start-ups and the continuing ramp-up of production at fields started in 2014, 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. These positive effects were partly offset by the decline of mature fields. New field start-ups and ramp-ups of production added an estimated 139 kboe/d of new production. The share of oil and natural gas produced outside Italy was 90% (compared to 89% in the corresponding period a year ago). Liquids production (908 kbbl/d) increased by 80 kbbl/d or 9.7%, due to higher production in Libya, Iran and Iraq as well as new fields start-ups and ramp-ups in particular in Angola, the United States and Norway.

Natural gas production (4,681 mmcf/d) increased by 457 mmcf/d or 10.8% from 2014. The start-ups in Venezuela,

the United Kingdom, Egypt and the United States, as well as higher production in Libya more than offset the decline of mature fields.

Oil and gas production sold amounted to 614.1 mmboe. The 28.3 mmboe difference over production (642.4 mmboe) mainly reflected volumes of natural gas consumed in operations (26.4 mmboe), changes in inventory levels and other variations. Approximately 61% of liquids production sold (330.1 mmbbl) was destined to Eni's mid-downstream sectors. About 25% of natural gas production sold (1,560 bcf) was destined to Eni's Gas & Power segment.

In 2015 oil spills from operations reported an increase compared to the previous year, amounting to 22%; oil spills from sabotage increased by 57%. Oil spills were concentrated in Nigeria, due to disruptions and force majeure events reported during the year. Eni continues to promote operations aimed to guarantee safety standards and at ensuring efficient operations management.

	(mmbbl) Liquids	Natural gas	Hydrocarbons (mmboe)	(mmbbl) Liquids	Natural gas	Hydrocarbons (mmboe)	(mmbbl) Liquids	Natural gas	Hydrocarbons (mmboe)
		(bcf)			(bcf)			(bcf)
Consolidated subsidiaries		2013			2014			2015
Italy	26	230	68	27	213	65	25	200	62
Rest of Europe	28	157	57	34	195	69	31	201	68
North Africa	91	609	201	91	627	206	98	780	240
Sub-Saharan Africa	88	176	120	84	185	118	93	171	124
Kazakhstan	22	78	36	19	73	32	20	80	35
Rest of Asia	16	130	40	13	114	34	28	106	47
Americas	22	89	38	27	80	41	28	94	45
Australia and Oceania	4	40	11	2	40	10	2	41	9
	297	1,509	571	297	1,527	575	325	1,673	630
Equity-accounted entities
North Africa	1	2	2	1	2	1	1	2	1
Sub-Saharan Africa		5	1		4	1
Rest of Asia	2	61	13		8	2	1	9	2
Americas	4		4	4		4	4	25	9
	7	68	20	5	14	8	6	36	12
Total	304	1,577	591	302	1,541	583	331	1,709	642

Oil and natural gas production(a)

(a) Includes volumes of gas consumed in operations (26.4, 29.4 and 30 mmboe in 2015, 2014 and 2013, respectively).

Oil and natural gas production(a)

			Hydrocarbons			Hydrocarbons			Hydrocarbons
	(kbbl/d) Liquids	Natural gas (mmcf/d)	(kboe/d)	(kbbl/d) Liquids	Natural gas (mmcf/d)	(kboe/d)	(kbbl/d) Liquids	Natural gas (mmcf/d)	(kboe/d)
Consolidated subsidiaries		2013			2014			2015
Italy	71	630.2	186	73	583.8	179	69	546.6	169
Rest of Europe	77	429.6	155	93	535.2	190	85	551.8	185
Croatia		43.0	8		38.2	7		21.2	4
Norway	60	250.5	106	62	274.2	112	57	264.6	105
United Kingdom	17	136.1	41	31	222.8	71	28	266.0	76
North Africa	248	1,668.7	551	248	1,718.9	562	268	2,138.0	658
Algeria	73	81.6	88	83	141.3	109	79	94.1	96
Egypt	93	734.6	227	88	649.8	206	96	510.1	189
Libya	76	836.7	228	73	911.2	239	89	1,517.3	365
Tunisia	6	15.8	8	4	16.6	8	4	16.5	8
Sub-Saharan Africa	242	481.7	329	231	507.5	323	256	468.3	341
Angola	79	32.7	84	75	38.3	82	96	31.6	101
Congo	90	161.8	120	80	145.1	106	78	136.8	103
Nigeria	73	287.2	125	76	324.1	135	82	299.9	137
Kazakhstan	61	213.5	100	52	200.7	88	56	218.3	95
Rest of Asia	43	354.7	108	36	310.4	93	77	289.8	130
China	7	3.4	8	4		4	3		3
India		7.2	1		3.7	1		2.6	1
Indonesia	1	55.0	11	1	52.6	11	2	54.8	12
Iran	4		4	1		1	22		22
Iraq	22		22	21		21	40		40
Pakistan		283.1	52		248.2	45		226.4	41
Turkmenistan	9	6.0	10	9	5.9	10	10	6.0	11
Americas	61	244.5	106	74	217.8	115	75	257.1	122
Ecuador	13		13	12		12	11		11
Trinidad & Tobago		58.6	11		60.3	11		70.4	13
United States	48	185.9	82	62	157.5	92	64	186.7	98
Australia and Oceania	10	110.4	30	6	110.5	26	5	111.8	26
Australia	10	110.4	30	6	110.5	26	5	111.8	26
	813	4,133.3	1,565	813	4,184.8	1,576	891	4,581.7	1,726
Equity-accounted entities
Angola		14.2	3		10.3	2		0.9
Indonesia	1	24.2	5	1	23.2	5	1	24.1	5
Russia	5	141.6	31
Tunisia	4	5.5	5	4	5.3	5	4	5.2	4
Venezuela	10	0.8	10	10	0.8	10	12	68.9	25
	20	186.3	54	15	39.6	22	17	99.1	34
Total	833	4,319.6	1,619	828	4,224.4	1,598	908	4,680.8	1,760

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

Productive wells

In 2015, oil and gas productive wells were 9,241 (3,667.5 of which represented Eni's share). In particular, oil productive wells were 6,558 (2,439.1 of which represented Eni's share); natural gas productive wells amounted to 2,683 (1,228.4 of which represented Eni's share).

The following table shows the number of productive wells in the year indicated by the Group and its equity-accounted entities in accordance with the requirements of FASB Extractive Activitiesoil&gas (Topic 932).

Productive oil and gas wells(a)

		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) Includes 2,135 gross (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.

Drilling

Exploration

In 2015, a total of 29 new exploratory wells were drilled (19.1 of which represented Eni's share), as compared to 44 exploratory wells drilled in 2014 (25.8 of which represent Eni's share) and 53 exploratory wells drilled in 2013 (27.8 of which represented Eni's share).

The following tables show the number of net productive, dry

and in progress exploratory wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of FASB Extractive Activities-oil&gas (Topic 932).

The overall commercial success rate was 16.7% (25.1% net to Eni) as compared to 31.3% (38.0% net to Eni) in 2014 and 36.9% (38.5% net to Eni) in 2013.

Exploratory Well 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

(a) 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.

Development

In 2015 a total of 335 development wells were drilled (132.4 of which represented Eni's share) as compared to 440 development wells drilled in 2014 (191 of which represented Eni's share) and 463 development wells drilled in 2013 (187.2 of which represented Eni's share).

The drilling of 103 development wells (35 of which represented

Eni's share) is currently underway.

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

Development Well Activity

			Wells completed (a)				Wells in progress at Dec. 31
	2013			2014		2015		2015
(units)	Productive	Dry(b)	Productive	Dry(b)	Productive	Dry(b)	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

(a) Net to Eni.

(b) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.

Acreage

In 2015 Eni performed its operations in 42 countries located in five continents. As of December 31, 2015, Eni's mineral right portfolio consisted of 852 exclusive or shared rights of exploration and development activities for a total acreage of 342,708 square kilometers net to Eni of which developed acreage of 40,640 square kilometers and undeveloped acreage of 302,068 square kilometers net to Eni.

In 2015, changes in total net acreage mainly derived from: (i) new

leases mainly in Egypt, Mexico, Myanmar, the United Kingdom and Ivory Coast for a total acreage of approximately 21,500 square kilometers; (ii) the total relinquishment of licences mainly in Congo, Ghana, Italy, Nigeria, Norway, Pakistan, Tunisia and the United States, covering an acreage of approximately 15,600 square kilometers; (iii) interest increase in Australia and partial relinquishment in Indonesia for a total net acreage of 2,000 square kilometers.

Exploration & Production Operating review

Oil and natural gas interests

	December 31, 2014				December 31, 2015
			Gross	Gross		Net	Net
	Total net acreage(a)	Number of Interest	developed acreage(a)(b)	undeveloped acreage(a)	Total gross acreage(a)	developed acreage(a)(b)	undeveloped acreage(a)	Total net acreage(a)
EUROPE	44,842	274	15,873	52,732	68,605	10,989	34,134	45,123
Italy	17,297	147	10,647	10,436	21,083	8,924	8,051	16,975
Rest of Europe	27,545	127	5,226	42,296	47,522	2,065	26,083	28,148
Cyprus	10,018	3		12,523	12,523		10,018	10,018
Croatia	987	2	1,975		1,975	987		987
Greenland	1,909	2		4,890	4,890		1,909	1,909
Norway	3,672	56	2,310	7,594	9,904	452	2,662	3,114
Portugal	6,370	3		9,099	9,099		6,370	6,370
United Kingdom	744	48	941	1,501	2,442	626	1,279	1,905
Other Countries	3,845	13		6,689	6,689		3,845	3,845
AFRICA	159,341	283	63,142	260,577	323,719	19,788	137,653	157,441
North Africa	21,693	119	30,392	26,704	57,096	13,778	11,921	25,699
Algeria	1,179	42	3,222	187	3,409	1,148	31	1,179
Egypt	4,946	57	5,623	17,829	23,452	2,121	7,547	9,668
Libya	13,294	10	17,947	8,688	26,635	8,951	4,343	13,294
Tunisia	2,274	10	3,600		3,600	1,558		1,558
Sub-Saharan Africa	137,648	164	32,750	233,873	266,623	6,010	125,732	131,742
Angola	4,327	72	7,688	13,608	21,296	987	3,417	4,404
Congo	2,883	26	1,794	943	2,737	971	383	1,354
Gabon	7,615	6		7,615	7,615		7,615	7,615
Ghana	1,664	2		226	226		100	100
Ivory Coast		1		1,431	1,431		429	429
Kenya	40,426	7		61,363	61,363		40,426	40,426
Liberia	1,841	3		7,364	7,364		1,841	1,841
Mozambique	5,103	6		3,911	3,911		1,956	1,956
Nigeria	7,638	36	23,268	8,747	32,015	4,052	3,380	7,432
South Africa	32,847	1		82,202	82,202		32,881	32,881
Other Countries	33,304	4		46,463	46,463		33,304	33,304
ASIA	109,237	70	17,556	202,632	220,188	5,803	111,380	117,183
Kazakhstan	869	6	2,391	2,542	4,933	442	427	869
Rest of Asia	108,368	64	15,165	200,090	215,255	5,361	110,953	116,314
China	7,075	8	77	7,056	7,133	13	7,056	7,069
India	6,167	11	206	16,546	16,752	109	6,058	6,167
Indonesia	26,248	14	3,218	31,415	34,633	1,217	23,907	25,124
Iraq	446	1	1,074		1,074	446		446
Myanmar	7,065	4		24,080	24,080		20,050	20,050
Pakistan	9,467	15	10,390	11,486	21,876	3,396	5,414	8,810
Russia	20,862	3		62,592	62,592		20,862	20,862
Timor Leste	1,230	1		1,538	1,538		1,230	1,230
Turkmenistan	180	1	200		200	180		180
Vietnam	26,384	5		30,777	30,777		23,132	23,132
Other Countries	3,244	1		14,600	14,600		3,244	3,244
AMERICAS	7,943	211	5,245	9,458	14,703	3,351	3,277	6,628
Ecuador	1,985	1	1,985		1,985	1,985		1,985
Mexico		3		67	67		67	67
Trinidad & Tobago	66	1	382		382	66		66
United States	3,500	192	1,617	2,301	3,918	803	1,315	2,118
Venezuela	1,066	6	1,261	1,543	2,804	497	569	1,066
Other Countries	1,326	8		5,547	5,547		1,326	1,326
AUSTRALIA AND OCEANIA	13,376	14	1,140	21,679	22,819	709	15,624	16,333
Australia	13,376	14	1,140	21,679	22,819	709	15,624	16,333
Total	334,739	852	102,956	547,078	650,034	40,640	302,068	342,708

(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.

Main exploration and development projects

Italy

In the Val d'Agri concession (Eni's interest 60.77%) 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.

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.

Other main development activities in the Adriatic and Ionic Seas 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.

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 In 2015 Eni was awarded two exploration licences: (i) the operatorship and a 40% interest in the PL 806 licence in the Barents Sea; and (ii) a 13.12% interest in the PL 044C licence in the North Sea. Focus of the exploration activity in 2015 were the preparatory activities for an exploration drilling campaign planned for 2016. At the beginning of 2015, production start-up was achieved at the Eldfisk 2 field (Eni's interest 12.39%) in the North Sea and in September 2015, Asgard Subsea Compression project started up in order to optimize production from Mitgard (Eni's interest 14.8%) and Mikkel fields (Eni's interest 14.9%) in the Norwegian Sea. The project is the first program of deep-sea gas compression in the world. 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. Other activities concerned the maintenance and optimization of the production at the Ekofisk field (Eni's interest 12.39%) and start-up of the FSU at Heidrun field (Eni's interest 5.2%) in the Norwegian Sea.

United Kingdom In 2015, Eni was awarded four exploration licences in the Central North Sea, with interests ranging from 9.13% to 100%. In addition, Eni finalized the acquisition of three licences in the Southern North Sea, with a 100% interest. 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 activities concerned drilling activities for the completion of the development of Jasmine field (Eni's interest 33%).

North Africa

Algeria Development and optimization activities progressed at the MLE-CAFC production fields (Eni operator with a 75% interest), 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.

In 2015, Eni signed with relevant Authorities a five-year extension for the operated field Rom East (Eni's interest 100%). Other activities concerned infilling activities and production optimization at the operated Blocks 403a/d (Eni's interest from 65% to 100%), Rom North (Eni's interest 35%), 401a/402a (Eni's interest 55%) and 403 (Eni's interest 50%), as well as in the nonoperated Blocks 208 and 404 (Eni's interest 12.25%).

Egypt Exploration activities yielded positive results with the following discoveries: (i) 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

Exploration & Production Operating review

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; (ii) oil and gas discovery with the Melehia West Deep well in the Melehia concession (Eni's interest 76%) located in the western desert; (iii) the Sidri-18 oil discovery in the Abu Rudeis concession (Eni's interest 100%) in the Gulf of Suez; (iv) a gas discovery in the Nooros exploration prospect, located in the Abu Madi West license (Eni's interest 75%) in the Nile Delta. 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.

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.

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 state-owned 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, North Port Said (Eni's interest 100%) and Baltim (Eni operator with a 50% interest), 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.

Production activities during the year concerned mainly infilling wells in the Gulf of Suez and Western Desert areas and for gas in El Temsah and Baltim and other production optimization activities aimed to optimized reserves 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 (Eni's interest 100%).

Libya Exploration activities near-field yielded positive results in the contractual area D (Eni's interest 50%), with gas and

condensates discoveries: (i) in the offshore Bahr Essalam South exploration prospect, nearby to the Bahr Essalam production field; (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. 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 (Eni's interest 100%). 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; (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.

Sub-Saharan Africa

Angola 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. In addition, Eni and Sonangol agreed a revision of certain contractual terms to support investments in the Block 15/06 (Eni operator with a 36.84% interest), where in January 2015, Eni obtained a three-year extension of the exploration period.

Eni started production in the Block 15/06 at the end of 2014 with the West Hub Development Project that 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. In addition, Eni started production at: (i) the Kizomba satellites Phase 2 project (Eni's interest 20%), in the deep offshore of the Country, by means of the start-up of further three fields connected to the existing FPSO. The peak production is estimated at approximately 80 kbbl/d; (ii) 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; and (iii) the Gazela field (Eni's interest 12%), with a production of approximately 3 kbbl/d.

Other development activities concerned: (i) the completion of flaring down activities at the Nemba field (Eni's interest 9.8%), with a reduction of gas flared of approximately 85%; and (ii) the Mafumeira project (Eni's interest 9.8%) with production start-up expected at the end of 2016.

Congo Exploration activities yielded positive results in the Marine XII block (Eni operator with a 65% interest) 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.

In 2015, Eni and the local Authorities defined a frame cooperation agreement for the expansion of the CEC power station (Eni's interest 20%), in order to promote the energy development in Congo and contribute to the Country's growth. 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.

Eni achieved production start-up of the Litchendjili field in the Marine XII block 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 while oil production start-up is expected with the next development wells.

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.

Ghana 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.

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 operated OCTP project (Eni's interest 47.22%), 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 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.

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.

Other development activities concerned the production start-up of the Coral discovery. In February 2016, the local Authorities approved the first stage of the development plan. 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 socio-economic 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 completed activities and achieved production start-ups at: (i) the Bonga NW project, by means of the linkage of additional productive and infilling wells to the existing FPSO; and (ii) the Abo project Phase 3, by means of the linkage of two additional production wells to the existing production facilities in the area.

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. Development activities progressed at the OMLs 60, 61, 62 and 63 blocks (Eni's interest 20%) 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. In addition, 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.

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 longterm contracts and exported to US, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co. During 2015, six new vessels were launched.

Kazakhstan

New initiatives 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 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 (Eni's interest 16.81%).

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. As of December 31, 2015, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to \$9.2 billion (€8.4 billion at the EUR/USD exchange rate of December 31, 2015). This capitalized amount included: (i) \$6.8 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) \$2.4 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.

As of December 31, 2015 Eni's proved reserves booked for the Kashagan field amounted to 611 mmbbl, recording an increase of 31 mmbbl compared to 2014 mainly due to lower marker Brent price. The major part of Kashagan reserves are classified proved undeveloped.

Karachaganak 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.

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, maintenance 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.

As of December 31, 2015, Eni's proved reserves booked for the Karachaganak field amounted to 587 mmboe, reporting an increase of 98 mmboe from 2014 mainly due to lower marker Brent price.

Rest of Asia

Indonesia Evaluation activities following the Merakes gas discovery 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. The ongoing development activities that will ensure gas supplies 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.

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 The first stage of the development activities (Rehabilitation Plan) of Zubair field (Eni's interest 41.6%) was substantially completed. 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.

The Zubair 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.

Americas

United States 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.

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

Other development activities concerned the drilling activities at: (i) the operated Devil's Tower field (Eni's interest 75%) 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%), in the Gulf of Mexico; and (ii) the Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni's interest 30%) fields in Alaska.

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 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 the State company 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 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. Drilling activities progressed at the giant Junin 5 oilfield (Eni's interest 40%), located in the Orinoco Oil Belt. Possible optimization of development program is currently under evaluation.

Capital expenditure

Capital expenditure of the Exploration & Production segment (€10,234 million) concerned development of oil and gas reserves (€9,341 million) directed mainly outside Italy, in particular in Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia and the United States. Development expenditures in Italy concerned in particular the drilling program of development wells and facility upgrading in Val d'Agri as well as sidetrack and workover activities in mature fields. About 97% of exploration expenditures (€820 million) were

directed outside Italy in particular to Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia. In Italy, exploration activities were directed mainly to the Adriatic offshore, Val d'Agri and Po Valley. In 2015 overall expenditure in R&D amounted to €78 million (€83 million in 2014). A total of 8 new patents applications were filed.

Capital expenditure	(€ million)	2013	2014	2015	Change	% Ch.
Acquisition of proved and unproved properties		109
North Africa		109
Sub-Saharan Africa
Americas
Exploration		1,669	1,398	820	(578)	(41.3)
Italy		32	29	28	(1)	(3.4)
Rest of Europe		357	188	176	(12)	(6.4)
North Africa		95	227	289	62	27.3
Sub-Saharan Africa		757	635	196	(439)	(69.1)
Kazakhstan		1
Rest of Asia		233	160	71	(89)	(55.6)
Americas		110	139	54	(85)	(61.2)
Australia and Oceania		84	20	6	(14)	(70.0)
Development		8,580	9,021	9,341	320	3.5
Italy		743	880	679	(201)	(22.8)
Rest of Europe		1,768	1,574	1,264	(310)	(19.7)
North Africa		808	832	1,570	738	88.7
Sub-Saharan Africa		2,675	3,085	2,998	(87)	(2.8)
Kazakhstan		658	521	835	314	60.3
Rest of Asia		749	1,105	1,333	228	20.6
Americas		1,127	921	637	(284)	(30.8)
Australia and Oceania		52	103	25	(78)	(75.7)
Other expenditure		117	105	73	(32)	(30.5)
		10,475	10,524	10,234	(290)	(2.8)

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 accidents).

›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 operating 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 the 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 Operating review

• In the Gas & Power segment we forecast sluggish demand growth even if far below the pre-crisis levels. We expect structural
• headwinds in the industry due to the increasing pressure of cheaper electricity from coal and renewables and increasing
• oversupply exacerbated by continued slowdown in China's industrial activity. European hubs will continue to play even more
• important role where approximately 60% of gas is exchanged. Against this scenario our priority is to preserve the economic and
• financial sustainability in the long-term. In order to achieve this goal, our strategy in the Gas & Power sector will leverage on: Strategy
• (i) complete supply portfolio alignment to market conditions;
• (ii) operational streamlining and optimization of logistic costs for total savings of €300 million in 2019;
• (iii) focus on both B2B and retail segments and the development of our portfolio of highly profitable businesses also launching innovative products;
• (iv) strengthen LNG and trading activities also leveraging integration with our upstream operations by marketing equity gas of recent discoveries.

Management expect that these actions will allow to generate a cumulative cash flow from operations in the 2016-2019 period of €2.8 billion.

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), and a market still depressed specially compared to the volumes marketed before the crisis and a raised 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 (for further information on the European scenario, see chapter on "Risk factors" below).

Natural Gas

Supply of natural gas

In 2015 Eni consolidated subsidiaries supplied 85.39 bcm of natural gas, up by 2.48 bcm or 3% from 2014.

Supply of natural gas	(bcm)	2013	2014	2015	Change	% Ch.
Italy		7.15	6.92	6.73	(0.19)	(2.7)
Russia		29.59	26.68	30.33	3.65	13.7
Algeria (including LNG)		9.31	7.51	6.05	(1.46)	(19.4)
Libya		5.78	6.66	7.25	0.59	8.9
Netherlands		13.06	13.46	11.73	(1.73)	(12.9)
Norway		9.16	8.43	8.40	(0.03)	(0.4)
United Kingdom		3.04	2.64	2.35	(0.29)	(11.0)
Hungary		0.48	0.38	0.21	(0.17)	(44.7)
Qatar (LNG)		2.89	2.98	3.11	0.13	4.4
Other supplies of natural gas		3.63	5.56	7.21	1.65	29.7
Other supplies of LNG		1.58	1.69	2.02	0.33	19.5
Outside Italy		78.52	75.99	78.66	2.67	3.5
TOTAL SUPPLIES OF ENI'S CONSOLIDATED SUBSIDIARIES		85.67	82.91	85.39	2.48	3.0
Offtake from (input to) storage		(0.58)	(0.20)		0.20	100.0
Network losses, measurement differences and other changes		(0.31)	(0.25)	(0.34)	(0.09)	(36.0)
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES		84.78	82.46	85.05	2.59	3.1
Available for sale by Eni's affiliates		5.78	3.65	2.67	(0.98)	(26.8)
E&P volumes		2.61	3.06	3.16	0.10	3.3
TOTAL AVAILABLE FOR SALE		93.17	89.17	90.88	1.71	1.9

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.

In 2015, main gas volumes from equity production derived from: (i) Italian gas fields (5.2 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.2 bcm); (iii) Libyan fields (2.2 bcm); (iv) the United States (1.4 bcm); (v) other European areas (Croatia with 0.2 bcm).

Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 17 bcm representing 19% of total volumes available for sale.

Sales of natural gas

In 2015, natural gas sales amounted to 90.88 bcm (including Eni's own consumption, Eni's share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico), up by 1.71 bcm or 1.9% from the previous year.

Gas sales by entity 2013 2014 2015 Change % Ch. (bcm) Total sales of subsidiaries 83.60 81.73 84.94 3.21 3.9 Italy (including own consumption) 35.76 34.04 38.44 4.40 12.9 Rest of Europe 42.30 43.07 41.14 (1.93) (4.5) Outside Europe 5.54 4.62 5.36 0.74 16.0 Total sales of Eni's affiliates (net to Eni) 6.96 4.38 2.78 (1.60) (36.5) Italy 0.10 Rest of Europe 5.05 3.15 1.75 (1.40) (44.4) Outside Europe 1.81 1.23 1.03 (0.20) (16.3) E&P in Europe and in the Gulf of Mexico 2.61 3.06 3.16 0.10 3.3 WORLDWIDE GAS SALES 93.17 89.17 90.88 1.71 1.9

Gas sales by market	(bcm)	2013	2014	2015	Change	% Ch.
ITALY		35.86	34.04	38.44	4.40	12.9
Wholesalers		4.58	4.05	4.19	0.14	3.5
Italian gas exchange and spot markets		10.68	11.96	16.35	4.39	36.7
Industries		6.07	4.93	4.66	(0.27)	(5.5)
Small and medium-sized enterprises and services		1.12	1.60	1.58	(0.02)	(1.3)
Power generation		2.11	1.42	0.88	(0.54)	(38.0)
Residential		5.37	4.46	4.90	0.44	9.9
Own consumption		5.93	5.62	5.88	0.26	4.6
INTERNATIONAL SALES		57.31	55.13	52.44	(2.69)	(4.9)
Rest of Europe		47.35	46.22	42.89	(3.33)	(7.2)
Importers in Italy		4.67	4.01	4.61	0.60	15.0
European markets		42.68	42.21	38.28	(3.93)	(9.3)
Iberian Peninsula		4.90	5.31	5.40	0.09	1.7
Germany/Austria		8.31	7.44	5.82	(1.62)	(21.8)
Benelux		8.68	10.36	7.94	(2.42)	(23.4)
Hungary		1.84	1.55	1.58	0.03	1.9
UK		3.51	2.94	1.96	(0.98)	(33.3)
Turkey		6.73	7.12	7.76	0.64	9.0
France		7.73	7.05	7.11	0.06	0.9
Other		0.98	0.44	0.71	0.27	61.4
Extra European markets		7.35	5.85	6.39	0.54	9.2
E&P in Europe and in the Gulf of Mexico		2.61	3.06	3.16	0.10	3.3
WORLDWIDE GAS SALES		93.17	89.17	90.88	1.71	1.9

Gas & Power Operating review

Sales in Italy increased to 38.44 bcm, up by 12.9% due to higher spot volumes and more severe weather conditions compared to 2014. These effects were partially offset by lower volumes marketed to the thermoelectric segment due to the competition from other energy sources (in particular, from renewables), the reduction in electricity demand registered in particular in the first part of the year as well as lower sales to the industrial segment due to increasing competitive pressure. Sales in European markets were 38.28 bcm, down by 9.3% from last year. This can be attributable to lower spot sales in Benelux and in Germany/Austria due to competitive pressure and the divestment of the GVS joint venture occurred in 2014 as well as in the United Kingdom, partially offset by higher sales in Turkey reflecting higher sales to Botas.

Direct sales of Exploration & Production segment in Northern Europe and the United State (3.16 bcm) increased by 0.10 bcm due to higher volumes marketed in the North Sea.

Sales to long-term buyers were up by 15% compared to the previous year, due to larger availability of Libyan output and higher sales to Extra European markets (up by 9.2%) driven by higher spot sales in the United States.

LNG

In 2015, LNG sales (13.5 bcm) were substantially unchanged from last year (up by 0.2 bcm). In particular, LNG sales in 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.

LNG sales	(bcm)	2013	2014	2015	Change	% Ch.
G&P sales		8.4	8.9	9.0	0.1	1.1
Rest of Europe		4.6	5.0	4.8	(0.2)	(4.0)
Outside Europe		3.8	3.9	4.2	0.3	7.7
E&P sales		4.0	4.4	4.5	0.1	2.3
Terminals:
Soyo (Angola)		0.1	0.1		(0.1)
Bontang (Indonesia)		0.5	0.5	0.5
Point Fortin (Trinidad & Tobago)		0.6	0.6	0.7	0.1	16.7
Bonny (Nigeria)		2.4	2.8	2.8
Darwin (Australia)		0.4	0.4	0.5	0.1	25.0
		12.4	13.3	13.5	0.2	1.5

Power

Availability of electricity

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.

Power 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.

		2013	2014	2015	Change	% Ch.
Purchases of natural gas	(mmcm)	4,295	4,074	4,270	196	4.8
Purchases of other fuels	(ktoe)	449	338	313	(25)	(7.4)
Power generation	(TWh)	21.38	19.55	20.69	1.14	5.8
Steam	(ktonnes)	9,907	9,010	9,318	308	3.4

Operating review Gas & Power

Availability of electricity	(TWh)	2013	2014	2015	Change	% Ch.
Power generation		21.38	19.55	20.69	1.14	5.8
Trading of electricity(a)		13.67	14.03	14.19	0.16	1.1
		35.05	33.58	34.88	1.30	3.9
Free market		28.73	24.86	25.90	1.04	4.2
Italian Exchange for electricity		1.96	4.71	5.09	0.38	8.1
Industrial plants		3.31	3.17	3.23	0.06	1.9
Other(a)		1.05	0.84	0.66	(0.18)	(21.4)
Power sales		35.05	33.58	34.88	1.30	3.9

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

Capital expenditure

In 2015 capital expenditure amounted to €154 million, mainly related to initiatives aimed to improve flexibility and upgrade the combined cycle power plants (€69 million) and gas marketing initiatives (€69 million).

Capital expenditure (€ million)	2013	2014	2015	Change	% Ch.
Marketing	206	164	138	(26)	(15.9)
Marketing	87	66	69	3	4.5
Italy	42	30	31	1	3.3
Outside Italy	45	36	38	2	5.6
Power generation	119	98	69	(29)	(29.6)
International transport	23	8	16	8	100.0
	229	172	154	(18)	(10.5)
of which:
Italy	161	128	100	(28)	(21.9)
Outside Italy	68	44	54	10	22.7

Refining & Marketing

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 reported an adjusted net profit of €282 million, up by €323 million compared to the adjusted operating loss of €41 million reported in previous year. This result reflected improved refining margins scenario and restructuring and optimization initiatives, which, together with an improved selection of raw materials, reduced refining break-even margin to 5\$/bl anticipating EBIT break-even to 2015, vs an original guidance for the year 2017 indicated in the 2015-2018 strategic plan.

›In 2015 refining throughputs were 26.41 mmtonnes, up by 1.38 mmtonnes 5.5% from 2014. In Italy, processed volumes increased by 14.1% mainly due to seized opportunities of the favorable refinery scenario. 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% 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 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%).

Strategy

The priority of the Refining & Marketing segment is the consolidation of business profitability registered in the last reporting period, in a context of weak fundamentals of the European refining market, affected by structural overcapacity, as well as the increasing competitive pressure from streams of oil products imported from Middle East, Russia and Asia.

For the next four years the management priority is the achievement of a stable positive operating profit and free cash flow, leveraging on: (i) the ongoing reconversion of industrial plants in bio-refinery; (ii) the optimization of the production assets and the utilization of more profitable raw materials also leveraging on the reconversion capacity of the heavy fractions of crude oil into light products, ensured by the EST technology at Sannazzaro Refinery; (iii) continuous efficiency improvement in both refining and commercial activities; (iv) marketing activities development mainly through product and service differentiation and innovation; (v) strengthening of competitive position in the main Central-European markets (Germany, Austria, Switzerland and France). Overall, these planned actions will allow to reduce the refinery breakeven margin to 3 \$/bl from 2018.

Supply and Trading

In 2015, were purchased 24.80 mmtonnes of crude oil (compared with 23.02 mmtonnes in 2014), of which 5 mmtonnes by equity crude oil. The subdivision by geographic area was as follows:

approximately 47% of purchased crude came from former USSR, 20% from the Middle East, 16% from Italy, 12% from North Africa, 2% from West Africa, 1% from North Sea and 2% from other areas.

Purchases	(mmtonnes)	2013	2014	2015	Change	% Ch.
Equity crude oil		5.93	5.81	5.04	(0.77)	(13.3)
Other crude oil		19.71	17.21	19.76	2.55	14.8
Total crude oil purchases		25.64	23.02	24.80	1.78	7.7
Purchases of intermediate products		2.46	2.02	1.66	(0.36)	(17.8)
Purchases of products		9.62	11.07	10.68	(0.39)	(3.5)
TOTAL PURCHASES		37.72	36.11	37.14	1.03	2.9
Consumption for power generation		(0.55)	(0.57)	(0.41)	0.16	28.1
Other changes(a)		(1.59)	(0.62)	(1.22)	(0.60)	(96.8)
		35.58	34.92	35.51	0.59	1.7

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

Refining & Marketing Operating review

Refining

In 2015 refining throughputs were 26.41 mmtonnes, up by 1.38 mmtonnes or 5.5% from 2014.

In Italy, refinery throughputs increased by 14.1% from 2014, reflecting the favorable refinery scenario. Particularly, the selection of crude oil purchased has been addressed to highsulphur and profitable quality, thanks to a purchase strategy which privileged spot market vs long-term market. On an homogeneous structure, excluding the effect of the shutdown for conversion of the Refinery of Gela, volumes processed increased by 16.4% compared to 2014. The volumes of palm oil processed at Venice plant reported an increase compared with 2014 (start-up year). On a homogeneous basis when excluding the effects of the shutdown of the Gela, process volumes increased by 16.4% from 2014. In 2015 the production of biofuels increased from 2014 period (start-up year of Porto Marghera bio-refinery).

Outside Italy, Eni's refining throughputs were 3.69 mmtonnes,

down by 1.42 mmtonnes or 27.8% from previous reporting period, mainly due to the above mentioned divestment in Czech Republic occurred in the second quarter of 2015. Excluding such effects, on a homogeneous basis, refining throughput were up by 5%.

Total throughputs in wholly-owned refineries were 18.37 mmtonnes, down by 2.13 mmtonnes or 13.1% compared with 2014, determining a refinery utilization rate (ratio between throughputs and balanced capacity) of 94.7%. Approximately 20.4% of processed crude was supplied by Eni's Exploration & Production segment, down by 4.8 percentage point from 2014 (25.2%).

In the field of local development, as provided by stakeholder agreements, Eni continued the commitment to environmental protection and improvement, as well as, social and urban development projects, as defined by the conventions signed with the Municipality of Ferrera Erbognone and Sannazzaro de' Burgondi.

Availability of refined products	(mmtonnes)	2013	2014	2015	Change	% Ch.
ITALY
At wholly-owned refineries		18.99	16.24	18.37	2.13	13.1
Less input on account of third parties		(0.57)	(0.58)	(0.38)	0.20	34.5
At affiliated refineries		4.14	4.26	4.73	0.47	11.0
Refinery throughputs on own account		22.56	19.92	22.72	2.80	14.1
Consumption and losses		(1.23)	(1.33)	(1.52)	(0.19)	(14.3)
Products available for sale		21.33	18.59	21.20	2.61	14.0
Purchases of refined products and change in inventories		5.73	7.19	6.22	(0.97)	(13.5)
Products transferred to operations outside Italy		(0.83)	(0.73)	(0.48)	0.25	34.2
Consumption for power generation		(0.55)	(0.57)	(0.41)	0.16	28.1
Sales of products		25.68	24.48	26.53	2.05	8.4
OUTSIDE ITALY
Refinery throughputs on own account		4.82	5.11	3.69	(1.42)	(27.8)
Consumption and losses		(0.22)	(0.21)	(0.23)	(0.02)	(9.5)
Products available for sale		4.60	4.90	3.46	(1.44)	(29.4)
Purchases of refined products and change in inventories		4.30	4.48	4.77	0.29	6.5
Products transferred from Italian operations		0.83	0.73	0.48	(0.25)	(34.2)
Sales of products		9.73	10.11	8.71	(1.40)	(13.8)
Refinery throughputs on own account		27.38	25.03	26.41	1.38	5.5
of which: refinery throughputs of equity crude on own account		5.93	5.81	5.04	(0.77)	(13.3)
Total sales of refined products		35.41	34.59	35.24	0.65	1.9
Crude oil sales		0.18	0.33	0.27	(0.06)	(18.2)
TOTAL SALES		35.59	34.92	35.51	0.59	1.7

Marketing of refined products

In 2015, retail sales of refined products (35.24 mmtonnes)

increased by 0.65 mmtonnes from 2014, up by 1.9%, mainly due to higher volumes sold to oil companies.

Product sales in Italy and outside Italy by market	(mmtonnes)	2013	2014	2015	Change	% Ch.
Retail		6.64	6.14	5.96	(0.18)	(2.9)
Wholesale		8.37	7.57	7.84	0.27	3.6
Petrochemical		1.24	0.89	1.17	0.28	31.5
Other sales		9.43	9.89	11.56	1.67	16.9
Sales in Italy		25.68	24.49	26.53	2.04	8.3
Retail Rest of Europe		3.05	3.07	2.93	(0.14)	(4.6)
Wholesale Rest of Europe		4.56	4.60	3.83	(0.78)	(16.7)
Wholesale outside Italy		0.10	0.43	0.43
Other sales		2.02	2.00	1.52	(0.48)	(24.2)
Sales outside Italy		9.73	10.10	8.71	(1.39)	(13.8)
TOTAL SALES OF REFINED PRODUCTS		35.41	34.59	35.24	0.65	1.9

Retail sales in Italy

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. Eni's retail market share for 2015 was 24.5%, down by one percentage point 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 on January 2015. On April 2016, a new "you & eni" program has been launched, with a 2 years duration, addressed to customers that utilize served modality.

Retail and wholesales sales of refined products	(mmtonnes)	2013	2014	2015	Change	% Ch.
Italy		15.01	13.71	13.80	0.09	0.7
Retail sales		6.64	6.14	5.96	(0.18)	(2.9)
Gasoline		1.96	1.71	1.60	(0.11)	(6.4)
Gasoil		4.33	4.07	3.96	(0.11)	(2.7)
LPG		0.32	0.32	0.36	0.04	12.5
Others		0.03	0.04	0.04
Wholesale sales		8.37	7.57	7.84	0.27	3.6
Gasoil		4.09	3.54	3.69	0.15	4.2
Fuel Oil		0.24	0.12	0.12
LPG		0.30	0.28	0.22	(0.06)	(21.4)
Gasoline		0.25	0.30	0.38	0.08	26.7
Lubricants		0.09	0.09	0.07	(0.02)	(22.2)
Bunker		1.00	0.91	1.07	0.16	17.6
Jet fuel		1.58	1.59	1.60	0.01	0.6
Other		0.82	0.74	0.69	(0.05)	(6.8)
Outside Italy (retail+wholesale)		7.71	8.10	7.19	(0.91)	(11.2)
Gasoline		1.73	1.80	1.51	(0.29)	(16.1)
Gasoil		4.23	4.48	3.98	(0.50)	(11.2)
Jet fuel		0.51	0.56	0.65	0.09	16.1
Fuel Oil		0.22	0.18	0.17	(0.01)	(5.6)
Lubricants		0.10	0.10	0.10
LPG		0.51	0.55	0.51	(0.04)	(7.3)
Other		0.41	0.43	0.27	(0.16)	(37.2)
		22.72	21.81	20.99	(0.82)	(3.8)

Refining & Marketing Operating review

Service stations in Italy and average throughput

Retail sales in the 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 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 disposal, 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 with December 31, 2014 mainly due to the assets sale in East European subsidiaries. Average throughput (2,272 kliters) were substantially stable compared to the previous reporting period.

Wholesale and other sales

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.

In the field of lubricants, Eni launched a new line of products for motorcycles (i-Ride) able to guarantee high performance and reliability of engines for which is designed.

Capital expenditure

In 2015, capital expenditure amounted to €408 million and mainly regarded: (i) refining activities in Italy and outside Italy (€282 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) upgrading and rebranding of the refined product retail network in Italy (€75 million) and in the Rest of Europe (€51 million).

Capital expenditure	(€ million)	2013	2014	2015	Change	% Ch.
Refining		497	362	282	(80)	(22.1)
Marketing		175	175	126	(49)	(28.0)
		672	537	408	(129)	(24.0)

Discontinued operations

Saipem transaction

In the last months of 2015, Eni defined a complex transaction to restructure the share ownership of the listed subsidiary Saipem through the entry of a new shareowner, obtaining the reimbursement of intercompany loans, in line with the Group strategy aimed to:

• focus on its upstream core business, by making available additional financial sources to be reinvested in the development of the considerable mineral resources recently discovered;
• strengthening of its capital structure on the back of the weaker oil scenario.

On January 22, 2016, following the fulfilment of all the conditions precedent, among which the consensus of Consob to the subscription of the share capital increase in Saipem, was closed the sale of 12.503% of Eni's interest in the share capital of Saipem to Fondo Strategico Italiano (FSI). The transaction refers to No. 55,176,364 Saipem shares at an average price of €8.4 per share. The reference price for the transaction was the arithmetic average of the Official prices for the shares registered in the trading days immediately before and after the announcement to the markets of the transaction, on October 28, 2015. The total consideration of €463 million has been paid by FSI through a single payment, at the time of the transaction execution.

Contextually, Eni and FSI entered into the Shareholders' Agreement signed on October 27, 2015, by virtue of which they intended to establish the terms and conditions that shall govern, from the closing date onwards, their relations as shareholders of Saipem.

Each of Eni and FSI will contribute to the Shareholders' Agreement, for its entire duration, an equal number of Saipem shares, which will not exceed 12.503% of the Company's ordinary share capital (therefore up to a total amount slightly above 25% of Saipem ordinary share capital). The Shareholders' Agreement will enter into force on the closing date of the Sale and Purchase Agreement, for a period of three years, with automatic renewal for a further period of three years, unless terminated by notice.

The key elements of the Shareholders' Agreement provides, inter alia:

• a) for the future renewal of corporate bodies, the submission by Eni and FSI of a single list for the appointment of the Board of Directors (where the President and the CEO will be designated jointly by the parties) and the panel of statutory auditors of Saipem and the relevant vote commitments;
• b) mutual commitments to stand-still and lock-up commitment on all the shares contributed to the Shareholders' Agreement, and certain other restrictions regarding the transfer of

shares not contributed to the Shareholders' Agreement;

c) obligations to engage in consultation before exercising voting rights and, to the extent permitted by law, voting commitments (also regarding Saipem shares not contributed to the Shareholders' Agreement) in relation to all resolutions submitted to the Shareholders Meetings of Saipem and certain resolutions of Saipem's Board of Directors that are conventionally considered relevant, among which the approval of the industrial plan.

As defined by the Shareholders' Agreement and following the transaction, Eni and FSI jointly control Saipem.

Eni and FSI have undertaken towards Saipem an irrevocable obligation to subscribe pro-rata the capital increase for €3.5 billion. The agreements foresee the reimbursement of intercompany net debt by Saipem to Eni through funds from share capital increase and the refinancing at certain third parties.

Considering, that the transactions disclosed above were defined after the end of 2015, in the financial statements of 2015 Saipem is still fully consolidated and represented as "discontinued operation" based on the guidelines of IFRS 5 on certain disposal assets.

Therefore, economic and financial impacts of Saipem transaction will be recorded in the 2016 Eni statutory reporting, as described below:

• considering that the governance structure defined in the Shareholders Agreement established joint control over Saipem, Eni will derecognize the former subsidiary from its consolidated accounts' assets and liabilities, revenues and expenses, effective January 1, 2016. The residual stake in Saipem of 30.42% will be evaluated on the base of the equity accounting method, considering the book value to be equal to the share price at the closing date of the transaction (€4.2 per share) equal to an overall value of €564 million and a loss to recognize through profit and loss of €441 million (resulting from the difference between the fair value and the book value at December 31, 2015);
• reduction of €4.8 billion of net debt resulting from the reimbursement by Saipem to Eni of intercompany debt (€5.4 billion as of December 31, 2015) and cash from the disposal of Eni's stake (€0.4 billion), net of the amount cashed out to subscribe capital increase (€1.07 billion);
• assuming the effects of the transaction at December 31, 2015, pro-forma leverage declined to 0.22.

At the end of February 2016, following the subscription of capital increase and third-party refinancing, Saipem reimbursed integrally intercompany loans.

Discontinued operations Operating review

As of the date of the transaction agreement, Eni is subjected to the de facto control of the MEF (Italian Ministry of Economy and Finance). FSI is also indirectly controlled by MEF. Therefore the transaction is a transaction between Eni and one of its related parties, deemed "more relevant" for the purpose of the Consob Regulation No. 17721/2010, as amended ("Related Parties Regulation") and of the related parties procedure adopted by Eni ("Related Parties Procedure"). The transfer of the Transferred Stake to FSI also represents a significant transfer1 transaction within the meaning of Article 71 of the Consob Regulation No. 11791/1999 ("Issuers' Regulation").

For further information see the information document filled on November 3, 2015 published in accordance to article 5 of Consob regulation and article 71 of the Consob regulation No. 11971/1999 available on the website eni.com.

Description of the company involved in the Transaction

Saipem supplies turnkey and infrastructure plants for the oil, refining and petrochemical industry, and provides engineering, procurement, construction, installation and commissioning services under EPC (Engineering, Procurement, Construction) and EPCI (Engineering, Procurement, Construction, Installation) contracts. In addition, Saipem is one of the leading worldwide providers of offshore drilling services, due to its technologically advanced fleet of vessels and rigs. The Company also operates in the onshore drilling business. The Company is well positioned in the market for services to the oil industry, in both the construction of offshore and onshore projects, focusing on the toughest and most technologically challenging projects, which are conducted in remote areas, in deep water and which involve complex hydrocarbon extraction, in which it leverages its distinctive competences and execution skills.

The company has a large and diversified orders portfolio, consisting in many ultra-deep water projects, extreme condition pipeline laying, as well as relevant and complex onshore projects, in which it leverages the competitive advantage it has acquired from its technologically advanced fleet and its distinctive know-how.

Saipem is a global contractor, with a strong local presence in strategic and emerging markets such as West Africa, North Africa, the Middle East, and South East Asia.

In 2015 new contracts awarded to Saipem amounted to €6,515 million. The relevant ones related to:

• an Engineering & Construction contract on behalf of North Caspian Operating Company for the Kashagan field project, which includes the construction of two 95-kilometres pipelines, which will connect the island D located in the Caspian Sea to the Karabatan in Kazakhstan;
• a contract on behalf of Fermaca Pipeline El Encino, for the EPC project that encompasses engineering, procurement, construction and support with commissioning of a new compression station in El Encino, located in Mexico.

Orders acquired	(€ million)	2013	2014	2015	Change	% Ch.
		10,062	17,971	6,515	(11,456)	(63.7)
Engineering & Construction Offshore		5,581	10,043	4,479	(5,564)	(55.4)
Engineering & Construction Onshore		2,193	6,354	1,386	(4,968)	(78.2)
Offshore drilling		1,401	722	234	(488)	(67.6)
Onshore drilling		887	852	416	(436)	(51.2)

As of December 31, 2015, order backlog was €15,846 million (€22,147 million at December 31, 2014). The order backlog was negatively impacted by the cancellation of outstanding

orders for the South Stream project (€1,232 million), which was terminated by the client under a termination for convenience provision received on July 8, 2015.

Order backlog	(€ million)	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2015	Change	% Ch.
		17,065	22,147	15,846	(6,301)	(28.5)
Engineering & Construction Offshore		8,320	11,161	7,518	(3,643)	(32.6)
Engineering & Construction Onshore		4,114	6,703	5,301	(1,402)	(20.9)
Offshore drilling		3,390	2,920	2,010	(910)	(31.2)
Onshore drilling		1,241	1,363	1,017	(346)	(25.4)

(1) The Management System Guideline "Transactions involving the interests of the directors and statutory auditors and Transactions with Related Parties" was approved by Eni's Board on November 18, 2010 and amended on January 19, 2012. The Document is available on the website www.eni.com, section: "Governance - Related Parties".

Versalis

As far as the chemical business managed by Eni's wholly-owned subsidiary Versalis SpA is concerned, at December 31, 2015, negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business.

Therefore, effective for the full year, likewise Saipem, Versalis' assets and liabilities, revenues and expenses and cash flow have been classified as discontinued operations. In addition, Eni's net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the transaction that is underway.

Description of the business under disposal

Eni, through Versalis, performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies, advanced production facilities, as well as a large and efficient retail network present in 17 European countries.

Versalis' portfolio of patents and proprietary technologies covers the whole field of basic petrochemicals and polymers: phenol and its derivatives, polyethylene, styrenes and elastomers as well as catalysts and special chemical products.

As a producer of intermediates, all types of polyethylene and a wide range of elastomers/latices and of the complete line of styrenic products, Versalis continues in the development of its proprietary

technologies supported by the experience it gained in production and R&D. This approach favoured the optimization of the design of equipment and plants, of their performance, of proprietary catalysts and other products that allowed it to achieve excellence in all technologies in the specific business areas in order to compete in markets worldwide. A key role is played by the most innovative proprietary catalysts, particularly those based on zeolites developed by Versalis as building blocks of some of its most advanced technologies and available worldwide.

The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibres and polystyrene. In the polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular, in the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

In 2015, production of petrochemical products amounted to 5,700 ktonnes, increasing by 417 ktonnes compared to the previous year, thanks to the recovery in products demand.

	(ktonnes)	2013	2014	2015	Change	% Ch.
Intermediates		3,462	2,972	3,334	362	12.2
Polymers		2,355	2,311	2,366	55	2.4
Production		5,817	5,283	5,700	417	7.9

Eni's results of operations and cash flow as at and for the twelve months ended December 31, 2015 have been prepared: (i) on a consolidated basis; and (ii) presenting separately continuing operations from discontinued operations, in accordance to IFRS 5. Discontinued operations comprise:

• The E&C operating segment which is managed by Eni's former subsidiary Saipem SpA. On January 22, 2016, there was the closing of the agreements signed on October 27, 2015 with the Fondo Strategico Italiano (FSI). Those include the sale of a 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 subsidiary. Therefore effective for the full year, Saipem revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition as provided by IFRS 5, Eni's net assets in Saipem have been aligned to the lower of their carrying amount and fair value given by the share price at the reporting date.
• The chemical segment managed by Eni's wholly-owned subsidiary Versalis SpA. As of the reporting date, negotiations are underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing the industrial plan designed to upgrade this business. Therefore, effective for the full year, likewise Saipem, Versalis revenues and expenses and cash flow have been classified as discontinued operations and its assets and liabilities have been classified as held for sale. In addition, as provided by IFRS 5, Eni's net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the transaction that is underway.

Consequently, the review of the financial performance of the FY2015 mainly focuses on the results of the continuing operations. In this regard, taking into consideration that gains and losses pertaining to the discontinued operations include according to the accounting provided by IFRS 5 only those resulting from transactions with third parties, the results of the continuing operations do not fully illustrate the underlying performance given the elimination of gains and losses on intercompany transactions with the discontinued operations. The same is true for the performance of the discontinued operations. The bigger are the intercompany transactions, the larger is that sort of misrepresentation.

In particular, the accounting of the E&C segment as discontinued operations according to IFRS 5 criteria yields a benefit to the continuing operations due to the elimination of the costs incurred towards Saipem for the execution of contract works commissioned by Eni's Group companies for maintenance and construction of assets (plants and other infrastructures). On the contrary, the accounting of the chemical segment as discontinued operations affects the results of the continuing operations due to the elimination of revenues relating to the supply of oil-based petrochemical feedstock and other plant utilities to Versalis, mainly from the Group's R&M segment.

Because of this, in order to obtain a better comparison of base Group performance across reporting periods and to understand in a better way underlying industrial trends, throughout this financial review management has presented measures of the underlying performance of the continuing operations on a standalone basis by reinstating the effects of the elimination of intercompany transactions. These performance measures by excluding gains and losses of the discontinued operations earned from both third parties and the Group's continuing operations, actually determine the derecognition of the two disposal group. These measures are: standalone adjusted operating profit, standalone adjusted net profit and standalone cash flow from operations1 .

(1) Management assesses the underlying performance of the Group's business segments looking at certain Non-GAAP measures of results from operations. Those Non-GAAP measures are the adjusted operating profit and the adjusted net profit, which exclude from reported operating profit and reported net profit the impact of extraordinary gains and losses ("special items") pre-tax and post-tax respectively, as well as of the profit/loss on stock. Special items mainly comprise asset impairment losses, gains on disposal, restructuring charges, environmental and other provisions, the fair value of certain derivative contracts lacking the formal criteria to be accounted as hedges and write-downs of deferred tax assets. The profit/loss on stock is the difference between the current costs of supplies and the cost determined in accordance to the weighted-average cost accounting method for the evaluation of inventories as provided by IFRSs.

Furthermore, considering the process to dispose of the two business segments "E&C" and "Chemical", which is underway at the reporting date and the related accounting of the two disposal groups as discontinued operations in accordance to IFRS5, management has presented in this press release additional Non-GAAP measures to assess the performance of the continuing operations. Those measures are the standalone adjusted operating profit and the standalone adjusted net profit, which reinstate in the results of the continuing operations the effect related to the elimination of profit on intercompany transactions with the discontinued operations. Those Non-GAAP measures obtain a representation of the performance of the continuing operations anticipating the effect of the derecognition of the discontinued operations. A corresponding alternative performance measure has been presented for the cash flow from operating activities (operating cash flow on a standalone basis).

2015 results

In 2015 Eni reported a net loss pertaining to continuing

operations of €7,680 million, considerably down compared to the previous year (closed in substantial break-even). A prolonged slide in crude oil prices has negatively affected the Group's performance, impacting results from operations and the value of assets.

Operating performance resulted in a loss of €2,781 million. These negatives were driven by lower E&P revenues reflecting reduced oil and gas realizations negatively impacted by sharply lower Brent prices (down by 47%), the alignment of the carrying amounts of oil and product inventories to current market prices and the recognition of material impairment losses mainly taken at the Group oil&gas CGUs (€4,502 million). In performing the impairment review, Eni's management assumed a reduced long-term price outlook for the Brent crude oil price down to \$65 per barrel compared to the previous \$90 per barrel scenario adopted for valuating asset recoverability in the 2014 financial statements. Furthermore, the operating loss was impacted by an estimate revision of €484 million taken at revenues accrued on the sale of natural gas and electricity to retail customers in Italy dating back to past reporting periods and the establishment of a provision of €226 million for those accruals.

Eni's management has implemented certain initiatives to mitigate the negative effect of low oil prices on profitability and cash flow. These initiatives include the reduction of E&P operating expenses and the curtailment of capital expenditure by carefully selecting exploration plays, rescheduling and re-phasing large development activities and renegotiating supply contracts for plants and other E&P infrastructures, as well as leveraging oilfield services rates on the deflationary pressure induced by the decline in crude oil prices. This reduction in capital expenditure only had a modest impact on hydrocarbon production, which grew by 10% to 1.760 kboe/d. The production plateau has been the highest since 2010, on yearly basis. The Refining & Marketing segment returned to underlying profitability supported by plant optimizations and an ongoing margin recovery. The G&P segment almost achieved operating profit break-even, net of extraordinary charges related to the unfavorable outcome of commercial arbitration, and in spite of the postponement of the recognition of gains on the renegotiations of certain longterm supply contracts. Finally, G&A expenses were reduced by €0.6 billion.

Net loss for 2015 was significantly affected by an increased tax rate driven by a deteriorating price scenario in the E&P segment, which resulted in the segment's taxable profit earned in PSA contracts, which, although more resilient in a low-price environment, nonetheless bear higher-thanaverage rates of tax and a higher incidence of non-deductible expenses on the pre-tax profit that has been lowered by the scenario. In addition, the tax rate was impacted by lower recognition of deferred tax assets relating operating losses

due to a reduced profitability outlook (€1,058 million). The Group tax rate was also impacted by the write-off of Italian deferred tax assets of €885 million in the full year due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutory tax rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date.

Net loss attributable to Eni's shareholders including both continuing operations and discontinued operations amounted to €8,783 million for the FY2015. The loss of the discontinued operations pertaining to Eni's shareholders was affected by the recognition of impairment losses on the disposal groups Saipem and Versalis, which net assets were aligned to the lower of their carrying amounts and fair value. Eni's net assets in Saipem and Versalis were aligned respectively to the share price at the reporting date and the likely outcome of the industrial agreement, which is being evaluated in the negotiations currently underway, resulting in an overall impairment charge of €1,969 million. Partly offsetting, a fair-valued derivative gain of €49 million was recorded for Saipem due to the difference between the transaction price (€8.39 per share) and the market price at the reporting date (€7.49 per share) for the stake disposed of to FSI.

On January 22, 2016, following the closing of the Saipem transaction, the residual interest in the former subsidiary was initially recognized as investment in a joint venture and was aligned at the market price at closing of €4.2 per share with a charge through profit and loss of €441 million. Subsequently, in February 2016 Saipem's market capitalization has fallen sharply. Under the provisions of IAS 10 these negative developments do not constitute adjusting events of the Saipem valuation made in the 2015 accounts which aligned the Saipem carrying amount to the market price at December 31, 2015.

In 2015, adjusted operating profit of continuing operations on a standalone basis was €4,104 million, down by €7,338 million or by 64.1%. The decrease was driven mainly by the upstream segment (down by €7,443 million or 64.6%) due to the effects of scenario/exchange rate, which impacted by €8.8 billion, 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 from continuing operations on a standalone basis of €334 million was down by €3,520 million. Net result excluded a post-tax inventory loss (€561 million), post-tax special charges (€6,421 million) and an adjustment amounting to €1,032 million, which was made to reinstate the elimination of gains and losses on intercompany transactions with the discontinued operations. These adjustments resulted in an overall positive adjustment of €8,014 million.

Special items of the operating profit of continuing operations

(net charges of €5,762 million) comprised: (i) impairment losses

Adjusted results(*)

2013	(€ million)	2014	2015	Change	% Ch.
11,280	Adjusted operating profit (loss) - continuing operations	10,447	3,795	(6,652)	(63.7)
1,856	Reinstatement of intercompany transactions vs. disc. Op.	995	309
13,136	Adjusted operating profit (loss) - continuing operations on a standalone basis	11,442	4,104	(7,338)	(64.1)
3,472	Net profit (loss) attributable to Eni's shareholders - continuing operations	101	(7,680)	(7,781)
291	Exclusion of inventory holding (gains) losses	890	561
(1,264)	Exclusion of special items	1,209	6,421
2,499	Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations	2,200	(698)	(2,898)
1,355	Reinstatement of intercompany transactions vs. disc. Op.	1,654	1,032
3,854	Adjusted net profit (loss) attributable to Eni's shareholders on a standalone basis	3,854	334	(3,520)	(91.3)
63.2	Tax Rate (%)	65.3	93.0

(*) Adjusted results from continuing operations 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, represented as discontinued operations under the IFRS 5.

(€4,826 million) mainly in the E&P segment, relating to oil&gas properties driven by the impact of a lower price environment on the expected future cash flows in the medium and long-term. The most notable impairments refer to certain assets, which were acquired by the Group following business combinations in previous reporting periods (Algeria, Congo and Turkmenistan) and to CGUs which are currently operating in high-cost areas (USA, UK, Norway and Angola). Furthermore, investments made for compliance and stay-in-business purposes were written off at cash generating units previously devaluated in the Refining & Marketing business. Finally, impairment losses were recorded at the Group power plants in the G&P segment due to a weak margins scenario; (ii) net charges in the Gas & Power segment due to an estimate revision of revenues accrued on the sale of natural gas (€346 million) and electricity (€138 million) to retail customers and the establishment of a provision for these revenues (€130 million for gas sale and €96 million for electricity); (iii) the effects of the fair-value evaluation of

certain commodity derivatives lacking the formal criteria to be accounted as hedges under IFRS (charge of €164 million); (iv) environmental provisions (€204 million) and provisions for redundancy incentives (€27 million).

Non-operating special items mainly related to income taxes related to the tax effects of special gains/charges in operating profit, the write-off of certain deferred tax assets (€851 million) due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutory tax rate. In addition, similar adjustments to deferred tax assets were recognized outside Italy at E&P subsidiaries (€860 million). These charges were partly offset by the reversal of deferred taxation due to changes in the United Kingdom tax law.

The breakdown of the adjusted net profit from continuing operations is shown in the table below:

2013	(€ million)	2014	2015	Change	% Ch.
5,950	Exploration & Production	4,423	752	(3,671)	(83.0)
(239)	Gas & Power	86	(168)	(254)
(246)	Refining & Marketing	(41)	282	323
(689)	Corporate and other activities	(852)	(663)	189	22.2
(1,854)	Impact of unrealized intragroup profit elimination(a)	(873)	(296)	577
2,922	Adjusted net profit (loss) - continuing operations	2,743	(93)	(2,836)
	attributable to:
423	- non-controlling interest	543	605	62	11.4
2,499	- Eni's shareholders	2,200	(698)	(2,898)

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

The Exploration & Production segment reported an adjusted operating profit of €4,108 million, down by €7,443 million or 64.4% y-o-y. This change was driven by lower oil and gas realizations in dollar terms (down by 47.8% and 33.8%, respectively), reflecting the lower price for the marker

Brent (down by 47%) and lower gas prices in Europe and in the United States. The price effect was only partially offset by a favorable exchange rate environment, higher production volumes, opex efficiencies and lower exploration expenses.

Adjusted net profit amounted to €752 million, decreasing by €3,671 million or 83% from 2014, due to lower operating performance and an increased adjusted tax rate (81.5%) due to: (i) the recognition of a major part of the positive pre-tax results in PSAs contracts which, although more resilient in a low-price environment nonetheless, bear higher-thanaverage rates of tax; ii) a higher incidence of non-deductible expenses on the pre-tax profit that has been lowered by the scenario.

Excluding the impact of the higher incidence on pre-tax profit of certain non-deductible expenses, because this incidence is expected to prospectively come down due to the effect of lower amortization charges going forward as a result of the impairment losses recorded in 2015 driven by the price outlook, and also restating the Group operating profit in accordance with the successful-effort-method accounting of exploration expenses, net of impaired exploration projects, the E&P tax rate has been re-determined in 70% and 60% for 2015 and 2014, respectively. In 2015, taxes paid represent approximately 34% of cash flow by operating activities of the E&P segment before changes in working capital and income taxes paid, slightly lower than in 2014.

The Gas & Power segment reported an adjusted operating loss of €126 million, down by €294 million from an adjusted operating profit of €168 million in 2014. The change reflected the one off economic benefits associated to certain contracts renegotiation recorded in the fourth quarter of 2014 as well as the negative outcome of a commercial arbitration in the fourth quarter of 2015. The Gas & Power segment reported an adjusted net loss of €168 million in the full year 2015, down by €254 million compared to the €86 million profit reported in the same period of a year ago due to the weaker operating performance and lower results of equity-accounted entities.

The Refining & Marketing segment reported an adjusted operating profit of €387 million, up by €452 million from the adjusted net loss of €65 million reported in 2014. This strong performance was driven by an improved refining margin scenario and efficiency and optimization gains, which helped lower margin to around \$5 per barrel, anticipating the EBIT break-even of the refining business to 2015 versus an original guidance for the year 2017 indicated in the 2015-2018 strategic plan.

Capital expenditure

2013	(€ million)	2014	2015	Change	% Ch.
10,475	Exploration & Production	10,524	10,234	(290)	(2.8)
109	- acquisition of proved and unproved properties
1,669	- exploration	1,398	820
8,580	- development	9,021	9,341
117	- other expenditure	105	73
229	Gas & Power	172	154	(18)	(10.5)
672	Refining & Marketing	537	408	(129)	(24.0)
211	Corporate and other activities	113	64	(49)
(3)	Impact of unrealized intragroup profit elimination	(82)	(85)	(3)
11,584	Capital expenditure - continuing operations	11,264	10,775	(489)	(4.3)
1,216	Capital expenditure - discontinued operations	976	781	(195)	(20.0)
12,800	Capital expenditure	12,240	11,556	(684)	(5.6)

In 2015, capital expenditure of continuing operations amounted to €10,775 million (€11,264 million in 2014) and

mainly related to:

• development activities deployed mainly in Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia, Italy and the United States and exploratory activities of which 97% was spent outside Italy, primarily in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia;

• refining activity (€282 million) with projects designed to improve the conversion rate and flexibility of refineries, as well as the upgrade of the refined product retail network (€126 million);

• initiatives to improve flexibility of the combined cycle power plants (€69 million).

Sources and uses of cash

The Company's cash requirements for capital expenditures, buy-back program, dividends to shareholders, and working capital were financed by a combination of funds generated from operations, borrowings and divestments.

In 2015, net cash provided by operating activities from continuing operations amounted to €12,189 million and was impacted by the eliminations of intercompany flows with discontinued operations. Proceeds from disposals were €2,258 million and mainly related to an interest in Snam due to exercise of the conversion right by bondholders (€911 million), an interest in Galp (€658 million) and the divestment of non-strategic assets mainly in the Exploration & Production business. These inflows funded part of capital expenditure (€10,775 million), other changes relating to capital expenditure and the payment of Eni's dividend (balance dividend for fiscal 2014 and the 2015 interim dividend totaling €3,457 million).

When considering the cash flow of discontinued operations, the Group's net debt increased by €3,178 million to €16,863 million, net of negative exchange rate differences and the reclassification of Saipem net cash in the discontinued operations.

Net cash provided by operating activities from continuing operations on a standalone basis was €12,189 million for 2015 and it fully funded capital expenditure. The Group cash flow performance was excellent (down by 15% from 2014) in spite of sharply lower oil prices. This result was driven by optimization initiatives in working capital performed mainly in the G&P segment, with the substantial recovery of prepaid gas volumes and other renegotiation benefits, and in the R&M segment as well as in corporate activities. Non-recurring effects of the working capital positively influenced cash flow by approximately €2.2 billion.

Profit and loss account

2013	(€ million)	2014	2015	Change	% Ch.
98,547	Net sales from operations	93,187	67,740	(25,447)	(27.3)
1,117	Other income and revenues	1,039	1,205	166	16.0
(80,765)	Operating expenses	(76,639)	(56,761)	19,878	25.9
(71)	Other operating income (expense)	145	(485)	(630)
(10,961)	Depreciation, depletion, amortization and impairments	(10,147)	(14,480)	(4,333)	(42.7)
7,867	Operating profit (loss)	7,585	(2,781)	(10,366)
(999)	Finance income (expense)	(1,181)	(1,323)	(142)	(12.0)
6,083	Net income from investments	469	124	(345)	(73.6)
12,951	Profit (loss) before income taxes	6,873	(3,980)	(10,853)
(9,055)	Income taxes	(6,681)	(3,147)	3,534	52.9
69.9	Tax rate (%)	97.2
3,896	Net profit (loss) - continuing operations	192	(7,127)	(7,319)
1,063	Net profit (loss) - discontinued operations	658	(2,251)	(2,909)
4,959	Net profit (loss)	850	(9,378)	(10,228)
	attributable to:
5,160	Eni's shareholders	1,291	(8,783)	(10,074)
3,472	- continuing operations	101	(7,680)	(7,781)
1,688	- discontinued operations	1,190	(1,103)	(2,293)
(201)	Non-controlling interest	(441)	(595)	(154)	34.9
424	- continuing operations	91	553	462
(625)	- discontinued operations	(532)	(1,148)	(616)

Non-GAAP measures

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

2015										Discontinued operations
(€ million)	Exploration & Production	Gas & Power	Refining & Marketing	Corporate and other activities	Engineering & Construction	Chemicals(a)	intragroup profit elimination Impact of unrealized	GROUP	Engineering & Construction and Chemicals	Consolidation adjustments	Total	CONTINUING OPERATIONS	company transactions vs. Discontinued operations Reinstatement of inter	CONTINUING OPERATIONS - on a standalone basis
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
- net 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				102.7		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 interest.

2014										Discontinued operations
(€ million)	Exploration & Production	Gas & Power	Refining & Marketing	Corporate and other activities	Engineering & Construction	Chemicals(a)	intragroup profit elimination Impact of unrealized	GROUP	Engineering & Construction and Chemicals	Consolidation adjustments	Total	CONTINUING OPERATIONS	company transactions vs. Discontinued operations Reinstatement of inter	CONTINUING OPERATIONS - on a standalone basis
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
- net 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.

2013										Discontinued operations
(€ million)	Exploration & Production	Gas & Power	Refining & Marketing	Corporate and other activities	Engineering & Construction	Chemicals(a)	intragroup profit elimination Impact of unrealized	GROUP	Engineering & Construction and Chemicals	Consolidation adjustments	Total	CONTINUING OPERATIONS	company transactions vs. Discontinued operations Reinstatement of inter	CONTINUING OPERATIONS - on a standalone basis
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
- net 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.

2013	(€ million)	2014	2015	Change
11,026	Net cash provided by operating activities	15,110	11,903	(3,207)
1,894	Net cash provided by operating activities - discontinued operations	1,948	722	(1,226)
9,132	Net cash provided by operating activities - continuing operations	13,162	11,181	(1,981)
1,686	Reinstatement of intercompany transactions vs. discontinued operations	1,225	1,008
10,818	Net cash provided by operating activities on a standalone basis	14,387	12,189	(2,198)

Breakdown of special items including discontinued operations

2013	(€ million)	2014	2015
3,046	Special items of operating profit (loss)	2,197	7,740
205	- environmental charges	179	225
2,400	- assets impairments	1,531	6,792
(187)	- net gains on disposal of assets	(28)	(417)
334	- risk provisions	(10)	211
270	- provision for redundancy incentives	9	42
315	- commodity derivatives	(16)	164
(195)	- exchange rate differences and derivatives	229	(63)
(96)	- other	303	786
179	Net finance (income) expense	203	282
	of which:
195	- exchange rate differences and derivatives	(229)	63
(5,299)	Net income (expense) from investments	(189)	471
	of which:
(3,599)	- gains on disposal of assets	(159)	(33)
(1,682)	- impairments / revaluation of equity investments	(38)	489
901	Income taxes	(270)	297
	of which:
954	- impairment of deferred tax assets of Italian subsidiaries	976	851
	- other net tax refund	(824)
490	- deferred tax adjustment on PSAs	69
	- impairment of deferred tax assets of upstream business		860
(543)	- taxes on special items of operating profit (loss) and other special items	(491)	(1,414)
(1,173)	Total special items of net profit (loss)	1,941	8,790
	Attributable to:
(5)	- non-controlling interest	533	353
(1,168)	- Eni's shareholders	1,408	8,437
	of which:
96	Total special items of discontinued operations	199	2,016
	impairment due to fair value evaluation		1,969
	financial derivative on the disposal of 12.503% interest in Saipem		49
96	other net special items	199	(2)

Summarized Group balance sheet

The summarized Group balance sheet aggregates the amount of assets and liabilities derived from the statutory balance sheet in accordance with functional criteria which consider the enterprise conventionally divided into the three fundamental areas focusing on resource investments, operations and financing. Management believes that this summarized group balance sheet is useful

information in assisting investors to assess Eni's capital structure and to analyze its sources of funds and investments in fixed assets and working capital. Management uses the summarized group balance sheet to calculate key ratios such as the proportion of net borrowings to shareholders' equity (leverage) intended to evaluate whether Eni's financing structure is sound and well-balanced.

(€ million)	December 31, 2014	December 31, 2015	Change
Fixed assets
Property, plant and equipment	71,962	63,795	(8,167)
Inventories - Compulsory stock	1,581	909	(672)
Intangible assets	3,645	2,433	(1,212)
Equity-accounted investments and other investments	5,130	3,263	(1,867)
Receivables and securities held for operating purposes	1,861	2,026	165
Net payables related to capital expenditure	(1,971)	(1,276)	695
	82,208	71,150	(11,058)
Net working capital
Inventories	7,555	3,910	(3,645)
Trade receivables	19,709	12,022	(7,687)
Trade payables	(15,015)	(9,345)	5,670
Tax payables and provisions for net deferred tax liabilities	(1,865)	(3,133)	(1,268)
Provisions	(15,898)	(15,266)	632
Other current assets and liabilities	222	1,804	1,582
	(5,292)	(10,008)	(4,716)
Provisions for employee post-retirement benefits	(1,313)	(1,056)	257
Discontinued operations and assets held for sale including related liabilities	291	10,446	10,155
CAPITAL EMPLOYED, NET	75,894	70,532	(5,362)
Eni shareholders' equity	59,754	51,753	(8,001)
Non-controlling interest	2,455	1,916	(539)
Shareholders' equity	62,209	53,669	(8,540)
Net borrowings	13,685	16,863	3,178
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	75,894	70,532	(5,362)

The summarized Group balance sheet was affected by a sharp movement in the EUR/USD exchange rate which determined an increase in net capital employed, net borrowings and total equity by €4,670 million, €136 million and €4,534 million respectively. This was due to translation into euros of the financial statements of US-denominated subsidiaries reflecting a 10.3% appreciation of the US dollar against the euro (1 EUR= 1.089 USD at December 31, 2015 compared to 1.214 at December 31, 2014).

Fixed assets (€71,150 million) decreased by €11,058 million from December 31, 2014 mainly due to the reclassification of the tangible and intangible assets of Saipem and Versalis as discontinued operations. Other changes related to impairment losses and DD&A at continuing operations (€14,480 million), which were partly offset by currency movements and capital expenditure (€10,775 million). The reduction in the line item "Equity-accounted investments and other investments" was due to the divestment of Eni's interest in Snam and Galp.

Net working capital was in negative territory at minus €10,008 million and decreased by €4,716 million year-on-year. This mainly reflected the mentioned reclassification of the disposal groups Saipem and Versalis as discontinued operations. In addition, the G&P segment reduced its working capital, while the carrying amount of oil and gas inventories declined due to the impact of lower prices on the weighted-average cost accounting method as well as the destocking of products and gas inventories as part of ongoing optimization measures. These decreases were partly offset by the increased balance of other current assets and liabilities. This was due to increased working capital exposure to joint venture partners in E&P. This latter increase was partly offset by the reversal of the deferred costs related to pre-paid gas volumes in previous reporting periods in the G&P segment following the off-taken of the underlying gas; while an opposite trend was recorded due to our long-term buyers off-taking Eni's gas. Finally, the change in the balance of tax payables and provisions for deferred taxes (up by €1,268 million) reflected the write-off of Italian deferred tax assets

(€885 million) due to projections of lower future taxable profit at Italian subsidiaries as well as deferred tax assets of subsidiaries located outside Italy of the upstream segment (€1,058 million) and the reimbursement/transferring to financing institutions of taxes receivables in Italy (approximately €900 million).

Discontinued operations and assets held for sale including

related liabilities (€10,446 million) comprised: i) Saipem and its subsidiaries considering the arrangements signed on October 2015 with the Fondo Strategico Italiano (FSI). These include the sale of a 12.503% stake of the share capital of Saipem to FSI and a concurrent shareholder agreement with Eni intended to establish joint control over the target entity; ii) the chemical operating segment. As of the reporting date, negotiations were underway to define an agreement with an industrial partner who, by acquiring a controlling stake of Versalis, would support Eni in implementing

the industrial plan designed to upgrade this segment. In addition, the book value of goodwill and of the non-current assets of the two disposal groups have been aligned to the fair value of the underlying net assets. This item also includes non-strategic assets in the Refining & Marketing and Gas & Power businesses.

Shareholders' equity including non-controlling interest was

€53,669 million, representing a decrease of €8,540 million from December 31, 2014. This was due to net loss in comprehensive income for the year (€5,032 million) given by net loss of €9,378 million partly offset by positive foreign currency translation differences (€4,534 million). Also affecting the total equity was dividend distribution and other changes of €3,478 million (€3,457 million being the 2014 final dividend and the interim dividend for 2015 paid to Eni's shareholders and dividends to other noncontrolling interests).

Net borrowings and leverage

Eni evaluates its financial condition by reference to net borrowings, which is calculated as total finance debt less: cash, cash equivalents and certain very liquid investments not related to operations, including among others non operating financing receivables and securities not related to operations. Non-operating financing receivables consist of amounts due to Eni's financing subsidiaries from banks and other financing institutions and amounts due to other subsidiaries from banks for investing purposes and deposits in escrow. Securities not related to operations consist primarily of government and corporate securities.

Leverage is a measure used by management to assess the Company's level of indebtedness. It is calculated as a ratio of net borrowings which is calculated by excluding cash and cash equivalents and certain very liquid assets from financial debt to shareholders' equity, including non-controlling interest. Management periodically reviews leverage in order to assess the soundness and efficiency of the Group balance sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards.

	December 31,	December 31,
(€ million)	2014	2015	Change
Total debt:	25,891	27,776	1,885
Short-term debt	6,575	8,383	1,808
Long-term debt	19,316	19,393	77
Cash and cash equivalents	(6,614)	(5,200)	1,414
Securities held for trading and other securities held for non-operating purposes	(5,037)	(5,028)	9
Financing receivables for non-operating purposes	(555)	(685)	(130)
Net borrowings	13,685	16,863	3,178
Shareholders' equity including non-controlling interest	62,209	53,669	(8,540)
Leverage	0.22	0.31	0.09

Summarized Group cash flow statement and change in net borrowings

Eni's summarized Group cash flow statement derives from the statutory statement of cash flows. It enables investors to understand the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. The measure enabling such a link is represented by the free cash flow which is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows

relating to financing debts/receivables (issuance/repayment of debt and receivables related to financing activities), shareholders' equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; and (ii) change in net borrowings for the period by adding/deducting cash flows relating to shareholders' equity and the effect of changes in consolidation and of exchange rate differences. The free cash flow and net cash provided by operating activities from continuing operations on a standalone basis are non-GAAP measures of financial performance.

2013	(€ million)	2014	2015	Change
3,896	Net profit (loss) - continuing operations	192	(7,127)	(7,319)
	Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
8,917	- depreciation, depletion and amortization and other non monetary items	10,919	15,521	4,602
(3,877)	- net gains on disposal of assets	(99)	(559)	(460)
9,203	- dividends, interests, taxes and other changes	6,822	3,259	(3,563)
121	Changes in working capital related to operations	2,148	4,450	2,302
(9,128)	Dividends received, taxes paid, interests (paid) received during the period	(6,820)	(4,363)	2,457
9,132	Net cash provided by operating activities - continuing operations	13,162	11,181	(1,981)
1,894	Net cash provided by operating activities - discontinued operations	1,948	722	(1,226)
11,026	Net cash provided by operating activities	15,110	11,903	(3,207)
(11,584)	Capital expenditure - continuing operations	(11,264)	(10,775)	489
(1,216)	Capital expenditure - discontinued operations	(976)	(781)	195
(12,800)	Capital expenditure	(12,240)	(11,556)	684
(317)	Investments and purchase of consolidated subsidiaries and businesses	(408)	(228)	180
6,360	Disposals	3,684	2,258	(1,426)
(243)	Other cash flow related to capital expenditure, investments and disposals	435	(1,351)	(1,786)
4,026	Free cash flow	6,581	1,026	(5,555)
(3,981)	Borrowings (repayment) of debt related to financing activities	(414)	(300)	114
1,715	Changes in short and long-term financial debt	(628)	2,126	2,754
(4,225)	Dividends paid and changes in non-controlling interests and reserves	(4,434)	(3,477)	957
(40)	Effect of changes in consolidation, exchange differences and cash and cash equivalent related to discontinued operations	78	(789)	(867)
(2,505)	NET CASH FLOW FOR THE PERIOD	1,183	(1,414)	(2,597)
10,818	Net cash provided by operating activities on standalone basis	14,387	12,189	(2,198)

Change in net borrowings

2013	(€ million)	2014	2015	Change
4,026	Free cash flow	6,581	1,026	(5,555)
(21)	Net borrowings of acquired companies	(19)		19
(23)	Net borrowings of divested companies		83	83
349	Exchange differences on net borrowings and other changes	(850)	(810)	40
(4,225)	Dividends paid and changes in non-controlling interest and reserves	(4,434)	(3,477)	957
106	CHANGE IN NET BORROWINGS	1,278	(3,178)	(4,456)

The risks described below may have a material effect on our operational and financial performance. We invite our investors to consider these risks carefully.

Eni's operating results and cash flow and future rate of growth are exposed to the effects of fluctuating prices of crude oil, natural gas and oil products

Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni's control. These factors include among other things:

• global and regional dynamics of oil and gas supply and demand. The price of crude oil has been on a downtrend since the second half of 2014 with oil prices falling from the level of approximately 110 \$/bbl (where "bbl" means barrel) by mid-year, down to multi-year lows below the 30-dollar mark in January 2016. For the full year 2015, the benchmark Brent crude oil price averaged 53 \$/bbl with a reduction of approximately 50% year-on-year. This decline was driven by structural imbalances in the global oil market on the back of continued oversupplies fuelled by production growth in both Organization of the Petroleum Exporting Countries ("OPEC") and non-OPEC countries, as well as uncertainties about the pace of macroeconomic growth. However, according to our records, demand for fuels held remarkably well in 2015, posting one of the best increase of the latest years, which was spurred by price elasticity and other factors. Looking forward, we believe that there are risks of further price erosion in 2016, as witnessed by trends in crude oil prices in the first months of the year, reflecting continued oversupplies, increased risks of a slowdown in global economic activity, a rise in global stockpiles of crude oil and the return of Iran's oil to the global market as sanctions are being lifted following its nuclear agreement with Western countries. Furthermore, uncertainties exist among market participants about the long-term prospects of the global energy demand also considering the growing political and institutional focus on energy conservation and reduction in Greenhouse Gas ("GHG") emissions;
• global political developments, including sanctions imposed on certain producing countries and conflict situations;
• global economic and financial market conditions;
• the influence of OPEC over world supply and therefore oil prices;
• prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables);
• weather conditions;
• operational issues;
• governmental regulations and actions;
• success in development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption; and
• the effect of worldwide energy conservation and environmental protection efforts.

All these factors can affect the global balance between demand and supply for oil and prices of oil.

Management believes that a gradual absorption of the supply glut in the medium to long-term may occur, as a result of reduced investments by international oil companies, possible oil-producing countries' agreements to curb output, a reduction in OPEC's spare capacity and the probable forcing of less efficient players, such as the operators in the U.S. tight oil production which we believe to have a cost structure no longer sustainable under the current scenario, out of the market. However, management has evaluated a number of risks and uncertainties inherent in such expectations, including structural changes that have been affecting oil industry – e.g. the increase in oil supply following U.S. tight oil revolution – reduced impact of geopolitical crises and the greater role played by renewable energy sources, as well as risks associated with internationally-agreed measures intended to reduce greenhouse gas emissions. Based on this outlook, Eni's management has revised downwards its pricing assumptions of the Brent crude oil marker utilized in each of the periods of the Company's 2016-2019 strategic plan, in particular the long-term reference price has been reduced to 65 \$/bbl, down from the 90-dollar scenario utilized in the previous planning assumptions and in evaluating recoverability of the carrying amounts of our oil&gas assets.

Price fluctuations have had in 2015 and may continue to have a material adverse effect on the Group's results of operations and cash flow. Lower oil prices from one year to another negatively affect the Group's consolidated results of operations and cash flow, because revenues are price sensitive; such current prices are reflected in revenues recognized in the Exploration & Production segment at the time of the price change, whereas expenses in this segment are either fixed or less sensitive to changes in crude oil prices than revenues. Eni estimates that its consolidated net profit and cash flow vary by approximately €0.2 billion for each onedollar change in the price of the Brent crude oil benchmark with respect to the price scenario assumed in Eni's financial projections for 2016 at 40 \$/bbl. Free cash flow is expected to reduce/increase by a corresponding amount.

In addition to the adverse effect on revenues, profitability and cash flow, lower oil and gas prices could result in the debooking of proved reserves, if they become economically unfavorable in this type of environment, and asset impairments. In 2015, we debooked 84 million BOE of proved reserves because decreases in commodity prices shortened the economic lives of certain producing properties and caused certain development projects to become economically unfavorable. In 2015, we recorded impairment losses at our oil&gas properties in the region of €5 billion (€3.5 billion post-tax) which were mainly driven by our revised outlook for commodity prices.

Depending on the significant and speed of a decrease in crude oil prices, Eni may also need to review investment decisions and the viability of development projects. Lower oil and gas prices over prolonged periods may also adversely affect Eni's results of operations and cash flow and hence the funds available to finance expansion projects, further reducing the Company's ability to grow future production and revenues. In addition, they may reduce returns at development projects, either planned or implemented, forcing the Company to reschedule, postpone or cancel development projects. We are currently planning a capital budget of approximately €37 billion in the next four years excluding expenditures associated with our planned disposals, which is significantly lower than our previous financial projections, down by 21% on constant exchange rate basis, to take into account the expected lower cash flow from operations under our reduced price outlook in the years 2016-2019. We are forecasting crude oil prices in the range of 40 to 65 \$/bbl in the next four years, which is significantly lower than our previous planning assumption of 55-90 \$/bbl. Finally, lower oil prices over prolonged periods may trigger a review of the future recoverability of the Company's carrying amounts of oil&gas properties, resulting in the recognition of significant further impairment charges. In response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions, lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating by rating agencies, including Standard & Poor's Ratings Services ("S&P") and Moody's Investor Services Inc ("Moody's"). These downgrades negatively affect our cost of capital, increase our financial expenses, and may limit our ability to access capital markets and execute aspects of our business plans.

Eni estimates that movements in oil prices affect approximately 50% of Eni's current production. The remaining portion of Eni's current production is insulated from crude oil price movements considering that the Company's property portfolio is characterized by a sizeable presence of production sharing contracts, where, due to the cost recovery mechanism, the Company is entitled to a larger number of barrels in case of a fall in crude oil prices. (See also the section on the specific risks of the Exploration & Production segment "Risks associated with the exploration and production of oil and natural gas" below).

Because of the above-mentioned risks, an extended continuation of the current commodity price environment, or further declines in commodity prices, will materially and adversely affect our business prospects, financial condition, results of operations, cash flows, liquidity, ability to finance planned capital expenditures and commitments and may impact shareholder returns, including dividends and the share price.

In gas markets, price volatility reflects the dynamics of demand and supply for natural gas. Over the latest years, in the face of weak demand dynamics in Europe due to the economic downturn and competition from coal and renewable sources in the production of gas-fired power, gas supplies in Europe have continued to rise. Factors underlying this rise comprise the increased availability of liquefied natural gas ("LNG") on a global scale, which in the future will be fuelled by an expected growth in LNG exports from the U.S., and volumes of contracted supplies of European gas wholesalers under long-term arrangements with take-or-pay clauses. (See also the other trends described in the specific risk-factors section of Eni's Gas & Power business below). The increased liquidity of European hubs has put significant downward pressure on spot prices. Eni expects those trends to continue in the foreseeable future due to a weak outlook for gas demand and continued oversupplies. In case Eni fails to renegotiate its long-term gas supply contracts in order to make its gas competitive as market conditions evolve, its profitability and cash flow in the Gas & Power segment would be significantly affected by current downward trends in gas prices.

The Group's results from its Refining & Marketing business are primarily dependent upon the supply and demand for refined products and the associated margins on refined product sales, with the impact of changes in oil prices on results of these segments being dependent upon the speed at which the prices of products adjust to reflect movements in oil prices.

Competition

There is strong competition worldwide, both within the oil industry and with other industries, to supply energy to the industrial, commercial and residential energy markets Eni faces strong competition in each of its business segments. In the current uncertain financial and economic environment, Eni expects that prices of energy commodities, in particular oil and gas, will be very volatile, with average prices and margins influenced by changes in the global supply and demand for energy, as well as in the market dynamics. This is likely to increase competition in all of Eni's businesses, which may impact costs and margins. Competition affects license costs and product prices, with a consequent effect on Eni's margins and its market shares. Eni's ability to remain competitive requires continuous focus on technological innovation, reducing unit costs and improving efficiency. It also depends on Eni's ability to get an access to new investment opportunities, both in Europe and worldwide.

• In the Exploration & Production segment, Eni faces competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its relatively smaller size compared to other international oil companies, particularly when bidding for large scale or capital intensive projects, and may be exposed to industry-wide cost increases to a greater extent compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, as a result of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flow may be adversely affected.

• In the Gas & Power segment, Eni faces strong competition from gas and energy players to sell gas to the industrial segment, the thermoelectric sector and the retail customers both in the Italian market and in markets across Europe. Competition has been fuelled by ongoing weak trends in demand due to the downturn and macroeconomic uncertainties and continued oversupplies in the marketplace. These have been driven by rising production of LNG on global scale and inter-fuel competition. The use of gas in gas-fired power plants has registered a dramatic decline due to the replacement with coal reflecting cost advantages and a dramatic growth in the adoption of renewable sources of energy (photovoltaic and solar). The large-scale development of shale gas in the United States was another fundamental trend that aggravated the oversupply situation in Europe because many LNG projects that originally targeted the U.S. market ended to supply the already saturated European sector. The continuing growth in the production of shale gas in the United States increased global gas supplies. These market imbalances in Europe were exacerbated by the fact that throughout the last decade and up to a few years ago the market consensus projected that gas demand in the continent would grow steadily until 2020 and beyond driven by economic growth and the increased adoption of gas in firing power production. European gas wholesalers including Eni committed to purchasing large amounts of gas under long-term supply contracts with so-called "take-or-pay" clauses from the main producing countries bordering Europe (namely Russia and Algeria). They also made significant capital expenditures to upgrade existing pipelines and to build new infrastructures in order to expand gas import capacity to continental markets. Long-term gas supply contracts with take-or-pay clauses expose gas wholesalers to a volume risk, as they are contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the underlying price. Due to the trends described above of the prolonged economic downturn and inter-fuel competition, the projected increases in gas demand failed to materialize, resulting in a situation of oversupply and pricing pressure. As demand contracted across Europe, gas supplies increased, thus driving the development of very liquid continental hubs to trade spot gas. Spot prices at continental hubs have become the main benchmarks to which selling prices are indexed across all end-markets, including large industrial customers, thermoelectric utilities and the retail segment. The profitability of gas operators was negatively impacted by falling sales prices at those hubs, where prices have been pressured by intense competition among gas operators in the face of weak demand, oversupplies and the constraint to dispose of minimum annual volumes of gas to be purchased under longterm supply contracts. Eni does not expect any meaningful improvement in the European gas sector for the foreseeable future. Gas demand will remain weak due to macroeconomic uncertainties and unclear EU policies regarding how to satisfy energy demand in Europe and the energy mix. Additionally, supplies at continental hubs will continue to build given the expected ramp-up of LNG exports from the

United States due to steady growth in gas production and ongoing projects to reconvert LNG regasification facilities into liquefaction export units and the start of several LNG projects in the Pacific region and elsewhere. Eni believes that these ongoing negative trends may adversely affect the Company's future results of operations and cash flows, also taking into account the Company's contractual obligations to off-take minimum annual volumes of gas in accordance to its long-term gas supply contracts with take-or-pay clauses.

• In its Gas & Power segment, Eni is vertically integrated in the production of electricity via its gas-fired power plants which currently use the combined-cycle technology. In the electricity business, Eni competes with other producers and traders from Italy or outside Italy who sell electricity in the Italian market. Going forward, the Company expects continuing competition due to the projections of moderate economic growth in Italy and Europe over the foreseeable future, also causing outside players to place excess production on the Italian market. The economics of the gasfired electricity business have dramatically changed over the latest few years due to ongoing competitive trends. Spot prices of electricity in the wholesale market across Europe decreased due to excess supplies driven by the growing production of electricity from renewable sources, which also benefit from governmental subsidies, and a recovery in the production of coal-fired electricity which was helped by a substantial reduction in the price of this fuel on the back of a massive oversupply of coal which occurred on a global scale. As a result of falling electricity prices, margins on the production of gas-fired electricity went into negative territory. Eni believes that the profitability outlook in this business will remain weak in the foreseeable future.
• In the Refining & Marketing segment, Eni faces strong competition both in the industrial and in the commercial activities. Refining margins have been negatively impacted by declining demand due to growing energy efficiency and the economic downturn, as well as by growing competition from new large scale refineries in the Middle East, benefiting of low production costs. In 2015, refining margins rebounded as a consequence of falling oil price and a recovery in oil products demand. Looking forward, management believes that refining margins will remain under pressure. In 2016, Eni forecasts a lower refining margin than in 2015. In marketing Eni faces the challenges of a growing competition from no logo operators and large retailers, which leverage on the price awareness of the final consumers to increase their market share.

Safety, security, environmental and other operational risks

The Group engages in the exploration and production of oil and natural gas, processing, transportation, and refining of crude oil, transport of natural gas, storage and distribution of petroleum products. By their nature the Group's operations expose Eni to a wide range of significant health, safety, security and environmental risks. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni's activities. Eni's future results from operations and liquidity depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries.

In the Exploration & Production segment, Eni faces natural hazards and other operational risks including those relating to the physical characteristics of oil and natural gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and the security of Eni's personnel and risks of blowout, fire or explosion. Accidents at a single well can lead to loss of life, damage or destruction to properties, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operations, liquidity, reputation and prospects of the Group, including the share price and the dividends.

Eni's activities in the Refining & Marketing segment entails health, safety and environmental risks related to the handling, transformation and distribution of oil and oil products. These risks arise from the inherent characteristics of hydrocarbons, in particular flammability and toxicity. Also environmental risks are involved in the use of oil products, such as greenhouse gas emissions, soil and groundwater contaminations.

All of Eni's segments of operations involve, to varying degrees, the transportation of hydrocarbons. Risks in transportation activities depend both on the hazardous nature of the products transported, and on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road, gas distribution networks), the volumes involved and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people and the environment.

The Company invests significant resources in order to upgrade the methods and systems for safeguarding the safety and health of employees, contractors and communities, and the environment; to prevent risks; to comply with applicable laws and policies; and to respond to and learn from unexpected incidents. Eni seeks to minimize these operational risks by carefully designing and building facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and managing its operations in a safe, compliant and reliable manner. Failure to manage these risks could effectively result in unexpected incidents, including releases or oil spills, blowouts, fire, mechanical failures and other incidents resulting in personal injury, loss of life, environmental damage, legal liabilities and/or damage claims, destruction of crude oil or natural gas wells, as well as damage to equipment and other property, all of which could lead to a disruption in operations. Eni's operations are often conducted in difficult and/or environmentally sensitive locations such as the Gulf of Mexico, the Caspian Sea and the Arctic. In such locations, the consequences of any incident could be greater than in other locations. Eni also faces risks once production is discontinued, because Eni's activities require decommissioning of productive infrastructure and environmental site

remediation. Furthermore, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

Eni's insurance subsidiary provides insurance coverage to Eni's entities, generally up to \$1.1 billion in case of offshore incident and \$1.5 billion in case of incident at onshore facilities (refineries). In addition, the Company also maintains worldwide third-party liability insurance coverage for all of its subsidiaries. Management believes that its insurance coverage is in line with industry practice and sufficient to cover normal risks in its operations. However, the Company is not insured against all potential risks. In the event of a major environmental disaster such as the BP Deepwater Horizon, for example, Eni's third-party liability insurance would not provide any material coverage and thus the Company's liability would far exceed the maximum coverage provided by its insurance. The loss Eni could suffer in the event of such a disaster would depend on all the facts and circumstances of the event and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster.

The occurrence of the events mentioned above could have a material adverse impact on the Group's business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders' returns and damage the Group's reputation.

The Company cannot guarantee that it will not suffer any uninsured loss and there can be no guarantee, particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Company.

Risks associated with the exploration and production of oil and natural gas

The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production.

A description of the main risks facing the Company's business in the exploration and production of oil and gas is provided below.

Eni's oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2015, approximately 52%

of Eni's total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Italy, Angola, the Gulf of Mexico, Congo, United Kingdom and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore accidents and spills could have impacts also of catastrophic proportions on the ecosystem and health and security of people due to the objective difficulties in handling hydrocarbons containment, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Further, offshore operations are subject to marine risks, including storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations. Failure to manage these risks could result in injury or loss of life, damage to property, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to Eni's reputation and could have a material adverse effect on Eni's operations, results, liquidity, reputation, business prospects and the share price.

Exploratory drilling efforts may be unsuccessful Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells have margins of uncertainty, and drilling operations may be unsuccessful as a result of a large variety of factors, including geological play failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents, and shortages or delays in the delivery of equipment. The Company also engages in exploration drilling activities offshore, also in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea). In these locations, the Company generally experiences more challenging conditions and incurs higher exploration costs than onshore or in shallow waters. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni's future growth prospects, results of operations and liquidity. Because Eni plans to make investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. Some of these activities are high-risk projects that generally involve sizeable plays located in deep and ultra-deep waters or at higher depths where operations are more challenging and costly than in other areas. Furthermore, deep and ultra-deep water operations will require significant time before commercial production of discovered reserves can commence, increasing both the operational and financial risks associated with these activities. The Company plans to conduct exploration projects offshore West Africa (Angola, Nigeria, Congo, and Gabon), East Africa (Mozambique and South Africa), South-East Asia (Indonesia, Vietnam, Myanmar and other locations), Australia, the Norwegian Barents Sea, the Mediterranean and offshore Gulf of Mexico. In 2015, the Company spent €0.8 billion to conduct exploration projects and plans to spend approximately €0.9 billion on average in the next four-year plan on exploration activities. Unsuccessful

exploration activities and failure to discover additional commercial reserves could reduce future production of oil and natural gas, which is highly dependent on the rate of success of exploration projects.

Development projects bear significant operational risks, which may adversely affect actual returns

Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or environmentally sensitive locations. Eni's future results of operations and liquidity depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include:

• the outcome of negotiations with co-venturers, governments and state-owned companies, suppliers, customers or others, including, for example, Eni's ability to negotiate favorable long-term contracts to market gas reserves;
• commercial arrangements for pipelines and related equipment to transport and market hydrocarbons;
• timely issuance of permits and licenses by government agencies;
• the Company's relative size compared to its main competitors which may prevent it from participating in largescale projects or affect its ability to reap benefits associated with economies of scale, for example by obtaining more favorable contractual terms by suppliers of equipment and services;
• the ability to carefully carry out front-end engineering design so as to prevent the occurrence of technical inconvenience during the execution phase;
• timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where complex offshore units such as FPSO and platforms are built; these events may cause cost overruns and delays impacting the time-tomarket of the reserves;
• risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
• poor performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) – turn key contractual scheme. Eni believes this kind of risk may be due to lack of contractual flexibility, poor quality of front-end engineering design and commissioning delays;
• changes in operating conditions and cost overruns. In recent years, the industry has been adversely impacted by the growing complexity and scale of projects which drove cost increases and delays, including higher environmental and safety costs. Due to the recent downtrend in crude oil prices, the Company is seeking to renegotiate construction contracts, daily rates for rigs and other field services and costs for materials and other productive factors to preserve margins at its development projects. In case it fail to obtaining

the planned cost reductions, its profitability in the Exploration & Production segment could be adversely affected;

• the actual performance of the reservoir and natural field decline; and
• the ability and time necessary to build suitable transport infrastructures to export production to final markets.

Events such as the ones described above of poor project execution, inadequate front-end engineering design, delays in the achievement of critical events and project milestones, delays in the delivery of production facilities and other equipment by third parties, differences between scheduled and actual timing of the first oil, as well as cost overruns may adversely affect the economic returns of Eni's development projects. Failure to deliver major projects on time and on budget could negatively affect results of operations, cash flow and the achievement of short-term targets of production growth. Finally, development and marketing of hydrocarbons reserves typically require several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-leadtime projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from the prices and costs assumed when the investment decision was actually made, leading to lower rates of return. In addition, projects executed with partners and co-venturers reduce the ability of the Company to manage risks and costs, and Eni could have limited influence over and control of the operations and performance of its partners. Furthermore, Eni may not have full operation control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operation and strategic objectives due to the nature of its relationships. Finally, in case the Company is unable to develop and operate major projects as planned, particularly if the Company fails to accomplish budgeted costs and time schedules, it could incur significant impairment losses of capitalized costs associated with reduced future cash flows of those projects.

For example, we have incurred cost overruns and continuing delays in the achievement of first oil at the Kashagan offshore field in the Kazakh section of the Caspian Sea. The latest issue related to a pipeline for the transport of acid gas where a spillage occurred, forcing the Consortium to shut down production. The damaged pipeline needs to be replaced and activities are underway. Management believes that production will resume as early as in late 2016.

Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition Eni's results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. In addition to being a function of production, revisions and new discoveries, the Company's reserve replacement is also affected by the entitlement mechanism in its PSAs and similar contractual schemes. Pursuant to these contracts, Eni is entitled to a portion of a field's reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to estimate Eni's proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The opposite occurs in case of lower oil prices. Future oil and gas production is dependent on the Company's ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with national oil companies and other entities owners of known reserves and acquisitions. In a number of reserve-rich countries, national oil companies decide to develop portion of oil and gas reserves that remain to be developed. To the extent that national oil companies decide to develop those reserves without the participation of international oil companies or if the Company fails to establish partnership with national oil companies, Eni's ability to access or develop additional reserves will be limited.

An inability to replace produced reserves by finding, acquiring and developing additional reserves could adversely impact future production levels and growth prospects. If Eni is unsuccessful in meeting its long-term targets of production growth and reserve replacement, Eni's future total proved reserves and production will decline and this will negatively affect future results of operations, cash flow and business prospects.

Uncertainties in estimates of oil and natural gas reserves Several uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depend on a number of factors, assumptions and variables, among which the most important are the following:

• the quality of available geological, technical and economic data and their interpretation and judgment;
• projections regarding future rates of production and costs and timing of development expenditures;
• changes in the prevailing tax rules, other government regulations and contractual conditions;
• results of drilling, testing and the actual production performance of Eni's reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and
• changes in oil and natural gas prices which could affect the quantities of Eni's proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions.

Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company's production sharing agreements and similar contractual schemes. The prices used in calculating Eni's estimated proved reserves are, in accordance with the U.S. Securities and Exchange Commission (the "U.S. SEC") requirements,

calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ending December 31, 2015, average prices were based on 54 \$/bbl for the Brent crude oil which compared to a price reference of 101 \$/bbl in 2014. This decline in the price of crude oil triggered the downward revision of those reserves that have become uneconomic in this type of environment, amounting to approximately 84 mmboe.

Commodity prices declined significantly in the fourth quarter of 2015 and in the first quarter of 2016 and if such prices do not increase significantly, our future calculations of estimated proved reserves will be based on lower commodity prices which could result in our having to remove non-economic reserves from our proved reserves in future periods. This effect will be counterbalanced in full or in part by increased reserves corresponding to the additional volume entitlements under Eni's PSAs relating to cost oil: i.e. because of lower oil and gas prices, the reimbursement of expenditures incurred by the Company requires additional volumes of reserves.

Many of these factors, assumptions and variables involved in estimating proved reserves are subject to change over time, therefore impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves reported as of the end of the period covered by this filing could be significantly different from the quantities of oil and natural gas that will be ultimately recovered. Any downward revision in Eni's estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni's results of operations and financial condition.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced At December 31, 2015, approximately 42% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2015 includes estimates of total future development costs associated with our proved undeveloped reserves of approximately €38 billion (undiscounted). We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company's development plans to develop of those reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves.

Oil and gas activity are subject to high levels of income taxes The oil and gas industry is subject to the payment of royalties and income taxes, which tend to be higher than those payable in many other commercial activities. In addition, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of countries where the Company conducts its upstream operations. Because of these trends, management estimates that the tax rate applicable to the Company's oil and gas operations is materially higher than the Italian statutory tax rate for corporate profit, which currently stands at 27.5 per cent.

The effective tax rate of the Company's Exploration & Production segment for the fiscal year 2015 was estimated at approximately 80 per cent driven by: (i) the recognition of a major part of positive pre-tax results in PSA contracts, which, although more resilient in a low-price environment, nonetheless bear higher-than-average rates of tax; and (ii) a higher incidence of certain non-deductible expenses on the pre-tax profit that has been lowered by the scenario. Also this outsized tax rate was due to the fact that in certain jurisdictions we were unable to match before-tax losses with the recognition of deferred tax assets due to lack of expected future taxable profit against which those asset can be utilized. Looking forward management believes that the tax rate in this segment will continue being negatively affected by those factors due to the persistence of weak commodity prices.

Management believes that the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices, which could make it more difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will decrease in response to falling oil prices. Adverse changes in the tax rate applicable to the Group profit before income taxes in its oil and gas operations would have a negative impact on Eni's future results of operations and cash flows.

In the current uncertain financial and economic environment also due to falling oil prices, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, nationalization and expropriations.

Eni's results depend on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to Eni's operation.

The present value of future net revenues from Eni's proved reserves will not necessarily be the same as the current market value of Eni's estimated crude oil and natural gas reserves and, in particular, may be reduced due to the recent significant decline in commodity prices

Investors should not assume the present value of future net revenues from Eni's proved reserves is the current market value of Eni's estimated crude oil and natural gas reserves. In accordance with U.S. SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-

the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the U.S. SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:

• the actual prices Eni receives for sales of crude oil and natural gas;
• the actual cost and timing of development and production expenditures;
• the timing and amount of actual production; and
• changes in governmental regulations or taxation.

The timing of both Eni's production and its incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor Eni uses when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Eni's reserves or the crude oil and natural gas industry in general.

At December 31, 2015, the net present value of Eni's proved reserves totaled approximately €37.8 billion, calculated in accordance with the requirements of FASB Extractive Activities - Oil & Gas (Topic 932), significantly lower than in 2014 due to reduced commodity prices. The average price used to estimate Eni's proved reserves and the net present value at December 31, 2015, as calculated in accordance with U.S. SEC rules, was 54 \$/ bbl for the Brent crude oil that compares to 101 \$/bbl in 2014. Future prices may materially differ from those used in our yearend estimates. Commodity prices have decreased significantly in recent months. Holding all other factors constant, if commodity prices used in Eni's year-end reserve estimates were in line with the pricing environment existing in the first quarter of 2016, Eni's PV-10 at December 31, 2016 could decrease significantly.

Political considerations

A substantial portion of Eni's oil and gas reserves and gas supplies are located in countries outside the EU and the North America, mainly in Africa, Central Asia and Central-Southern America, where the socio-political framework and macroeconomic outlook is less stable than in the OECD countries. In those less stable countries, Eni is exposed to a wide range of risks and uncertainties which could materially impact the ability of the Company to conduct its operations in a safe, reliable and profitable manner.

As of December 31, 2015, approximately 81% of Eni's proved hydrocarbon reserves were located in such countries and 60% of Eni's supplies of natural gas came from outside OECD countries. Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions,

inflation levels, exchange rates and similar events in those non-OECD countries may negatively impair Eni's ability to continue operating in an economic way, either temporarily or permanently, and Eni's ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues:

• lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights;
• unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriations, nationalizations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from state-owned oil companies who are partnering Eni in a number of oil and gas projects and properties in the host countries where Eni conducts its upstream operations. These state-owned oil companies can change contractual terms and other conditions of oil and gas projects in order to obtain a larger share of profit from a given project, thereby reducing Eni's profit share. They can also render different interpretations of contractual clauses relating to the recovery of certain expenses incurred by the Company to produce hydrocarbons reserves in any given projects. As of the balance sheet date receivables for €773 million relating to cost recovery under certain petroleum contracts in a non-OECD country were the subject of an arbitration proceeding;
• restrictions on exploration, production, imports and exports;
• tax or royalty increases (including retroactive claims);
• political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar incidents. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of personnel or assets. They may force Eni to evacuate personnel for security reasons and to increase spending on security. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographic areas in which Eni operates;
• difficulties in finding qualified suppliers in critical operating environment; and
• complex process in granting authorizations or licenses affecting time-to-market of certain development projects. Areas where Eni operates, where the Company is particularly exposed to the political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Indonesia, Kazakhstan, Venezuela, Iraq and Russia. In addition, any possible reprisals because of military or other action, such as acts of terrorism in the United States or elsewhere, could have a material adverse effect on Eni's business, results of operations and financial condition. 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, negatively affecting Eni's results of operations and cash flow until the

situation began to stabilize. Although our production levels in Libya for the year 2015 returned to levels not seen from the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2015, Libya accounted for approximately 20% of the Group total hydrocarbons production for the year and going forward its contribution albeit slowing down will remain significant. 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 which could significantly and negatively affect our results of operations, cash flow, business prospects and shareholder value. Also Eni's activities in Nigeria have been impacted in recent years by continuing episodes of theft, acts of sabotage and other similar disruptions which have jeopardized the Company's ability to conduct operations in full security, particularly in the onshore area of the Niger Delta. Looking forward, Eni expects that those risks will continue to affect Eni's operations in those countries. Particularly, the uncertain geopolitical outlook in Libya and unsafe operational conditions onshore Nigeria were factored up to a certain extent in the Company's projections of future production levels in these two countries.

In the current depressed environment for crude oil prices, the financial outlook of certain countries where Eni's hydrocarbons reserves are located has significantly deteriorated due to lower proceeds from the exploitation of hydrocarbons resources. This trend has increased the risk of sovereign default, which may cause political and macroeconomic instability and trigger one or more of the above-mentioned risks factors. State-owned petroleum companies of those countries are exposed to a liquidity risk too. Eni is partnering those national oil companies in executing certain oil&gas development projects. A possible sovereign default might jeopardize the financial feasibility of ongoing projects or increase the financial exposure of Eni, which is contractually obligated to finance the share of development expenditures of the first party in case of a financial shortfall of the latter. This risk is mitigated by the customary default clause, which states that in case of a default, the nondefaulting party is entitled to compensate its claims with the share of production of the defaulting party.

In Egypt, we have experienced continued difficulties in collecting overdue trading receivables for the supply of our share of oil and gas production to local oil and gas companies. As of December 31, 2015, Eni owned a significant amount of trade receivables due (€771 million) in respect of supplies of its oil and gas entitlements to local companies. Management is currently addressing the recoverability of the Company's trade receivables vs. Egyptian counterparties leveraging various initiatives and commercial agreements. Eni has not experienced any disruptions in its producing activities in the Country to date.

Eni closely monitors political, social and economic risks of approximately 60 countries in which has invested or intends to invest, in order to evaluate the economic and financial return of certain projects and to selectively evaluate projects. While the occurrence of those events is unpredictable, it is likely that the occurrence of any such events could adversely affect Eni's results from operations, cash flow and business prospects.

An escalation of the political crisis in Russia and Ukraine could affect Eni's business in particular and the global energy supply generally

Eni is closely monitoring developments to the political situation in Russia, Ukraine and the Crimea Region and is adapting its business activities to the sanctions adopted by the relevant authorities in Europe and the U.S. targeting the financial sector and the energy sector in Russia in view of Russia's actions intended to destabilize the political framework in Ukraine. Eni will adapt to any further related regulations and/or economic sanctions that could be adopted by the authorities. The EU enacted Regulation No. 833/2014, which is restricting, inter alia, the supply of certain oil and gas items to Russia and certain forms of financing related to the oil and gas sector in Russia.

Approximately 30% of Eni's natural gas is supplied by Russia and Eni is currently partnering the Russian company Rosneft in executing exploration activities in the Russian sections of the Barents Sea and the Black Sea. Contracts pertaining to the above-mentioned exploration licenses were entered into before enactment of the restrictive measures and have been put on hold since then. Eni started the required authorization procedure before the relevant EU Member States' Authorities who granted the Company certain authorizations that are valid throughout the whole European Union. However, given the uncertainty surrounding this matter, Eni cannot exclude major delays in certain ongoing or planned oil&gas projects in Russia.

It is possible that wider sanctions covering the Russian energy, banking and/or finance industries may be implemented, which may be targeted at specific individuals or companies or more generally. Further sanctions imposed on Russia, Russian individuals or Russian companies by the international community, such as sanctions enacting restrictions on purchases of Russian gas by European companies or restricting dealings with Russian counterparties could adversely impact Eni's business, results of operations and cash flow. In addition, an escalation of the crisis and of imposed sanctions could result in a significant disruption of energy supply and trade flows globally, which could have a material adverse effect on the Group's business, financial conditions, results of operations and future prospects.

Risks in the Company Gas & Power business

We expect a weak trading environment in our Gas & Power segment, which will negatively affect the profitability outlook in this business

Eni anticipates a number of risk factors to the profitability outlook of the Company's gas marketing business over the four-year planning period. Those include weak demand growth due to macroeconomic uncertainties, muted thermoelectric consumption, continuing oversupplies and strong competition. Eni believes that those trends will

negatively affect the gas marketing business future results of operations and cash flows by reducing gas selling prices and margins. Our financial outlook has factored in the rigidities of the Company's long-term supply contracts with take-or-pay clauses, where the Company is obligated to offtake a contractually set minimum volume of gas supplies or, in case of failure, to pay the contractual price (see below).

The main source of risk is concerning Eni's wholesale business which results are exposed to the volatility of the spreads between spot prices at European hubs and Italian spot prices because our supply costs are mainly indexed to spot prices at European hubs, whereas a large part of our selling volumes are indexed to Italian spot prices.

Against this backdrop, Eni's management will continue to execute its strategy of renegotiating the Company's long-term gas supply contracts in order to align pricing and volume terms to current market conditions as they evolve. The revision clauses provided by these contracts states the right of each counterparty to renegotiate the economic terms and other contractual conditions periodically, in relation to ongoing changes in the gas scenario. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will be ultimately achieved and the timing of recognition in profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, the claiming party has faculty to open an arbitration procedure to obtain revised contractual conditions. This would add to the level of uncertainty surrounding the outcome and timing of those renegotiations. In 2015, the results of operations in the Gas & Power segment were negatively affected by a delay in the settlement of an arbitration procedure with a long-term supplier, which management had budgeted to recognize in that year, owing to the complexity of the matter. These considerations also apply to ongoing renegotiations with our long-term buyers. In 2015, the performance of our Gas & Power business was negatively affected by the unfavorable outcome of an arbitration procedure with one of our long-term buyer, where the amount of the discount on the price of gas awarded to the claimant was higher than our initial provision. Based on these risk factors, we believe that future results of the Gas Marketing activities are subject to increasing volatility and unpredictability.

Current, negative trends in gas demands and supplies may impair the Company's ability to fulfill its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts In order to secure long-term access to gas availability, particularly with a view of supplying the Italian gas market and anticipating certain trends in gas demand which actually failed to materialize, Eni has signed a number of long-term gas supply contracts with national operators of certain key producing countries, which include Russia, Algeria, Libya, Norway and the Netherlands, where most of European gas supplies are sourced from.

These contracts have a residual life of approximately 12 years. These contracts include take-or-pay clauses whereby the Company is required to off-take minimum, pre-set volumes of gas in each year of the contractual term or, in case of failure, to pay the whole price, or a fraction of that price, up to the minimum contractual quantity. The take-or-pay clause entitles the Company to off-take pre-paid volumes of gas in later years. Amounts of cash pre-payments and time schedules for off-taking pre-paid gas vary from contract to contract. Generally, cash pre-payments are calculated on the basis of the energy prices current in the year when the Company is scheduled to purchase the gas, with the balance due in the year when the gas is actually purchased.

The right to off-take pre-paid gas expires within a ten-year term in some contracts or remains in place until contract expiration in other arrangements. In addition, the right to off-take the prepaid gas can be exercised in future years if the Company fulfills its minimum take obligation in a given year and within the limit of the maximum annual quantity. Similar considerations apply to ship-or-pay contractual obligations.

Looking forward, management believes that the current market outlook which will be driven by a weak recovery in gas demand, continued oversupplies and strong competitive pressures as well as any possible change in sector-specific regulation represents a risk factor to the Company's ability to fulfill its minimum take obligations associated with its long-term supply contracts. Adding to this risk, the Company is currently forecasting sales volumes to remain flat or to decrease slightly in 2016 and in the subsequent years compared to 2015.

Furthermore, the above-mentioned take-or-pay clause exposes the Company to a price risk because the cost of gas that the Company recognizes at the incurrence of the take-or-pay clause may be higher than the current cost of gas supplies in the year when the accrued gas is actually reversed through profit and loss. In 2015, the segment operating profit was hit by a €150 million charge in connection to this factor.

Risks associated with sector-specific regulations in Italy

Risks associated with the regulatory powers entrusted to the Italian Authority for Electricity and Gas in the matter of pricing to residential customers

Eni's Gas & Power segment is exposed to regulatory risks mainly in its domestic market in Italy. Developments in the regulatory framework may negatively affect future sales margins of gas and electricity, operating results and cash flow. Below is provided an overview of the most important aspects of the ongoing regulatory framework of the gas sector in Italy including management's evaluation of the possible impacts on the future results of operations in the Gas & Power segment. The Italian Authority for Electricity and Gas (the "Authority") is entrusted with certain powers in the matter of natural gas pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential users. Accordingly, decisions of the Authority

on these matters may limit the ability of Eni to pass an increase in the cost of the raw material onto final consumers of natural gas.

In 2013, the Authority changed the pricing mechanism of gas supplies to retail customers by introducing a full indexation of the raw material cost component of the tariff to spot prices, by this way replacing the former oil-linked indexation. The new regulatory regime was introduced in a market scenario where gas spot prices were significantly lower than gas prices under long-term, oil-linked contracts, as the Brent price at the time was about 100 \$/bbl. Subsequently, the Authority introduced a compensation mechanism to promote the renegotiation of long-term gas supply contracts. This compensation mechanism was intended to mitigate the impact of the new tariff regime to operators with long-term supply contracts (typically oil-linked) by reimbursing to them part of the higher long-term gas supply costs which would be no longer recoverable trough tariffs. This compensation mechanism applies to the three thermal years, from October 2013 through October 2016.

The Authority set the initial amount of the compensation in 2013 based on the documentation filed by each operator, taking into account the price differential between the average price of a basket of theoretically efficient longterm contract and spot prices at the Dutch platform TTF. The Authority elaborated a projection of the supply costs of gas that Eni would incur in the future thermal year of the compensation mechanism, under various oil prices assumptions. Based on those projections and on gas forward prices and volume forecast for Eni, the Authority established a maximum compensation of €160 million, to which Eni would be entitled for the three-thermal year period of the mechanism implementation. The Authority resolution envisages that 40% of the compensation is due in the first thermal year, 40% in the second year and 20% in the third thermal year. In each thermal year, the Authority would update the compensation mechanism to verify the ongoing right of gas operators to receive compensation in the light of evolving trends in costs and prices of gas. Based on this, the initial amount of the compensation would be confirmed or, in case trends in spot prices vs. oil-linked prices reverse, operator would have to compensate customers by paying to the Authority up to three time the amount of the initial compensation, plus giving back any tranche of the compensation already cashed in.

In thermal year 2014, the Authority updated the index of supply costs applicable to Eni's portfolio. Under a 100 \$/bbl scenario, the AEEGSI verified that Eni's costs of supplies were higher than spot prices and accordingly ratified the first tranche of the compensation equal to €60 million (or the 40% of the initial amount). This gain was recognized in the group consolidated financial statements for the year 2014. In November 2015, the Authority updated the index of procurement cost for thermal year 2015 and resolved that Eni's supply costs have evolved

coherently to the Authority projections made in 2013. Under this scenario, the Authority confirmed the initial amount of the compensation of €160 million and Eni recognized a second tranche equal to 40% of that amount (approximately €60 million) in the 2015 Financial Statements.

In spite of these favorable developments, considering the current market scenario, it is possible that the Authority might determine an unfavourable update of the supply cost index for the thermal year 2016. Under this scenario, Eni could incur a loss up to three times the amount of the initial compensation or €480 million, giving back the amounts already recognized in 2014 and 2015.

The final outcome is expected in the fourth quarter of 2016 when the AEEGSI is scheduled to update the supply cost index for the thermal year 2016, on which basis Eni is due to recognize the profit and loss impact (positive or negative as the case may be).

In the light of current market scenario, Eni prudently contested the Resolution 549/2014/R/gas, which implements the compensation mechanism. Eni claimed that the Resolution did not provided sufficient criteria for updating the compensation and could potentially determine unfair results, also contending its legitimacy.

Environmental, health and safety regulations

Eni has incurred in the past, will continue incurring material operating expenses and expenditures, and is exposed to business risk in relation to compliance with applicable environmental, health and safety regulations in future years, including compliance with any national or international regulation on GHG emissions

Eni is subject to numerous EU, international, national, regional and local laws and regulations about the impacts of its operations on the environment and health and safety of employees, contractors, communities and properties. Generally, these laws and regulations require acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining and other Group's operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the Company's activities, and impose criminal or civil liabilities for polluting the environment or harming employees' or communities' health and safety resulting from oil, natural gas, refining and other Group's operations.

Different kinds of limits and restrictions on the activities of exploring and producing hydrocarbons could be enacted also in OECD countries due to environmental reasons or other motivations as it would occur in case of a favorable outcome of an Italian referendum scheduled April 17, 2016 on whether to abrogate an environmental rule that currently allows

oil&gas operators to continue production at offshore fields located in territorial waters beyond relevant concessions term till fields depletion. Eni is currently operating 29 concessions in Italy's territorial waters. These concessions account for approximately 1% of the Company's proved reserves at December 31, 2015 (6,890 million boe). Within such amount and factoring in the portion of those reserves that could be produced before the expirations of the underlying concessions, in case of an unfavourable outcome of the above mentioned referendum and assuming that the concessions would be revoked upon expiration, the Company's results of operations and cash flow might be negatively affected also considering the negative impact associated with higher amortization charges and accelerated wind down of decommissioning liabilities.

These laws and regulations also regulate emissions of substances and pollutants, handling of hazardous materials and discharges to surface and subsurface of water resulting from the operation of oil and natural gas extraction and processing plants, petrochemical plants, refineries, service stations, vessels, oil carriers, pipeline systems and other facilities owned by Eni. In addition, Eni's operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials.

Breach of environmental, health and safety laws expose the Company's employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage, as well as damage to its reputation. Additionally, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace, the Company can be liable for negligent or willful conduct on part of its employees as per Italian Law Decree No. 231/2001.

Environmental, health and safety laws and regulations have a substantial impact on Eni's operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations and to safeguard the environment, safety on the workplace, health of employees, contractors and communities involved by the Company operations, including:

• costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change;
• remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below);
• damage compensation claimed by individuals and entities, including local, regional or state administrations, in case Eni causes any kind of accident, pollution, contamination or other environmental liability involving its operations or the Company is found guilty of violating environmental laws and regulations; and
• costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging.

Furthermore, in the countries where Eni operates or expects to operate in the near future, new laws and regulations, the imposition of tougher license requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause Eni to incur material costs resulting from actions taken to comply with such laws and regulations, including:

• modifying operations;
• installing pollution control equipment;
• implementing additional safety measures; and
• performing site clean-ups.

As a further result of any new laws and regulations or other factors, Eni may also have to curtail, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish Eni's productivity and materially and adversely impact Eni's results of operations, including profits and cash flow. Security threats require continuous assessment and response measures. Acts of terrorism against Eni's plants, installations, platforms and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people and the environment.

Risks of environmental, health and safety incidents and liabilities are inherent in many of Eni's operations and products. Management believes that Eni adopts high operational standards to ensure safety in running its operations and safeguard of the environment and the health of employees, contractors and communities. In spite of those measures, it is possible that incidents like blowouts, oil spills, contaminations, pollution, and release in the air, soil and ground water of pollutants and other dangerous materials, liquids or gases, and other similar events could occur that would result in damage, also of large proportion and reach, to the environment, employees, contractors, communities and property. The occurrence of any such events could have a material adverse impact on the Group business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders' return and damage to the Group reputation.

Eni has incurred in the past and may incur in the future material environmental liabilities in connection with the environmental impact of its past and present industrial activities. Eni is also exposed to claims under environmental requirements and, from time to time, such claims have been made against us. In Italy, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, natural resource damages, and other damages as a result of Eni's conduct of operations that was lawful at the time it occurred or the conduct of prior operators or other third parties. In addition, plaintiffs may seek to obtain compensation for damage resulting from events of contamination and pollution or in case, the Company is held liable of violations of any environmental laws or regulations.

Eni is notified from time to time of potential liabilities at the

Italian sites where the Company has conducted industrial operations in the past. These potential liabilities may arise from both historical Eni operations and the historical operations of companies that Eni has acquired. Many of those potential liabilities relate to certain industrial sites that the Company disposed of, liquidated, closed or shut down in prior years where Group products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities. At those industrial locations Eni has commenced a number of initiatives to restore and clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group's industrial activities. The Group believes that it cannot be held liable for contaminations occurred in past years (as permitted by applicable regulations in case of declaration rendered by a guiltless owner i.e. as a result of Eni's conduct that was lawful at the time it occurred) or because Eni took over operations from third parties. However, state or local public administrations sued Eni for environmental and other damages and for clean-up and remediation measures in addition to those which were performed by the Company, or which the Company committed to perform.

Eni expects remedial and clean-up activities at Eni's sites to continue in the foreseeable future impacting Eni's liquidity. As of December 31, 2015, the Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amounts represent the management's best estimates of the Company's liability.

Management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the likelihood of as yet unknown contamination; (ii) the results of ongoing surveys or surveys to be carried out on the environmental status of certain of Eni's industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavorable developments in ongoing litigation on the environmental status of certain of the Company's sites where a number of public administrations and the Italian Ministry of the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites.

As a result of those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni's liquidity, results of operations, consolidated financial condition, business prospects, reputation and shareholders' value, including dividends and the share price.

Laws and regulations related to climate change may adversely affect the Group's businesses

Growing public concern in a number of countries over greenhouse gas (GHG) emissions and climate change, as well as a multiplication of stricter regulations in this area, could adversely affect the Group's businesses, increase its operating costs and reduce its profitability.

The scientific community has established a link between climate change and increasing GHG emissions. The worldwide goal to limit global warming has led to the need to gradually reduce fossil fuel use notably through the diversification of the energy mix. The share of natural gas, the least GHG-emitting fossil energy source, represented 48% of Eni's production in 2015.

In December 2015, a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries committing to work towards limiting global warming and agreeing to a monitoring and review process of greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by countries. Nonetheless, the agreement may result in increased political pressure worldwide to adopt measures intended to reduce and monitor GHG emissions and may spur further initiatives aimed at reducing greenhouse gas emissions in the future.

Changes in environmental requirements related to greenhouse gases and climate change may negatively impact demand for oil and natural gas and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). State, national, and international governments and agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which Eni conducts business. Because Eni's business depends on the global demand for oil and natural gas, existing or future laws, regulations, treaties, or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on Eni's business if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of carbon dioxide that could have a material adverse effect on Eni's liquidity, consolidated results of operations, and consolidated financial condition.

The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. Finally, it should be noted some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.

Risks related to legal proceedings and compliance with anticorruption legislation

Eni is the defendant in a number of civil actions and administrative proceedings arising in the ordinary course of business. In addition to existing provisions accrued as of December 31, 2015 to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses due to the circumstance that they are often inherently difficult to estimate. Certain legal proceedings where Eni or its subsidiaries or its officers are parties involve the alleged breach of anti-corruption laws and regulations and ethical misconduct. Ethical misconduct and non-compliance with applicable laws and regulations, including non-compliance with anti-bribery and anticorruption laws, by Eni, its partners, agents or others that act on the Group's behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni's reputation and shareholder value.

Risks from acquisitions

Eni is constantly monitoring the oil and gas market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. Eni may also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets it acquires. If the integration and financial risks connected to acquisitions materialize, Eni's financial performance and shareholders' returns may be adversely affected.

Risks deriving from Eni's exposure to weather conditions

Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products. In colder years, demand for such products is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing business, as well as the comparability of results over different periods may be affected by such changes in weather conditions. In general, the effects of climate change could result in less stable weather patterns, resulting in more severe storms and other weather conditions that could interfere with Eni's operations and damage Eni's facilities. Furthermore, Eni's operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to Eni's operations and consequent

loss or damage of properties and facilities, as well as loss of output, revenues, maintenance and repair expenses and cash flow shortfall.

Eni's crisis management systems may be ineffective and Eni may be the target of cyber attacks

Eni has developed contingency plans to continue or recover operations following a disruption or incident. An inability to restore or replace critical capacity to an agreed level within an agreed period could prolong the impact of any disruption and could severely affect business, operations and financial results. Likewise, Eni has crisis management plans and capability to deal with emergencies at every level of its operations. If Eni does not respond or is not seen to respond in an appropriate manner to either an external or internal crisis, its business and operations could be severely disrupted with negative consequences on results of operations and cash flow.

Exposure to financial risk

Eni's business activities are inherently exposed to financial risk. This includes exposure to market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, and credit risk.

Eni's primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts, which are not covered by contracted sales, its refining margins and other activities. The Group's risk management objectives in addressing commodity risk are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group's exposures and to profit from short-term market opportunities and trading.

Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over The Counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage the commodity risk exposure. Eni also uses financial instruments to manage foreign exchange and interest rate risks.

The Group's approach to risk management includes identifying, evaluating and managing the financial risk using a top-down approach whereby the Board of Directors is responsible for establishing the Group risk management strategy and setting the maximum tolerable amounts of risk exposure. The Group's Chief Executive Officer is responsible for implementing the Group risk management strategy, while the Group's Chief Financial and Risk Management Officer is in charge of defining policies and tools to manage the Group's exposure to financial risk, as well as monitoring and reporting activities.

Various Group committees are in charge of defining internal

criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni's top level, to be used by the Group's business units, including monitoring and controlling activities. Although Eni believes it has established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties.

Commodity risk

Commodity risk is the risk associated with fluctuations in the price of commodities which may impact the Group's results of operations and cash flow. Exposure to commodity risk is both of a strategic and commercial nature. Generally, the Group does not hedge its strategic exposure to commodity risk. However, the Group actively manages its exposure to commercial risk arising when a contractual sale of a commodity has occurred or it is highly probable that it will occur and the Group aims to lock in the associated commercial margin.

The Group's risk management policies have evolved particularly in response to the deep changes occurred in the competitive landscape of the gas marketing business, volatile gas margins and development of liquid markets to trade spot gas. These policies also contemplate the use of derivative contracts for speculative purposes whereby Eni is seeking to profit from opportunities available in the gas market based, among other things, on its expectations regarding trends in future prices.

As part of those trading activities, the Company is implementing strategies of asset-backed trading in order to maximize the economic value of the flexibilities associated with its assets. Management believes that the price risks related to asset-backed trading activities are mitigated by the natural hedge granted by the assets' availability.

These derivative contracts entered into for trading purposes may lead to gains, as well as losses, which, in each case, may be significant. Those derivatives are accounted for through profit and loss, resulting in higher volatility in Eni's earnings.

Exchange rate risk

Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni's results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni's expenses are incurred in euros. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni's results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in U.S. dollar-denominated expenses and may also result in significant translation adjustments that impact Eni's shareholders' equity. The Exploration & Production segment is particularly affected by movements in the U.S. dollar versus the euro exchange rates as the U.S. dollar is the functional

currency of a large part of its foreign subsidiaries and therefore movements in the U.S. dollar versus the euro exchange rate affect year-on-year comparability of results of operations. In 2015, the Exploration & Production results of operations were positively affected by trends in the exchange rate of the euro against the U.S. dollar as the euro depreciated on average by 16.5% against the U.S. dollar.

Susceptibility to variations in sovereign rating risk

Eni's credit ratings are potentially exposed to risk in reductions of sovereign credit rating of Italy. On the basis of the methodologies used by Standard & Poor's and Moody's, a potential downgrade of Italy's credit rating may have a potential knock-on effect on the credit rating of Italian issuers such as Eni and make it more likely that the credit rating of the Notes or other debt instruments issued by the Company could be downgraded.

Interest rate risk

Interest on Eni's debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, "Euribor", and the London Interbank Offered Rate, "Libor". As a consequence, movements in interest rates can have a material impact on Eni's finance expense in respect to its debt. Additionally, spreads offered to the Company may rise in connection with variations in sovereign rating risks or company rating risks, as well as the general conditions of capital markets.

Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace in order to meet short-term financial requirements and to settle obligations. Such a situation would negatively affect the Group results of operations and cash flows as it would result in Eni incurring higher borrowing expenses to meet its obligations or, under the worst conditions, the inability of Eni to continue as a going concern. European and global financial markets are currently subject to volatility amid uncertainties relating to a weak macroeconomic outlook, particularly in the Euro-zone, and the financial stress of certain emerging economies or countries whose financial conditions depends upon the proceeds of the sale of hydrocarbon resources following an ongoing slump in commodity prices. If there are extended periods of constraints in the financial markets, or if Eni is unable to access the financial markets (including cases where this is due to Eni's financial position or market sentiment as to Eni's prospects) at a time when cash flows from Eni's business operations may be under pressure, Eni's ability to maintain Eni's long-term investment program may be impacted with a consequent effect on Eni's growth rate, and may impact shareholder returns, including dividends or share price.

The oil and gas industry is capital intensive. Eni makes and expect to continue to make substantial capital expenditures in its business for the exploration, development, exploitation and production of oil and natural gas reserves. In 2015, we invested approximately €10.2 billion in our Exploration & Production segment, down by approximately 17% from 2014

at constant exchange rates, in response to weak oil prices. Our capital budget for the four-year plan 2016-2019 amounts €37 billion and is substantially lower than our previous industrial plan (down by an estimated 21% at constant exchange rates) as a result of a planned reduction in spending prompted by significantly depressed commodity prices. We have budgeted €9.4 billion for capital expenditure in 2016 relating to continuing operations which are 20% lower than in 2015 at constant exchange rates. We may find that additional reductions in our 2016 capital spending become necessary depending on market conditions.

Historically, Eni's capital expenditures have been financed with cash generated by operations, proceeds from asset disposal, borrowings under its credit facilities and proceeds from the issuance of debt and bonds.

The actual amount and timing of future capital expenditures may differ materially from Eni's estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, and regulatory, technological and competitive developments.

Eni's cash flows from operations and access to capital markets are subject to a number of variables, including but not limited to:

• the amount of Eni's proved reserves;
• the volume of crude oil and natural gas Eni is able to produce and sell from existing wells;
• the prices at which crude oil and natural gas are sold;
• Eni's ability to acquire, find and produce new reserves; and
• the ability and willingness of Eni's lenders to extend credit or of participants in the capital markets to invest in Eni's bonds.

If revenues or Eni's ability to borrow decrease significantly due to factors like a prolonged decline in crude oil and natural gas prices, Eni might have limited ability to obtain the capital necessary to sustain its planned capital expenditures. If cash generated by operations, cash from asset disposal, or cash available under Eni's liquidity reserve or its credit facilities is not sufficient to meet capital requirements, the failure to obtain additional financing could result in a curtailment of operations relating to development of Eni's reserves, which in turn could adversely affect its business, financial condition, results of operations, and cash flows and its ability to achieve its growth plans.

With respect to the 2016-2019 business plan in particular, management expects to deliver approximately €7 billion of additional cash flows from asset disposals, the main part of which will comprise the divestment of stakes in our exploration assets thereby in essence monetizing some of the Group's recent exploration successes and reserves. These additional cash flows are intended to provide funding to support organic growth and our planned shareholders distributions in a manner consistent with our target capital structure. The Company is seeking to complete such disposals in large part within 2016-2017. However, asset disposals are subject to execution risk and may fail to be completed, and the proceeds received from such disposals may not reflect values that management currently believes are

achievable, particularly if the disposals are carried out in difficult market conditions. The failure to achieve the planned disposal program could negatively affect the achievement of our financial targets forcing us to either curtail capital expenditure thus hampering growth or take on more finance debt.

These factors could also negatively affect shareholders' returns, including the amount of cash available for dividend distribution as well as the share price.

In addition, funding Eni's capital expenditures with additional debt will increase its leverage and the issuance of additional debt will require a portion of Eni's cash flows from operations to be used for the payment of interest and principal on its debt, thereby reducing its ability to use cash flows to fund capital expenditures and dividends.

Credit risk

Credit risk arise from the exposure of the Group to losses in case counterparties fail to perform or pay due amounts. Credit risks arise from both commercial partners and financial ones. In the latest years, the Group has experienced a higher than normal level of counterparty default due to the severity of the economic and financial downturn and the amount of trade receivables overdue at the balance sheet date has increased significantly. Furthermore, a collapse in oil prices has stressed the financial condition of many state-owned entities, which are party to our upstream projects for exploring and developing hydrocarbons. In Eni's 2015 Consolidated Financial Statements, it was accrued an allowance against doubtful accounts amounting to €581 million (compared to €518 million in 2014), mainly relating to the Gas & Power business. Management believes that this business is particularly exposed to credit risks due to its large and diversified customer base, which include a large number of medium and small-sized businesses and retail customers who have been particularly impacted by the financial and economic downturn. Eni believes that the management of doubtful accounts represents an issue to the Company, which will require management focus and commitment going forward. In the future Eni cannot exclude the recognition of significant provisions for doubtful accounts.

Digital infrastructure is an important part of maintaining Eni's operations. A breach of Eni's digital security could result in serious damage to business operations, personal injury, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs The reliability and security of Eni's digital infrastructure is critical to maintaining the availability of Eni's business applications, including the reliable operation of technology in Eni's various business operations and the collection and processing of financial and operational data, as well as the confidentiality of certain third-party information. If Eni's systems for protecting Eni's digital security prove to be ineffective, either due to intentional actions such as cyber attacks or due to negligence, Eni could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having Eni's business operations interrupted, and increased costs to prevent, respond to, or mitigate potential risks to Eni's digital infrastructure. Furthermore, in some circumstances, failures to protect digital infrastructure could result in injury to people, damage to assets, harm to the environment, breaches of regulations, litigation, legal liabilities and reparation costs.

The Company's auditors, like all other independent registered public accounting firms operating in Italy, are not permitted to be subject to inspection by the Public Company Accounting Oversight Board, and accordingly, investors may be deprived of the benefits of such inspection

The independent registered public accounting firm that issues the audit reports included in Eni's annual reports filed with the U.S. SEC, as auditor of companies that are traded publicly in the United States and firms registered with the Public Company Accounting Oversight Board ("PCAOB"), is required by the laws of the United States to undergo regular inspections by the

PCAOB to assess its compliance with U.S. SEC rules and PCAOB professional standards.

Because Eni's auditor is a registered public accounting firm in Italy, a jurisdiction where the PCAOB is currently unable under Italian law to conduct inspections pending the mutual agreement between the PCAOB and the Italian Authorities, Eni's auditor, like all other independent registered public accounting firms in Italy, is currently out of the reach of PCAOB inspections. PCAOB inspections of audit firms have identified holes and deficiencies in those firms' audit procedures and quality control procedures, which may be addressed as part of the inspection process to improve future audit quality. The lack of PCAOB inspections in Italy prevents the PCAOB from regularly evaluating Eni's auditor's audits and quality control procedures. As a result, the inability of the PCAOB to conduct inspections of auditors in Italy may deprive Eni's investors of the benefits of PCAOB inspections.

Outlook

The global macroeconomic outlook for 2016 is characterized by a number of risks and uncertainties, mainly due to the continued slowdown in China's industrial activity, the Eurozone and other commodity-exporting countries. After hitting multi-year lows of below \$30 per barrel, the price of crude oil is expected to continue to be weak due to structural imbalances in the marketplace driven by oversupply and renewed uncertainties surrounding the pace of future energy demand in the medium and long-term. Based on this macroeconomic outlook, Eni's management has

revised downwards its pricing assumptions of the Brent crude oil marker utilized in each of the periods of the Company's strategic plan 2016-2019: particularly the long-term reference price has been reduced to 65 dollar-a-barrel, down from the 90-dollar case utilized in the previous planning assumptions. In order to cope with the anticipated negative impact of the scenario on the E&P results from operations and cash flow, management is planning to increase efforts to optimize capex and reduce operating costs by exploiting the deflationary pressure induced by the fall in crude oil prices. In the G&P sector, management anticipates a challenging environment pressured by weak demand growth and oversupplies. The Company confirms its strategy to renegotiate long-term supply contracts in order to align the supply terms with market conditions, as well as boost profitability in its high-value businesses (LNG, gas retail and trading). In the R&M sector management expects still profitable refining margin, although lower than in 2015. In this context, business strategies will be focused on the optimization of refinery processes and costs as well as on the enhancement of results in marketing.

Management's forecasts for the Group's production and sale metrics are explained below:

• Hydrocarbons production: management expects production to be flat y-o-y due to the expected start-up of new fields, particularly in Norway, Egypt, Angola, Kazakhstan and the United States, and the ramp-up of fields started in 2015 to offset decline at mature fields;

• Natural gas sales: against the backdrop of weak demand and strong competition, management expects gas sales to be down y-o-y in line with an expected reduction of the contractual minimum take of long-term supply contracts. Management plans to retain its market share in the large customers and retail segments also increasing the value of the existing customer base by developing innovative commercial propositions, by integrating services to the supply of the commodity and by optimizing operations and commercial activities;

• Refinery intake on own account: refinery intake are expected flat y-o-y excluding the effect of the disposal of Eni's refining capacity in CRC refinery in Czech Republic finalized on April 30, 2015;
• Refined products sales in Italy and in the Rest of Europe: against the backdrop of weak demand growth and strong competition, management expects to consolidate volume and market share in the Italian retail market also increasing the value of the existing customer base by leveraging our offer differentiation, innovation in products and services as well as efficiency in logistic and commercial activities.

In 2016 management expects to carry out a number of initiatives intended to reduce capital spending by approximately 20% y-o-y on a constant exchange rate basis by re-phasing and rescheduling capital projects, being increasingly selective with exploration plays and renegotiating contracts for the supply of capital goods in order to cope with the slump in crude oil prices. Those initiatives are expected to have a limited impact on our plans to grow production in the short and medium term. Management forecasts that capex will be 100%-funded by cash flow from operations under a 50 dollar-a-barrel scenario. Operating costs per boe is expected to be reduced by 11% y-o-y.

The Group's leverage is projected to be below the 0.30 threshold thanks to the closing of the Saipem transaction, optimization of the underlying performance and portfolio management, which are expected to reduce the impact of the oil and gas prices.

Acceptance of Italian responsible payments code

Coherently with Eni's policy on transparency and accuracy in managing its suppliers, Eni SpA adhered to the Italian responsible payments code established by Assolombarda in 2014. During the year, payments to Eni's suppliers were made within 62 days, in line with contractual provisions.

Continuing listing standards provided by Article No. 36 of Italian exchanges regulation (adopted with Consob Decision No. 16191/2007 as amended) about issuers that control subsidiaries incorporated or regulated in accordance with laws of extra-EU Countries

Certain provisions have been enacted regulating continuing Italian listing standards of issuers controlling subsidiaries that are incorporated or regulated in accordance with laws of extra-EU Countries, also having a material impact on the Consolidated Financial Statements of the parent company.

Regarding the aforementioned provisions, the Company discloses that:

• as of December 31, 2015, ten of Eni's subsidiaries: Burren Energy (Bermuda) Ltd, Eni Congo SA, Eni Norge AS, Eni Petroleum Co Inc, NAOC - Nigerian Agip Oil Co Ltd, Nigerian Agip Exploration Ltd, Burren Energy (Congo) Ltd, Eni Finance USA Inc, Eni Trading & Shipping Inc and Eni Canada Holding fall within the scope of the new continuing listing standards. Eni has already adopted adequate procedures to ensure full compliance with the new regulations;
• the Company has already adopted adequate procedures to ensure full compliance with the regulation.

Branches

In accordance with Article No. 2428 of the Italian Civil Code, it is hereby stated that Eni has the following branches: San Donato Milanese (MI) - Via Emilia, 1 San Donato Milanese (MI) - Piazza Vanoni, 1.

Subsequent events

Subsequent business developments are described in the operating review of each of Eni's business segments.

Integrated performances

Reporting criteria

Eni's reporting system is structured with a multi-channel approach which allows for different levels of analysis and communication methods to reach all Eni's stakeholders in an effective, timely and immediate way.

Pursuing its commitment towards an integrated reporting, Eni has included in its Annual Report 2015 a prospect of integrated performance indicators: for each strategic objective the most significant indicators of each capital used by Eni (financial, productive, intellectual, natural, human, social and relationship) have been considered in drafting the company strategy.

Reporting principles

The present prospectus has been drafted following the principles of balance, comparability, accuracy, timeliness, reliability and clarity (reporting principles), as defined by the Global Reporting Initiative - GRI in the "G4 Sustainability Reporting Guidelines".

The performance indicators, selected according to the issues which have resulted being the most relevant, have been collected on an annual basis; the reporting periodicity is set according to a yearly frequency. The information and quantitative data collection process has been structured in order to guarantee the comparability of the data over several years, in order to allow all the stakeholders interested in the evolution of Eni's performances to have a proper interpretation of the information and a complete vision of the companies' results.

The data related to the years 2013 and 2014 can differ slightly from those previously published as a result of consolidating data that became available after the publication of the documents. For the same reason, the data on the year 2015 are the best estimates possible with the ones available at the time of writing of this prospectus.

Reporting perimeter

The present prospectus reports the integrated performance indicators of the 2013-2015 period. The information refer to Eni SpA and the consolidated companies. The consolidation perimeter matches with the one of the 2015 financial consolidated report, except for few data which have been expressly indicated.

In 2015, data reported for the three-year period are expressed, net of Saipem contribution, due to the 12.503% divestment to Fondo Strategico Italiano SpA, finalized in January 2016, and net of Versalis, for which as of the reporting date, negotiations were underway to define an agreement with an industrial partner aimed at the sale of a controlling stake. Regarding the health, safety and environmental data the consolidation scope is defined accordingly to the operational criteria (control of the operations). Data relating to employees refer to fully consolidated subsidiaries and reflect the new segmental reporting of Eni. KPIs on employees are determined consequently. The comparative data have been restated consistently.

	Fuel value and increase explorative resources and growth in upstream cash generation		2013	2014
	Capital expenditure	(€ million)	10,475	10,524	2015 10,234
Financial capital	Opex per boe	(\$/boe)	8.3	8.4	7.2
	Cash flow per boe	(\$/boe)	31.9	30.1	20.1
Productive capital	Proved hydrocarbon reserves	(mmboe)	6,535	6,602	6,890
	Reserves life index Organic reserves replacement ratio	(years) (%)	11.1 105	11.3 112	10.7 148
Natural capital	Direct GHG emission	(million tonnes CO2 eq)	27.4	23.4	22.8
	- of which CO2 eq from flaring eq emissions/100% operated hydrocarbon gross production	eq/kboe)	9.13 31.8	5.73 27.5	5.51 25.0
	CO2 Volume of hydrocarbons sent to process flaring	(tonnes CO2 (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		6,476	6,441	6,266
	Female employees		2,442	2,462	2,453
	Number of hiring Injury frequency rate of total workforce	(No. of accidents per million worked hours)	1,324 0.23	681 0.23	387 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
Financial capital	Adjusted operating profit (loss)	(€ million)	(622)	168	(126)
	Operating expenses reduction	(%)	(10)	(15)	(28)
	Capital expenditure	(€ million)	229	172	154
Productive capital	Worldwide gas sales	(bcm)	93.17	89.17	90.88
	LNG sales		12.4	13.3	13.5
	Customers in Italy	(million)	8.00	7.93	7.88
	Electricity sold	(TWh)	35.05	33.58	34.88
Natural capital	Direct GHG emissions	(million tonnes CO2 eq)	11.3	10.1	10.6
	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 SOx emissions/kWheq (EniPower)	(gNO2 (gSO2 eq/kWheq)	0.017	0.001	0.001
	Water withdrawals/kWeq produced (EniPower)	(cm/kWheq)	0.017	0.017	0.015
capital	Customer satisfaction rate	(scale from 0 to 100)	80.0	81.4	85.6
Social and relationship
Intellectual capital	Existing patents	(number)	56	43	7
Human capital	Employees at year end	(number)	4,791	4,469	4,388
	Employees outside Italy		2,550	2,437	2,402
	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 Employees covered by performance assessment tools (senior managers,	(€ million)	9	7	7
	managers/supervisors and young graduates)	(%)	63	72	69
	Training hours Training expenditure	(number) 147,011 (€ million)	1.9	92,701 1.2	98,579 1.9

Integrated performances

	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
capital Natural	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
	Employees at year end	(number)	6,469	5,823	5,234
Human capital	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% (GJ/toe) operated hydrocarbon gross production	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

	Other significant performances
		2013	2014	2015
	Members of Eni's Board of Directors (number)	9	9	9
	- executive	1	1	1
Governance	- non executive	8	8	8
	- independent(a)	7	7	7
	- non independent	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
	Employees at year end (number)	29,176	28,597	28,246
Human capital	- 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 relationship capital
	Suppliers used (number)	13,573	11,342	9,268
	Total procurement (€ million)	19,043	22,955	19,514
	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
capital	R&D expenditure(c) (€ million)	142	134	139
Intellectual	First patent filing applications (number)	35	50	22
	- of which filing of renewable energy Existing patents	21 3,644	17 3,056	11 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 Methane 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	1,114	968	801
	- of which fresh water	61	59	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.

(c) Net of general and administrative costs.

Integrated performances

Transparency on payments made to Governments for the purpose of the commercial development of hydrocarbons

In the matter of transparency of payments made to Governments in the extraction of hydrocarbons, Eni has been working to voluntarily achieve a higher degree of disclosure on payments, before the entry into force of transparency legislation and alongside the Company's continued support to the Extractive Industries Transparency Initiative (EITI) and anticipating the reporting obligations on payments transparency established by EU Directive 2013/34 which the Italian legislator has enacted with legislative decree No. 139 of August 18, 2015 effective for payments made on or after January 1, 2016 to be reported in 2017. Therefore information provided below has been furnished on voluntary basis and does not constitute compliance with a reporting obligations. In particular, as Eni believes that the active involvement of governments is key to a sustainable use of revenues, the company has reached out to all its counterparts in upstream contracts in order to share the company's commitment on transparency and request their consent on disclosing taxes, royalties and the other forms of payment foreseen by the EITI Standard and the EU Directives. Therefore, Eni voluntarily discloses payments ("on a cash basis") to governments (including to local authorities and other governmental authorities) for the year 2015. Payments refer to those Countries whose governments/local authorities/governmental counterparts provided consent to this disclosure. Data in the following table correspond to the Company's accounting records and include data for the parent company and consolidated subsidiaries. Payments to governments referring to petroleum activities operated by Eni are disclosed on a 100% basis, when Eni paid on behalf of the Joint Venture partners. Payments made by Joint Venture partners on behalf of Eni in those activities where Eni is not the operator are not reported. Payment categories are in line with EITI Standard and EU directives' payment categories. The following disclosure represents approximately 75% of Eni's 2015 production (80% when including the two countries adhering to EITI listed below).

(€ thousands)	Year	Host government's entitlement	National Oil Companies entitlement	Profit taxes	Royalties	Bonus	Fees	Other significant payments and benefits	Capital Expenditure(*)	Revenues from sales of equity hydrocarbons(*)
Angola	2015		46,335	193,814	80,202		33	1,447	1,354,317	1,585,505
Australia	2015			4,390			520		14,620	91,657
China	2015			1,484			136		11,248	62,060
Croatia	2015			4,607					2,597	36,958
Cyprus	2015							600	112,189
Denmark	2015
Ecuador	2015			41,106(a)				8,757	21,960	124,851
Gabon	2015						21	1,416	80,089
Ghana	2015						1,388		203,428
Indonesia	2015			27,669		39			732,705	165,603
Iraq	2015			15,843				11,647	481,312	576,265
Ireland	2015								2,057
Italy	2015				301,871		2,202	1,868	726,832	2,123,516
Kenya	2015						161		3,825
Libya	2015		1,554,740	1,983,759	222,621			45,065	444,061	3,840,949
Myanmar	2015						901		5,529
Nigeria	2015		11,277	163,789	168,537		9,681	28,664	451,078	1,559,178
Norway	2015			41,411			8,565		1,115,747	1,383,956
Pakistan	2015			27,122	30,584		724		55,443	279,963
Portugal	2015						523	160	3,589
Rep. of Congo	2015	40,098	9,433	173,989	162,855		3,780		888,754	1,284,200
Russia	2015			1,439					55
The Netherlands	2015			275
The United Kingdom	2015			126,713			926		200,746	907,974
Timor Leste	2015	47,965		21,735	1,693		509		16,909	163,479
Ukraine	2015			98					13
USA	2015			9,401	40,290		4,126		660,009	1,092,182
Vietnam	2015					451		563	16,080
EITI DATA(**)
Kazakhstan	2014			343,922				(94,344)(b)
Mozambique	2013-2014			53,280(c)				301,132(d)

(*) Accrual basis.

(**) The reported data refer to the last EITI disclosure issued in relation to EITI countries.

(a) The data include the payment of \$ 33,136 thousands for previous years taxes subject to tax dispute.

(b) Mainly refers to VAT reimbursement of 23,226,728 thousands of Tenge relating to Agip Caspian Sea BV Branch.

(c) Including taxes on employees and withholding taxes on suppliers.

(d) Payment of \$ 400,000 thousands to fiscal Authority of Mozambique relating to taxes on disposal of 28.57% shares of Eni East Africa SpA.

Royalties paid in Italy in the 2013-2015 period

(€ thousands)	2013	2014	2015
Royalties paid(a)	298,383	327,187	301,871
- of which to State	138,302	149,454	126,172
- of which to Regions	125,596	130,611	122,684
- of which to Basilicata	91,862	94,925	86,652
- of which to municipalities	34,486	47,123	53,015

(a) The data include Eni SpA (Exploration & Production), EniMed, Società Adriatica Idrocarburi and Società Ionica Gas.

The glossary of oil and gas terms is available on Eni's web page at the address eni.com. Below is a selection of the most frequently used terms.

Financial terms

• Dividend Yield Measures the return on a share based on dividends for the year. Calculated as the ratio of dividends per share of the year and the average reference price of shares in the last month of the year. Generally, companies tend to keep a constant dividend yield, as shareholders compare this indicator with the yield of other shares or other financial instruments (e.g. bonds).
• Leverage Is a measure of a company's debt, calculated as the ratio between net financial debt and shareholders' equity, including minority interests.
• ROACE (Return On Average Capital Employed) Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed.
• Coverage Financial discipline ratio, calculated as the ratio between operating profit and net finance charges.
• Current ratio Measures the capability of the company to repay short-term debt, calculated as the ratio between current assets and current liabilities.
• Debt coverage Rating companies use the debt coverage ratio to evaluate debt sustainability. It is calculated as the ratio between net cash provided by operating activities and net borrowings, less cash and cash-equivalents, Securities held for non-operating purposes and financing receivables for non operating purposes.
• Profit per boe Measures the return per oil and natural gas barrel produced. It is calculated as the ratio between Results of operations from E&P activities (as defined by FASB Extractive Activities - oil&gas Topic 932) and production sold.
• Opex per boe Measures efficiency in the oil&gas development activities, calculated as the ratio between operating costs (as defined by FASB Extractive Activities - oil&gas Topic 932) and production sold.
• Cash flow per boe Represents cash flow per each boe of hydrocarbon produced, less non-monetary items. Calculated as the ratio between Results of operations from E&P activities, net of depreciation, depletion, amortization and impairment and

exploration expenses (as defined by FASB Extractive Activities oil&gas Topic 932) and volumes of oil and gas produced.

• Finding & Development cost per boe Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities - oil&gas Topic 932).

Operating activities

• Average reserve life index Ratio between the amount of reserves at the end of the year and total production for the year.
• Barrel/BBL Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tons.
• Boe (Barrel of Oil Equivalent) Is used as a standard unit measure for oil and natural gas. From July 1, 2012, Eni has updated the conversion rate of gas to 5,492 cubic feet of gas equals 1 barrel of oil (it was 5,550 cubic feet of gas per barrel in previous reporting periods).
• Conversion Refinery process allowing the transformation of heavy fractions into lighter fractions. Conversion processes are cracking, visbreaking, coking, the gasification of refinery residues, etc. The ration of overall treatment capacity of these plants and that of primary crude fractioning plants is the conversion rate of a refinery. Flexible refineries have higher rates and higher profitability.
• Emissions of NOx (Nitrogen Oxides) Total direct emissions of nitrogen oxides deriving from combustion processes in air. They include NOx emissions from flaring activities, sulphur recovery processes, FCC regeneration, etc. They include NO and NO2 emissions and exclude N2 O emissions.
• Emissions of SOx (Sulphur Oxides) Total direct emissions of sulfur oxides including SO2 and SO3 emissions. Main sources are combustion plants, diesel engines (including maritime engines), gas flaring (if the gas contains H2 S), sulphur recovery processes, FCC regeneration, etc.
• Enhanced recovery Techniques used to increase or stretch over time the production of wells.
• Green House Gases (GHG) Gases in the atmosphere, transparent to solar radiation, can consistently trap infrared radiation emitted by the earth's surface, atmosphere and

Glossary

clouds. The six relevant greenhouse gases covered by the Kyoto Protocol are carbon dioxide (CO2 ), methane (CH4 ), nitrous oxide (N2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6 ). GHGs absorb and emit radiation at specific wavelengths within the range of infrared radiation determining the so called greenhouse phenomenon and the related increase of earth's average temperature.

• Infilling wells Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels.
• LNG Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed and consumed. One ton of LNG corresponds to 1,400 cubic meters of gas.
• LPG Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression.
• Mineral Potential (Potentially recoverable hydrocarbon volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage.
• Natural gas liquids Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that used to be defined natural gasoline, are natural gas liquids.
• Oil spills Discharge of oil or oil products from refining or oil waste occurring in the normal course of operations (when accidental) or deriving from actions intended to hinder operations of business units or from sabotage by organized groups (when due to sabotage or terrorism).
• Over/underlifting Agreements stipulated between partners regulate the right of each to its share in the production of a set period of time. Amounts different from the agreed ones determine temporary over/underlifting situations.
• Production Sharing Agreement (PSA) Contract in use in African, Middle Eastern, Far Eastern and Latin American countries, among others, regulating relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor's

equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: "cost oil" is used to recover costs borne by the contractor and "profit oil" is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country.

• Proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from know reservoirs, and under existing economic conditions. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
• Reserves Quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods.
• Ship-or-pay Clause included in natural gas transportation contracts according to which the customer for which the transportation is carried out is bound to pay for the transportation of the gas also in case the gas is not transported.
• Take-or-pay Clause included in natural gas purchase contracts according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of the gas set in the contract also in case it is not collected by the customer. The customer has the option of collecting the gas paid and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years.
• Upstream/downstream The term upstream refers to all hydrocarbon exploration and production activities. The term mid-downstream includes all activities inherent to oil industry subsequent to exploration and production. Process crude oil and oil-based feedstock for the production of fuels, lubricants and chemicals, as well as the supply, trading and transportation of energy commodities. It also includes the marketing business of refined and chemicals products.
• Workover Intervention on a well for performing significant maintenance and substitution of basic equipment for the collection and transport to the surface of liquids contained in a field.

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

ADRs/Depositary

BNY Mellon Shareowners Services P.O. Box 30170 College Station, TX 77842-3170 shrrelations@cpushareownerservices.com

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