UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 20-F

		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015
OR
		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____ to _____
OR
		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report

Commission file number: 1-14090
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Eni SpA
(Exact name of Registrant as specified in its charter)
Republic of Italy
(Jurisdiction of incorporation or organization)
1, piazzale Enrico Mattei - 00144 Roma - Italy
(Address of principal executive offices)
Massimo Mondazzi
Eni SpA
1, piazza Ezio Vanoni
20097 San Donato Milanese (Milano) - Italy
Tel +39 02 52041730 - Fax +39 02 52041765
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
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Securities registered or to be registered pursuant to Section 12(b) of the Act.

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
                                        Ordinary shares of euro 1.00 each                                                                                                                                                                3,634,185,330

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Certain disclosures contained herein including, without limitation, information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", "Item 5 – Operating and Financial Review and Prospects" and "Item 11 – Quantitative and Qualitative Disclosures about Market Risk" contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.

CERTAIN DEFINED TERMS

In this Form 20-F, the terms "Eni", the "Group", or the "Company" refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to "Italy" or the "State" are references to the Republic of Italy, all references to the "Government" are references to the government of the Republic of Italy. For definitions of certain oil&gas terms used herein and certain conversions, see "Glossary" and "Conversion Table".

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

The Consolidated Financial Statements of Eni, included in this Annual Report, have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB).

Unless otherwise indicated, any reference herein to "Consolidated Financial Statements" is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein.

Unless otherwise specified or the context otherwise requires, references herein to "dollars", "$", "U.S. dollars", "US$" and "USD" are to the currency of the United States, and references to "euro", "€" and "EUR" are to the currency of the European Monetary Union.

Unless otherwise specified or the context otherwise requires, references herein to "Division" and "segment" are to Eni’s business activities: Exploration & Production, Gas & Power, Refining & Marketing, Engineering & Construction, Chemical and Corporate and Other activities.

References to Versalis or Chemical are to Eni’s chemical activities engaged through its fully-owned subsidiary Versalis and Versalis’ controlled entities.

STATEMENTS REGARDING COMPETITIVE POSITION

Statements made in "Item 4 – Information on the Company" referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.

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GLOSSARY

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

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ABBREVIATIONS

CONVERSION TABLE

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PART I

Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
NOT APPLICABLE

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
NOT APPLICABLE

Item 3. KEY INFORMATION

Selected Financial Information

The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (IASB). The tables below present Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2011, 2012, 2013, 2014 and 2015.

Comparative results of operations and cash flow for the year 2014 and 2013 have been restated accordingly as dictated by IFRS 5.

Also the selected historical financial data for the years 2012 and 2011 have been restated accordingly.

All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18.

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Selected Operating Information

The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2011, 2012, 2013, 2014 and 2015.

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Selected Operating Information continued

Exchange Rates

The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board).

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Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on March 31, 2015 was $1.14 per euro 1.00.

Risk factors

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

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 GHG 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.

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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. See "Item 5 – Operating and Financial Review and Prospects". 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 euro 0.2 billion for each one-dollar 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&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 euro 5 billion (euro 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&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 euro 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&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. See also "Item 18 – note 28 – Long-term debt and current portion of long-term debt – of the Notes on Consolidated Financial Statements".

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.

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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.

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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 GHG 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

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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 above mentioned 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&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&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&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&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&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

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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 euro 0.8 billion to conduct exploration projects and plans to spend approximately euro 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

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-lead-time projects are exposed to the volatility of oil&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.

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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. See "Item 4 – Exploration & Production – Kashagan".

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&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&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

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.

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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 euro 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&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&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&gas operations is materially higher than the Italian statutory tax rate for corporate profit, which currently stands at 27.5 per cent. See also "Item 18 – note 42 – Income taxes – of the Notes on Consolidated Financial Statements".

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&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

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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 euro 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 year-end 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&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.

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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. See "Item 5 – Management’s expectations of operations".

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 non-defaulting 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&gas production to local oil&gas companies. As of December 31, 2015, Eni owned a significant amount of trade receivables due (euro 771 million) in respect of supplies of its oil&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&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.

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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 pre-paid 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.

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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 euro 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 long-term 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 euro 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 euro 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 euro 160 million and Eni recognized a second tranche equal to 40% of that amount (approximately euro 60 million) in the 2015 Financial Statements.

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In spite of these favorable developments, considering the current market scenario, it is possible that the Authority might determine an unfavorable 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 euro 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&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 mmBOE). 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 unfavorable outcome of the above mentioned referendum and assuming that those 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.

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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

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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 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 46% of Eni’s production in 2015 on available-for-sale basis.

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 GHG 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 GHG emissions in the future.

Changes in environmental requirements related to GHG 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 GHG 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 GHG 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 GHG or otherwise limit emissions of GHG from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or install new equipment to reduce emissions of GHG associated with our operations.

Finally, it should be noted some scientists have concluded that increasing concentrations of GHG 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 anti-corruption 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

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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&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&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

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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

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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&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 euro 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 euro 37 billion, excluding capex associated with our disposal plan, 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. This capital plan is directed for about 90% to the E&P segment. We have budgeted euro 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.

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 euro 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.

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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 euro 581 million (compared to euro 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.

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Item 4. INFORMATION ON THE COMPANY

History and development of the Company

Eni SpA with its consolidated subsidiaries of the continuing operations engages in oil&gas exploration, development and production, marketing of gas, electricity and LNG, power generation, refining and marketing of petroleum products and, commodity trading. In 2015, the Group commenced a plan to divest its Engineering & Construction segment, which is managed by the subsidiary Saipem (Eni’s interest being 42.9%), and its Chemical business which is managed by Eni’s wholly-owned subsidiary Versalis. In the 2015 Consolidated Financial Statements, the two segments have been accounted for in accordance with IFRS 5 "non-current assets held for sale and discontinued operations". Therefore, they have been disclosed as discontinued operations and have been measured at the lower of their carrying amounts and fair value; results of operations and cash flow of the comparative periods have been restated accordingly. Eni has operations in 66 countries and 29,053 employees (excluding Saipem and Versalis) as of December 31, 2015.

Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders.

The name of the agent of Eni in the United States is Pasquale Salzano, 485 Madison Avenue, New York, NY 10002.

Eni’s principal segments of operations are described below.

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 42 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2015, Eni average daily production amounted to 1,688 KBOE/d on an available-for-sale basis. As of December 31, 2015, Eni’s total proved reserves amounted to 6,890 mmBOE; proved reserves of subsidiaries totaled 5,975 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 915 mmBOE. In 2015, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 21,436 million and an operating loss of euro 144 million.

Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international gas transport activities, and LNG supply and marketing. This segment also includes the activity of electricity generation that is ancillary to the marketing of electricity. In 2015, Eni’s worldwide sales of natural gas amounted to 90.88 BCM. Sales in Italy amounted to 38.44 BCM, while sales in European markets were 52.44 BCM which included 4.61 BCM of gas sold to certain importers to Italy. Eni produces power at a number of operated sites in Italy with a total installed capacity of 4.9 GW as of December 31, 2015. In 2015, electricity sold totaled 34.88 TWh. In 2015, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 52,096 million and an operating loss of euro 1,258 million. The Gas & Power segment comprises results of the Group activities intended to manage commodity risk and of asset-backed trading activities. Through the trading department of the parent company and its wholly-owned subsidiary Eni Trading & Shipping SpA, the Group engages in derivative activities targeting the full spectrum of energy commodities on both the physical and financial trading venues. The objective of this activity is both to hedge part of the Group exposure to the commodity risk and to optimize commercial margins by entering speculative derivative transactions. Since 2015, of the Gas & Power segment also comprises the result of activities of crude oil and products supply, trading and shipping services provided on behalf of Group companies, which were formerly reported in the Refining & Marketing segment (see Item 5). Previous reporting periods data have been restated accordingly.

Eni’s Refining & Marketing segment engages in crude oil supply and refining and petroleum products marketing in retail and wholesale markets mainly in Italy and in the rest of Europe. In 2015, processed volumes of crude oil and other feedstock amounted to 26.41 mmtonnes and sales of refined products were 35.24 mmtonnes, of which 26.53 mmtonnes in Italy. Retail sales of refined products at Eni’s service stations amounted to 8.89 mmtonnes in Italy and in the rest of Europe. In 2015, Eni’s retail market share in Italy through its "Eni" branded network of service stations was

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24.5%. In 2015, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 18,458 million and operating loss of euro 552 million.

A list of Eni’s subsidiaries is provided in "Item 18 – note 46 – Other information about investments – of the Notes on Consolidated Financial Statements".

 

Strategy

In order to manage a sharply deteriorated commodity price environment, the Company outlined for the next four-year period an action plan, which comprises a number of rigorous initiatives and objectives in order to mitigate the impact of lower oil prices on results and cash flow and to preserve the Group financial structure, particularly in the short to medium term. Our financial projections for the four-year plan 2016-2019 and capital project evaluations are based on the assumption of a long-term Brent reference price of 65 $/BBL that is significantly lower than our previous long-term price assumption of 90 $/BBL. Our new long-term price assumption is reflective of our view of worsened market fundamentals driven by continued oversupplies and uncertainties about the pace of energy demand growth in the long term. We are forecasting a Brent price of 40 $/BBL in 2016 and a progressive recovery along the plan period up to the long term case of 65 $/BBL due to an expected better balance between supply and demand in the light of reduced capital expenditure plans by oil majors, the possible exit from the market of producers with unsustainable cost structure and any possible agreements on part of producing countries to curb output.

Against the backdrop of a depressed commodity price environment in the short to medium term, our primary target remains to generate adequate cash flow from operations which will be underpinned by well-designed industrial actions, capital discipline, focus on Exploration & Production activities and a large disposal plan.

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In executing this strategy, management intends to pursue integration opportunities among segments and within each segment to strongly focus on efficiency improvement through technology upgrading, cost efficiencies, commercial and supply optimization and continuing process streamlining across all segments.

For a description of risks and uncertainties associated with the Company’s outlook, and the capital expenditure program see "Item 5 – Operating and financial review and prospects – Management’s expectations of operations".

2015 disposal activity

On January 22, 2016, following the satisfaction of all the conditions precedent, among which the consensus of Consob to the share capital increase resolved by Saipem, Eni closed the Sale and Purchase Agreement regarding the sale of 12.503% of the share capital of Saipem to the Fondo Strategico Italiano (FSI). The transaction refers to No. 55,176,364 Saipem shares at an average price of euro 8.39 per share for a total consideration of euro 463 million. The reference price for the transaction was determined as the arithmetic average of the official prices of the Saipem shares recorded in the trading days immediately before and after the announcement to the markets of the transaction, on October 28, 2015. The total consideration has been paid by FSI in a single installment, at closing.

At the closing of the Sale and Purchase Agreement, the preliminary Shareholders’ Agreement signed by Eni and FSI on October 27, 2015 became effective. The Agreement establishes the terms and conditions that shall govern, from the closing date onwards, the two parties’ respective relationships as shareholders of Saipem, particularly with reference to the entity corporate governance and any possible transaction relating each party’s interest in Saipem.

Each of Eni and FSI are contributing to the Shareholders’ Agreement an equal number of Saipem shares not exceeding 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 which entered into force on the closing date has a three-year term, 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 restriction regarding the transfer of shares not contributed to the Shareholders’ Agreement; and (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.

Based on the new corporate governance setup of Saipem, Eni and FSI have joint control of Saipem.

Finally Eni and FSI committed towards Saipem to subscribe pro-rata the share capital increase resolved by the entity for euro 3.5 billion.

The agreements provides the reimbursement of intercompany financing receivables owed by Saipem to Eni through the proceeds of the share capital increase and the refinancing with certain third-party financing institutions.

Considering that the transactions disclosed above were closed after the 2015 reporting date, in Eni’s Consolidated Financial Statements for the year 2015 Saipem is still fully consolidated and presented as "discontinued operation"

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based on the guidelines of IFRS 5 on disposal assets. 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, Eni’s net assets in Saipem have been aligned to the lower of their carrying amount and their fair value given by Saipem share price at the reporting date (euro 7.49 per share) (see "Item 5" for further information).

At the end of February 2016, following completion of the subscription of the share capital increase and assumption by Saipem of third-party refinancing, Saipem reimbursed intercompany loans owed to Eni.

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. In executing this transaction Eni has complied with all relevant applicable listing standards, market regulation and internal procedures set to ensure fairness and formal and substantial correctness of the transaction as well as the fact that the transaction was in the best interest of the Company.

In 2015, the Group commenced a plan to reduce its exposure to the Chemical business managed by Eni’s wholly-owned subsidiary Versalis SpA. At 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 business.

Therefore, effective for the full year, like 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, Eni’s net assets in Versalis have been aligned to the lower of their carrying amount and their fair value based on the proposal transaction. See "Item 5 – Discontinued operations".

Other significant business and portfolio developments

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In 2015, capital expenditures of continuing operations amounted to euro 10,775 million, entirely relating to Exploration & Production, Gas & Power and Refining & Marketing segments, and primarily related to: (i) development of oil and gas reserves (euro 9,341 million) deployed mainly in Angola, Norway, Egypt, Kazakhstan, Congo, Indonesia, Italy and the United States, and exploratory projects (euro 820 million) carried out primarily in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia; (ii) refining, supply and logistics in Italy and outside Italy (euro 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 in Italy and in the rest of Europe (euro 126 million); and (iii) initiatives to upgrade combined-cycle power plants (euro 69 million).

In 2014, capital expenditures of continuing operations amounted to euro 11,264 million and primarily related to: (i) development of oil&gas reserves (euro 9,021 million) deployed mainly in Norway, Angola, Congo, the United States, Italy, Nigeria, Egypt, Indonesia and Kazakhstan and exploratory projects (euro 1,398 million) carried out primarily in Libya, Mozambique, the United States, Nigeria, Angola, Indonesia, Cyprus, Norway and Gabon; (ii) refining, supply and logistics in Italy and outside Italy (euro 362 million) with projects designed to improve the conversion rate and flexibility of refineries, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 175 million); and (iii) initiatives to improve flexibility of the combined-cycle power plants (euro 98 million).

In 2013, capital expenditures of continuing operations amounted to euro 11,584 million, and primarily related to: (i) development of oil&gas reserves (euro 8,580 million) deployed mainly in Norway, the United States, Angola, Congo, Italy, Nigeria, Kazakhstan, Egypt and the United Kingdom, and exploration projects (euro 1,669 million) carried out mainly in Mozambique, Norway, Congo, Togo, Nigeria, the United States and Angola; (ii) refining, supply and logistics in Italy and outside Italy (euro 462 million) with projects designed to improve the conversion rate and flexibility of refineries, in particular at the Sannazzaro refinery, as well as the upgrade of the refined product retail network in Italy and in the rest of Europe (euro 210 million); and (iii) initiatives to improve flexibility of the combined-cycle power plants (euro 119 million).

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BUSINESS OVERVIEW

Exploration & Production

Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 42 countries, including Italy, Libya, Egypt, Norway, the United Kingdom, Angola, Congo, Nigeria, the United States, Kazakhstan, Algeria, Australia, Venezuela, Iraq, Ghana and Mozambique. In 2015, Eni average daily production amounted to 1,688 KBOE/d on an available-for-sale basis. As of December 31, 2015, Eni’s total proved reserves amounted to 6,890 mmBOE; proved reserves of subsidiaries totaled 5,975 mmBOE; Eni’s share of reserves of equity-accounted entities stood to 915 mmBOE.

Eni’s strategy in its Exploration & Production operations is to pursue profitable production growth by developing its portfolio of projects underway and by optimizing its current producing fields. We plan to achieve a production growth rate more than 3% on average in the next 2016-2019 four-year period. Our production plans are incorporating our Brent price scenario of 40 $/BBL in 2016 and a gradual recovery in the subsequent years up to our long-term case of 65 $/BBL in 2019 and going forwards (on constant monetary term compared to 2019, i.e. from 2020 onwards crude oil prices will grow in line with a projected inflationary rate); as well as certain other trading environment assumptions including an indication of Eni’s production volume sensitivity to oil prices which are disclosed under "Item 5 – Management’s expectations of operations".

Management plans to achieve the target production growth by continuing development activities and new project start-ups in the main areas of operations including, North Africa, Sub-Saharan Africa, Barents Sea, Kazakhstan, and the Far East, leveraging Eni’s vast knowledge of reservoirs and geological basins, as well as technical and producing synergies. Planned start-ups over the next four years will add more than 800 KBOE/d of new production by 2019; over 90% of these new projects have already been sanctioned and 90% operated.

Management plans to maximize the production recovery rate at our current fields by counteracting natural field depletion and reducing facilities downtime. This will require intense development activities of work-over and infilling and careful planning of maintenance activities. We expect that continuing technological innovation and competence build-up will drive increasing rates of reserve recovery.

Management plans to invest some euro 37 billion to explore for and to develop reserves over the next four years, with a decrease of 18% net of exchange rate effects versus the previous four-year plan to mitigate the impact of a low oil price environment. We plan to prioritize lower intensity projects, brown-field developments and infilling wells mainly in Congo, Angola and Egypt, while we plan to re-schedule spending in some large projects. This re-scheduling will account for half of the overall reduction, while the remaining will be determined by contracts renegotiations.

Exploration projects will attract some euro 3.5 billion with a reduction of 37% net of exchange rate effects in 2016 and 28% over the plan period. Exploration expenditure will be focused on proven plays, near field and appraisal exploration, where we plan to drill 80% of our scheduled wells. The most important amounts of exploration expenditure will be incurred in 2018.

Management intends to implement a number of initiatives to support profitability in its upstream operations by exercising tight control on project time schedules and costs and reducing the time span which is necessary to develop and market reserves. We plan to achieve efficient development of our reserves by: (i) in-sourcing critical engineering and project management activities also redeploying to other areas key competences which will be freed with the start-up of certain strategic projects and increase direct control and governance on construction and commissioning activities; and (ii) signing framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants, increasing focus on supply chain programming to optimize order flows. Based on these initiatives we believe that almost all of our project which we are currently developing over the next four years plan will be completed on time and on cost schedule.

Finally we plan to achieve further cost efficiencies by: (i) increasing the scale of our operations as we concentrate our resources on larger fields than in the past where we plan to achieve economies of scale; (ii) expanding projects where we serve as operator. We believe operatorship will enable the Company to exercise better cost control, effectively manage reservoir and production operations, and deploy our safety standards and procedures to minimize risks; (iii) applying our technologies which we believe can reduce drilling and completion costs; and (iv) renegotiating contracts for oilfield services and other items to reap the benefits of the deflationary trend in the industry.

We plan to mitigate the operational risk relating to drilling activities by applying Eni’s rigorous procedures throughout the engineering and execution stages, by leveraging on proprietary drilling technologies, excellent skills and know-how, increased control of operations and by deploying technologies which we believe to be able to reduce blow-out risks and to enable the Company to respond quickly and effectively in case of emergencies.

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For the year 2016, management plans to spend over euro 8.6 billion in reserves development and exploration projects.

Disclosure of reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil&gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil&gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible 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&gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil&gas reserves can be designated as "proved", the accuracy of any reserves 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 recognize the Profit Oil set contractually (Profit Oil). A similar scheme applies to buy-back and 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 other 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; and (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&gas industry and more than 15 years of experience in evaluating reserves.

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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 companies to carry out an independent evaluation² 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 upon information furnished by Eni, without independent verification, with respect to property interests, production, current costs of operations and development, sales 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, 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, Ryder Scott Company, DeGolyer and MacNaughton and Gaffney, Cline & Associates provided an independent evaluation of approximately 31% of Eni’s total proved reserves at December 31, 2015⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation⁵.

In the 2013-2015 three-year period, 86% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2015, the main Eni properties not subjected to independent evaluation in the last three years were Kashagan (Kazakhstan) and CAFC-MLE (Algeria).

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Summary of proved oil and gas reserves

The tables below provide a summary of proved oil and gas reserves of the Group companies and its equity-accounted entities by geographic area for the three years ended December 31, 2015, 2014 and 2013. Net proved reserves are set out in more detail under the heading "Supplemental oil and gas information" on page F-139.

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