The upstream segment was boosted by exploration successes, which for the 10^th year in a row, delivered outstanding results, once again reaffirming our distinctive skills and know-how.

We added 1 billion boe of equity resources to our portfolio, of which 800 million boe from exploration, at a competitive unitary cost of 1 $/boe.

Since 2014, additions to the Company’s resource backlog were approximately 4 bboe, almost doubling production level of the full period.

Our exploration effort has been equally split between near-field initiatives aiming at quickly supporting production and cash flows leveraging on the proximity to our existing producing facilities and the higher-risk exploration of material resources in new areas or in unexplored geological layers. The results were extraordinary, which underpinned the execution of our Dual Exploration strategy intended to dilute the high working interests retained in exploration assets, with a view of anticipating reserves monetization.

The effectiveness of this strategy has been proved by the sale of a 25% stake in natural gas-rich Area 4 offshore Mozambique to ExxonMobil and a 50% stake of the Zohr gas field offshore Egypt. This latter deal included three separate transaction with BP for the sale of a 10% stake, with the Russian company Rosneft for the sale of a 30% stake and, recently, with Mubadala Petroleum for the sale of a 10% stake. In the last four years, the dual exploration model allowed Eni to early monetize reserves for a total of $10.3 billion.

Eni’s strong leadership in exploration and leading project execution capabilities allowed us to put into production, in less

than three years, seven giant fields, anticipating expected schedules and reducing capex, at a time when the oil&gas industry was mostly concentrated on the postponement of development initiatives.

In 2017, Eni started up four deep-water giant fields: East Hub in Angola, OCTP in Ghana, Jangkrik in Indonesia and Zohr in Egypt, the biggest gas field located in the Mediterranean Sea, in record time for the industry, in less than two years from the FID and only twenty-eight months from discovery.

These outstanding achievements leverage on our integrated model of exploration and development, which enabled us to accelerate the time-to-market of our projects at the same time ensuring control on execution and capex on budget.

The main drivers of this model are: (i) the parallelization of activities; (ii) the modular approach to project spending as to minimize financial exposure; (iii) the insourcing of critical project phases, such as commissioning and hook-up; (iv) the design-to-cost approach whereby exploration areas are selected targeting competitive development costs going forward; (v) the strict control on costs, schedules and project risks; as well as (vi) the retention of the operatorship in most initiatives.

Exploration successes at low unit costs, the reduction in reserves time-to-market and efficiency in operating costs determined the steady downtrend in the full-cycle cost of the barrel produced, which today is well below 30 $/bbl for new projects under execution.

The average hydrocarbon production for the year was 1.82 million barrel/day, marking an all-time high for Eni. This was an increase of 5.3% y-o-y, net of price effects in PSAs and OPEC cuts,

leveraging on start-ups and ramp-ups which added 243 kboe/d on average over the FY. Hydrocarbon production increased by 14% compared to 2014, even reducing capex by 40%.

Exploration successes and time-to-market acceleration, as in the case of the final investment decision for the Coral project in Area 4 in Mozambique in 2017, boosted also this year the reserve replacement ratio at 151%. When considering the reclassification of the Venezuelan reserves to the unproved category following the US SEC rules, the reserve replacement ratio is re-determined in 103%.

In the three-year period 2015-2017, reserve replacement ratio was 120% among the highest in the industry. This, also when considering the assets disposed of under the dual exploration model. The implementation of our dual exploration model with the early monetization of part of our reserves does not jeopardize our future plans in terms of further production growth.

In 2017, leveraging on these drivers, the E&P segment reported an adjusted operating profit of €5.2 billion, more than doubling the 2016 level, and a 38% increase in cash generation to €8.3 billion, even on the backdrop of a 22% reduction in Brent prices in euro terms.

MID-DOWNSTREAM

Progresses in the mid-downstream business restructuring plan enabled us to get record operating profits of the last ten years and to continue in the improvement of cash generation to €7.9 billion in the last three years, compared to an outflow of €3.7 billion in the three-year period 2012-2014.

The G&P segment reported a structurally positive EBIT at €214 million, a year ahead of expectations thanks to progresses

in the renegotiation of long-term gas contracts, logistic optimizations, as well as improved performance in LNG and retail businesses.

The Refining & Marketing and Chemicals businesses reported an operating profit of approximately €1 billion, thanks to the ability to fully capture scenario’s upside, leveraging on the optimization of plants set-up, continuous cost efficiencies and changes in products mix, focusing on high-value product segments.

A further driver of growth and profitability was the value of proprietary technologies such as the recent agreement for the licensing of the heavy crudes refining technology

(EST – Eni Slurry Technology) to the first chemical company, the Chinese Sinopec, as well as the start-up of premium elastomers production applying Versalis’ technology in the Lotte Chemicals JV in South Corea.

SUSTAINABILITY AND HSE

The strong boost to the long-term sustainability of Eni’s business is a key element in the definition and implementation of our strategies.

Eni is investing to improve safety of its people in the workplace, maintaining the leadership in the industry. We delivered solid results in safety with a reduction of 7% to 0.33 in the Total Recordable Injury Rate (TRIR) compared to 2016 and by maintaining best-in-class operational standards, reporting zero blow-out for the fourteenth consecutive year. The second pillar of the sustainable footprint of the Company is our commitment to fighting the climate change. The energy efficiency of our plants (for example upstream GHG

emissions per barrel produced were reduced by almost 3% and routine gas flaring was on an improving trend), adoption of low-emission solutions and the presence of significant gas reserves in our portfolio (among which reserves in Mozambique, Egypt and Indonesia) confirm Eni’s commitment in this direction.

Eni is also engaged in promoting to a significant extent the economic and social development of the communities where we operate, and the Ghana project is one of the most representative of our partnership strategy with producing countries.

In this country, we combine oil production for the international market with gas production entirely addressed to the local market for the development of power generation capacity, thus contributing to a sustainable development.

GROUP RESULTS

In 2017, adjusted operating profit more than doubled to €5.8 billion, with a net profit of €2.4 billion reverting the loss incurred in 2016, thanks to better performances from all business segments.

Cash flow from operating activities was robust at €10 billion, a 25% increase from 2016, when netted of advances cashed in by Egyptian State-owned partners with the aim of financing their capex share in the Zohr project.

These inflows, after funding net capex of €7.6 billion, yielded a surplus of approximately €2.4 billion. This surplus funded approximately 80% of the total amount of the cash dividend (€2.9 billion), at a Brent price scenario of 54 $/bbl.

The organic cash neutrality for funding FY capex and the floor dividend is achieved at 57 $/bbl, better than management’s expectations at 60 $/bbl.

2017 disposals net of the share of the transaction price relating to capex reimbursements amounted to €3.8 billion. When considering this cash inflow, the Brent level at which cash neutrality was achieved in 2017 reduced to 39 $/bbl. As of December 31, 2017, leverage was 0.23, well below the 0.30 threshold notwithstanding price downturn in the last three years and a half and over €11 billion of cash dividend paid in the same period.

OUTLOOK

Looking forward, we expect an ongoing rebalancing of fundamentals in the oil market to consolidate in the next years, due to the sharp slowdown in capex for new initiatives during the downturn and steady growth in demand. Our strategy in the medium-long term is designed to strengthen Eni’s competitive position and cash generation, leveraging on disciplined growth, synergies from businesses integration all along the value chain and technological innovation, pursuing sustainability in all our industrial projects. Operating, economic and financial targets

disclosed below, move towards growth and laid their foundation on the achievements of the last three-year period and on the high level of maturity and robustness of the initiatives in place. For example production rump-ups at fields recently started up, renegotiation of gas supply contracts, a reduced break-even margin in the refining activity, Chemical’s integration and specialization as well as the first projects on renewable sources developed on the basis of a distinctive model.

In the four-year period 2018-2021 we are projecting our capex to be flat versus the previous plan and lower than €32 billion for the development of new hydrocarbon reserves, exploration projects, selective growth initiatives in the mid-downstream businesses and the speed-up of the renewables expansion plan.

This capital budget will be driven by financial discipline, through selective FIDs and a phased approach in the development of giant projects in the upstream business.

In Upstream we intend to maintain strong hydrocarbon production growth, targeting a 3.5% average rate in the four-year plan. Production growth will be fostered by fast ramp-up of projects started up in 2017, mainly Zohr, and new start-ups planned in the next four years, where we have a good level of visibility considering that in many cases we are planning for additional developments at fields already into production.

We can mention the upgrading of the Bahr Essalam and Wafa fields in Libya, the OCTP gas phase, the satellite fields of our producing hubs in Angola, additional development at the Baltim/ Melehia fields in Egypt and Nenè field in Congo, the strengthening of Karachaganak and the start-up of producing activities in Mexico and Merakes in Indonesia. We plan that these initiatives will deliver an overall contribution of about 700 kboe/d in 2021.

In Exploration, we confirm the actions hitherto pursued, by balancing near fields themes with a low risk profile and high risk – high rewards themes, mainly in offshore Mexico, East and West Africa, east of Mediteranean Sea and Middle and Far East. Our target is to discover approximately 2 billion boe of new resources in the plan period.

In the Gas&Power segment, on the back of a challenging scenario, we intend to underpin profitability and cash generation through the strengthening of the core business gas and the development in the integration with the upstream business. Industrial actions will aim at valuing flexibility of our asset portfolio (contracts, infrastructures, delivery options, etc.), reducing logistic costs and obtaining a fair distribution of price/volume risks with long-term suppliers through a new round of renegotiations.

Expected results will be fuelled by a relevant contribution from growth in LNG and trading businesses, by seizing synergies from the availability of equity production in strategic areas

and long-term relationships with producing countries in the upstream business.

Furthermore, the strategic plan foresees a further improvement in the retail segment of the Gas & Power business, to be achieved through the development of customer portfolio and offering value-added services.

In the R&M and Chemical businesses, main targets related to the improvement in the resilience to the volatility of scenario and the selective international growth.

The strategic levers will be the growth in the bio-fuels, with the completion of the green refinery in Gela by the end of 2018 and the upgrade of the green refinery in Venice, as well as the further development of “differentiated products” and the biochemical in Versalis.

Results will be sustained by plant set-up optimization and the supply of feedstocks, also in terms of higher sustainable actions (for example the substitution of palm oil), new efficiency actions and the steady attention to assets reliability and integrity.

In the refining activity, we intend to reduce the break-even margin to approximately 3 $/barrel by the end of 2018, and in marketing, we plan to consolidate our position in our main geographies. All the mentioned targets and actions have been tested to prove their medium to long-term sustainability in line with Eni’s low carbon strategy.

In the upstream business, we have designed initiatives

to achieve the ambitious 2025 targets of zero flaring gas, corresponding to a reduction of 43% from 2014 baseline of the emissions per barrel produced and 80% of the fugitive emissions of methane.

We expect to speed up the development of renewable sources business, planning 2018-2021 capex for more than €1.8 billion, including the R&D expenditure, to reach an installed capacity of 1 GW at the end of the plan period.

The industrial projects in the R&M and Chemicals segments are all targeting to reach a higher level of energy efficiency and strengthen the green platform. These actions, together with the increasing role played by natural gas in Eni’s portfolio and the steady reduction in the average price break-even price of upstream projects, will confirm the resiliency of our portfolio even in more conservative energy scenarios.

All in all, the actions identified in the industrial plan will underpin a strong cash generation and a reduction in the Brent price for the organic cash neutrality, after paying capex and dividend. In light of these results, the Board of directors will propose to the Annual Shareholders’ meeting the distribution of a final dividend of €0.80 per share, of which €0.40 already paid as interim dividend in September 2017. Going forward leveraging the results achieved and the company’s growth prospects, we plan to increase our 2018 dividend to €0.83 per share, in line with our commitment to a progressive remuneration policy linked to our underlying results and free cash flow growth.

Adjusted results

Adjusted operating profit more than doubled to €5.80 billion (up by €3.49 billion vs. 2016), adjusted net profit of €2.38 billion compared to the loss reported 2016. This recovery in profitability was underpinned by the implementation of strategic drivers focused on upstream profitable growth, the turnaround and cost efficency initiatives in the mid-downstream business, leveraging on the scenario recovery.

Upstream

Adjusted operating profit doubled vs. 2016 to €5.2 billion.

Turnaround in the mid-downstream

Adjusted operating profit increasing by €1 billion in 2017:

Net capital expenditure 

€7.6 billion, reducing by 18% vs. 2016. Self-financing ratio of net capex at approximately 130%.

Cash neutrality

Organic cash neutrality covering capex and dividend at a Brent price of 57$/bbl; 39$/bbl, factoring in proceeds from disposals.

Gearing and Leverage

Eni confirms a solid financial structure with a gearing of 18%, the lower end of the European peer group and a leverage of 23%, leveraging on the excellence in operating cash flow generation, capex optimization and gains from disposals.

Dividend

The Company’s robust results and strong fundamentals underpin a dividend distribution of €0.80 per share of which €0.40 per share paid as interim dividend in September 2017.

Dual Exploration Model

Closed the 40% disposal of the super-giant Zohr gas field in Egypt offshore – through two different transactions with BP (10%) and Rosneft (30%) – and the 25% disposal of Area 4 in Mozambique to ExxonMobil. In March 2018, signed an agreement with Mubadala Petroleum for the divestment of a further 10% interest in Zohr.

Hydrocarbon production at record level

1.82 million boe/d, the highest ever level, with a 5.3% growth vs. 2016. Start-ups and ramp-ups additions of 243 kboe/d leveraged on Eni’s exploration and development integrated model, designed to optimize new projects’ time-to-market (Zohr in Egypt, East-Hub in Angola, OCTP in Ghana, Jangkrik in Indonesia, all in 2017) and on accelerate fields ramp-ups (Noroos).

Zohr development

Achieved production start-up at the super-giant Zohr gas field in record time-to-market: in less than two years from the FID and two and a half years from discovery.

Exploration resources

In 2017 added 1 bln boe of new resources, of which 0.8 bln boe from in house exploration with a discovery cost of approximately 1 $/bbl.

Mexico

Successfully completed the exploration campaign offshore Area 1, thanks to the appraisal of Tecoalli discovery which followed that of Amoca and Miztòn, resulting in a rise in estimated hydrocarbons in place of the Area to 2 bln boe, of which approximately 90% oil. Scheduled a fast-track development plan.

Exploration portfolio

Reloading of approximately 97,000 square kilometers of new acreage:

Proved hydrocarbon reserves

7 billion boe with an organic replacement ratio of 103%. The ratio increases to 151% when excluding the reclassification of PUD reserves to the unproved category in Venezuela in accordance with the applicable US SEC regulation.

Coral project

Sanctioned by the partners the development project for the exclusive reserves in Area 4 in Mozambique amounting to 16 TCF in place. The Floating LNG facilities construction will be realized through a multi-source project financing of $4.7 billion.

International development in the Chemical business

Completed, in South Korea, the construction of the industrial complex for production of premium elastomers, leveraging on Versalis technology and through the 50:50 joint venture Versalis – Lotte Chemical, local operator.

Licensing EST technology

Enhanced the refining know-how through two licensing agreements with the Chinese companies Sinopec and Zhejiang Petrochemicals for the use of the Eni Slurry Technology (EST) conversion proprietary technology.

Renewable energies

Eni’s committment for renewable energies was implemented by the start-up of operations for the set-up of plants in Italy and Algeria and the development of other initiatives in Italy and abroad. Signed the collaboration agreement with General Electric and with the Kazakh Ministry of Energy; finalized a Memorandum of Understanding with the Egyptian Ministry of Electricity to jointly realize new renewable plants.

Safety of Eni’s people

Total recordable injury rate (TRIR) reported a decrease of 6.8% vs. 2016. The reduction for the employees (down by 17.2%) and the contractors (down by 2%) was driven by specific program of education and awareness addressed to Eni’s people. In 2017, was launched the new Safety Training Center in Gela for training in health, safety and environmental issues.

Climate change 

Accordingly to Eni’s carbon footprint reduction strategy, the development program on renewables was implemented by 20 projects on an executive phase or near to FID, which will contribute to increase Eni's generation capacity by around 250 MW. Furthermore, Eni is part of the TCFD (Task Force on Climate-related Financial Disclosures) of the Financial Stability Board, targeted to a more trasparent disclosure about risks and opportunities relating to the climate change.

Commitment to flaring reduction 

Eni joins the Global Gas Flaring Reduction Partnership (GGFR), sponsored by the World Bank, a public-private initiative involving international oil companies, governments and international institutions. Eni reduced gas flaring of approximately 68% in the last ten years and promoted access to energy for over 18 million people in the Sub-Saharan Africa.

GHG emissions 

GHG emissions increased by 2.5% vs. 2016 due to the production growth. GHG emission index per barrel produced was down by approximately 3% vs. 2016 and by 19% vs. 2014 in accordance with the long-term target of a 43% reduction by 2025.

Oil spills due to operations

Oil spills due to operations (higher than one barrel), 94% of which relating to the E&P segment, more than doubled from 2016. This was mainly due to the spill from a tank located in COVA in Val d’Agri where the Company implemented all the remediation actions to reduce the environmental damage and to prevent any future accident through infrastructure upgrading.

Human rights

Started in 2017 the working group on Human Rights in the business supported by the Danish Institute for Human Rights. The comparison between Company’s processes and the International Standards (UN Guiding Principles on Business and Human Rights) allowed the definition of a roadmap aimed at further improvement of Eni’s performance on Human Rights.

ANALYSIS OF SUSTAINABILITY SCENARIO

Analysis of the context in which Eni operates, highlighting the emerging issues of sustainability, the relevant issues and the progress compared to the targets set. This scenario analysis is presented and examinated in the Sustainability and Scenarios Committee and approved by Eni’s Board of Directors.

RISK ASSESSMENT RESULTS

Identify the main Eni’s risks including those with potential impacts on environment, health and safety, social and reputational aspects.

STAKEHOLDERS' PERSPECTIVE 

This process identifies key issues for different stakeholders designed in accordance to the international standards such as the Global Reporting Initiative, (GRI), Accountability AA1000 and the IFC guidelines "Stakeholder Engagement: A Good Practice Handbook for Companies Doing Business in Emerging Markets" which considers the potential impacts on stakeholders referring to environmental, social and governance issues (ESG).

Eni’s business model is focused on creating long-term value, for both the company and its stakeholders, through the achievement of goals relating to profitability and growth, efficiency, operational excellence and prevention of business risks. Eni recognizes that the main challenge in the energy sector is providing access to energy resources for all efficiently and sustainably, while combating climate change.

To meet this challenge, Eni has adopted an integrated strategy to pursue its operating objectives, combining financial robustness with social and environmental sustainability, based on:

Accordingly, support for countries’

development in order to promote efficient and sustainable access to energy resources for all, valuing people, environmental protection, combating climate change, safeguarding health and safety, respect for human rights, ethics

and transparency are fundamental values integrated within the Eni business model. The Eni Board of Directors has always played a central role in the definition of sustainability policies and strategies, and also in the validation of relative results.

While carrying out the related duties, the Board is supported by the Sustainability and Scenarios Committee, established by the Board of Directors in 2014. The importance that Eni places on this area is demonstrated

by the fact that, once again in 2017, the CEO’s variable Incentive Plan and those for all managers with strategic responsibilities include sustainability objectives. In order to pursue these objectives, Eni has

set-up organizational and management models, operating tools and cross-functional working groups for the various sustainability areas, as set out in the table on the following page.

Companies operating in the energy sector face with two challenges: satisfy growing energy needs, working to build a future in which everyone can access to the energy sources in an efficient and sustainable way and limit their emissions in the atmosphere, contributing to the gradual path to decarbonization, in accordance with the decision taken in COP, starting from Paris 2015.

In 2040 the world population is expected to grow from 7 million to 9 million and the energy demand will increase by approximately

30%. There will be also a geographical shift in consumption and 70% of energy demand will come from non-OECD countries, representing approximately 85% of worldwide population.

In this context, natural gas represents an opportunity for a strategic repositioning of the oil companies thanks to lower carbon intensity and the possible integration with renewable sources in the electricity production. There is a growing awareness on the needs to promote policies aimed at replace coal in electricity generation.

The 2018-2021 industrial plan includes a gradual increase in Brent price scenario up to the balance long-term value of 72 $/bbl, in line with the market fundamentals trend.

Our deep transformation process of Eni's business model was implemented in the 2014-2017 period. As a result of this, we have set a company strongly integrated in the oil&gas value chain, strengthened and constantly growing in the upstream business, completed the turnaround in the mid-downstream business and more focused on the robustness of the financial structure. This process has been supported by organizational initiatives aimed at a more effective integration in the different company's function.

Operating, economic and financial goals of the 2018-2021 plan target the development and the value growth in all businesses by leveraging the high level of maturity and soundness due to the advanced actions planned, such as: production ramp-ups of the fields lately started up, progress of planned project sanction to support production start-up, renegotiation of long-term supply

contracts, LNG contracted volumes, reduced break-even level of refining activities, integration and specialties growth in the chemical business as well as our path to decabornization and development of the green businesses based on a distinctive model.

Another key driver of our plan is the dissemination of digital technology to catch development, efficiency and work-safety opportunities.

The low break-even of capex in execution phase, economic, financial and technical discipline as well as the decrease in activity of environmental impacts together with the improving Eni's portfolio integration, will allow to catch addition value and allowed the Company Eni to be more financial resilient and robust. In the 2018-2021 period, our cash neutrality (capex and dividend) targets are improving than the previous plan; in particular, in 2018, we plan a cash neutrality at a Brent price of approximately 55 $/bbl and decline to 50 $/bbl at the end of the plan period due to a growth in all businesses and the ongoing capex discipline.

2017, the year of rebalancing

In 2017, after three years of oversupply, OPEC and non-OPEC cuts in production and the strong demand led to rebalancing. At the end of 2017, OECD total stocks were near to the last 5 year average volumes, in line with the OPEC target. Geopolitical crises came back to play upward. In contrast, the growth of tight oil in the USA fuelled high volatility phases: notwithstanding a growth rate lower than the ones recorded during the boom years, the short-cycle nature of tight oil and the international export of crudes from the USA are the main volatility drivers for the market. 2017 average Brent price was 54.3 $/bbl (up 10 $/bbl vs. 2016), exceeding the 65 $/bbl threshold at the end of the year.

OPEC strategy addressing 2018 scenario

Expected cuts in 2018 and subsequent market control strategy by OPEC will support in 2018, driven also by widespread geopolitical crisis, primarily in Venezuela where production levels reached thirty years ago level. Capital expenditure discipline of

Capital expenditure discipline of the last two years will allow to maintain high prices, determining a gap from expected demand.

A better context in the mid-downstream industry

In Europe the rationalization process started in 2008 until the end of 2014, with margins and commodity demand recovery.

In 2017, in a trading scenario characterised by high margins, there were no reductions of capacity, despite the increase in Brent price. In the next years, European refining industry is expected to continue benefitting from demand growth and the IMO impact at 2020, which would foster the profitability of complex refineries in place of simple ones subject at risk of shut-down. However, European refiners will be less penalized because of already achieved capacity reduction. In the refinery business, Europe is expected to remain a marginal refiner in a global market of high competition from operators located in the Middle East, the USA, Russia and Asia, which leverage on competitive advantages in terms of supply cost and efficiency.

In light of the progress in all businesses and the expected growth in the next four-year plan, Eni intends to increase the cash dividend to €0.83 per share. Eni is committed to a progressive remuneration policy linked to our underlying earnings and free cash flow growth. Share buy-back remains a flexible way to return to shareholders the cash in excess of the leverage target (0.20-0.25).

| Focus on decarbonization

Eni defined a path to decarbonization and implemented a clear and defined climate strategy, integrated with its own business model. lt is based on the following pillars: 

to €0.6 billion in 2018-2021 at 100% and with relate only to upstream operated activities;

The IRM Model is characterized by a structured approach, based on international best practices and considering the guidelines of the Internal Control and Risk Management System (see page XX), that is structured on three control levels. Risk Governance attributes a central role to the Board of Directors (BoD) which defines the nature and level of risk in line with strategic targets, including in evaluation process all those risks that could be consistent for the sustainability of the

business in the medium-long term. 

The BoD, with the support of the Control and Risk Committee, outlines the guidelines for risk management, so as to ensure that the main corporate risks are properly identified and adequately assessed, managed and monitored.

For this purpose, Eni’s CEO, through the IRM process, presents every three months a review of the Eni’s main risks to the Board of Directors. The analysis is based on the scope of the work and risks specific of each

business area and processes aiming at defining an integrated risk management policy; the CEO also ensures the evolution of the IRM process consistently with business dynamics and the regulatory environment. Furthermore, the Risk Committee, chaired by the CEO, holds the role of consulting body for the latter with regards to major risks. For this purpose, the Risk Committee evaluates and expresses opinions, at the instance of CEO, related to the main results of the IRM process.

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

The process, regulated by the “Management System Guideline (MSG) Integrated Risk Management” published on July 2016, has been revised to strengthen the integration with the decision-making process. The IRM process includes six sub-processes: (i) risk management guidelines, (ii) risk strategy, (iii) risk assessment & treatment, (iv) risk monitoring, (v) risk reporting, and (vi) risk culture.

It takes a top-down and risk-based approach, starting from the definition of Eni’s Strategic Plan (risk strategy), by identifying specific de-risking targets, the analysis of the underlying risk profile of the Plan, also through stress test for economic-financial resiliency vs. strategic targets, as well as the identification of strategic treatment actions. These activities performed coherently and integrated with the strategic planning process, support

the Board's assessments regarding the acceptability of the risk profile of the strategic plan subject to his attention.

The process continues with the periodic cycles of risk assessment & treatment and monitoring, the profile analysis on specific risks of the relevant transactions, as well as the integrated analysis on the risks in common with certain business and/ or functions. The risk evaluation is carried out through metrics considering both potential quantitative (financial-economic or operations) and qualitative (like environment, health and safety, social, reputation, etc.) aspects. The prioritization is based on a multi-dimensional matrices that allows to obtain the risk level as combination of probability cluster and impact cluster.

All risks are evaluated and expressed following an inherent and a residual level (taking into account the implemented actions of mitigation). Eni’s top risks portfolio consists of 20 risks classified in: (i) external risks, (ii) strategic risks and, finally, (iii) operational risks (see Objectives, risks and treatment actions on the following pages). In 2017, two-assessment session were performed: the Annual Risk Profile Assessment performed

in the first half of the year, involving 81 subsidiaries in 28 countries and the Interim Top Risk Assessment performed in the second half of the year, relating to the update of the evaluation and treatment of Eni’s top risks and main business risks. The second assessment also revaluated certain main risks to the business level. The two-assessment results were submitted to Eni's management and control bodies in July and December 2017.

In addition, three monitoring processes were performed on top risks. The monitoring of such risks and the relevant treatment plans allow to analyze the risks evolution (through update of appropriate indicators) and the progress in the implementation of specific treatment measures decided by management.

The monitoring results were submitted to the management and control bodies in March, July and October 2017.

In the second half of 2017, IRM function provides the identification of specific de-risking objectives of the main corporate and business risks, issued as part of the 2018-2021 Guidelines by CEO, and identifies the chapters of the Strategic Plan 2018-2021 related to risk factors (business and consolidated risks), including mitigation actions.

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

Ongoing, transparent communication with stakeholders is an essential tool for better

understanding their needs. It is part of our efforts to ensure the effective exercise of shareholder rights. 

With this in mind, recognising the need for a deeper dialogue with the market, in 2017 Eni organised a new cycle of “corporate governance roadshows” involving the Chairman of the Eni Board of Directors with the main institutional investors of Eni to present the Company’s governance system and main initiatives in the fields of sustainability and corporate social responsibility.

The initiative was much appreciated by the investors, who welcomed the open and constructive dialogue forged with

the Company. In particular, the investors applauded the composition of the Board of Directors, including its diversity, the governance measures adopted and the completeness and transparency of the information provided to shareholders and the market as a whole. In addition, during the meetings the investors displayed considerable interest in developments in the governance of risks and the control system, including compliance, the associated organisational arrangements and the leading role reserved for the Board and the Chairman in the system. Additional events were held in early 2018.

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

Eni’s Board of Directors and Board of Statutory Auditors, and their respective Chairmen, are elected by the Shareholders’ Meeting using a slate voting mechanism. Three directors and two statutory auditors, including the Chairman of the Board of Statutory Auditors, are elected by non-controlling shareholders, thereby giving minority shareholders a larger number of representatives than that provided for under law. The number of independent directors provided for in the Eni By-laws is also greater than the number required by law.

In April 2017, the Shareholders’ Meeting re-elected 8 of the 9 directors from the previous term. With regard to the Board

of Statutory Auditors, 2 of the 5 previous statutory auditors were reappointed.

As with the appointments made in 2014, in deciding the composition of the Board of Directors, the Shareholders’ Meeting was able to take account of the guidance provided to investors by the previous Board with regard to diversity, professionalism, management experience and international representation. The outcome was a balanced and diversified Board of Directors. 

The composition of the Board of Directors and of the Board of Statutory Auditors is also more diversified in gender terms, in accordance with the provisions of applicable law and the By-laws.

Moreover, the number of independent directors on the Board of Directors (7² of the 9 serving directors, of whom 8 are non-executive directors) remains greater than the number provided for in the By-laws and in the Corporate Governance Code. 

The Board of Directors appointed a Chief

Executive Officer and established four internal committees with advisory and recommendation functions: the Control and Risk Committee³, the Compensation Committee⁴, the Nomination Committee and the Sustainability and Scenarios Committee. The Committees report, through their Chairmen, on the main issues they address at each meeting of the Board of Directors.

The Sustainability and Scenarios Committee, which was retained by the Board of Directors for the new term as well, has a key role in addressing sustainability issues, which are considered an integral part of the decisions of the Board, incorporated in the Company’s business model.

In addition, at its meeting of July 27, 2017, the Eni Board of Directors established an Advisory Board⁵, charged with analysing major geopolitical, technological and economic trends, including issues associated with decarbonization, in support of the Board itself and of the Chief Executive Office.

The Board of Directors also retained the Chairman’s major role in internal controls, with specific regard to the Internal Audit unit. The Chairman proposes the appointment and remuneration of its Head and the resources available to it, and also directly manages relations with the unit on behalf of the Board of Directors (without prejudice to the unit’s functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system). The Chairman is also involved in the appointment of the primary Eni officers responsible for internal controls and risk management, including the officer in charge of preparing financial reports, the

members of the Watch Structure, the Head of Integrated Risk Management and the Head of Integrated Compliance, which report directly to the Chief Executive Officer, including in his capacity as the director in charge of the internal control and risk management system of Eni. Finally, the Board of Directors, acting on a recommendation of the Chairman, reappointed the Secretary, keeping his role as Corporate Governance Counsel, charged with providing assistance and advice to the Chairman, the Board of Directors and the individual directors, reporting periodically to the Board of Directors on the functioning of Eni’s corporate governance system.

This report enables the periodic monitoring

of the governance model adopted by the Company, designed on the basis of the most prominent studies in this field, the choices of our peers and the corporate governance innovations incorporated in the corporate governance codes of other countries and in the principles issued by leading international bodies, identifying any strengths and areas for additional improvement in the Eni system. In view of this role, the Secretary, who reports to the Board of Directors itself and, on its behalf, to the Chairman, must also meet appropriate independence and other requirements⁶. The following chart summarises the Company’s corporate governance structure at December 31, 2017:

The Board of Directors entrusts the management of the Company to the Chief Executive Officer, while retaining key strategic, operational and organizational powers for itself, especially as regards governance, sustainability⁷, internal control and risk management.

In recent years, the Board of Directors has devoted special attention to the Company’s organizational arrangements, with a number of important measures being taken with regard to the internal control and risk management system. More specifically, the Board decided that the Integrated Risk Management function reports directly to the Chief Executive Officer and created an Integrated Compliance Department, also reporting to the Chief Executive Officer, separate from the Legal Department.

Among the Board of Directors’ most important duties is the appointment of people to key management and control positions in the Company, such as the officer in charge of preparing financial reports, the Head of Internal Audit, the members of the Watch Structure and the Guarantor of the Eni Code of Ethics. In performing these duties, the Board of Directors may draw on the support of the Nomination Committee.

In order for the Board of Directors to perform its duties as effectively as possible, the directors must be in a position to assess the decisions they are called upon to make, possessing appropriate expertise and information. The current members of the Board of Directors, who have a diversified

range of skills and experience, including on the international stage, are well qualified to conduct comprehensive assessments of the variety of issues they face from multiple perspectives. The directors also receive timely, complete briefings on the issues on the agenda of the meetings of the Board of Directors.

To ensure this operates smoothly, Board meetings are governed by specific procedures that establish deadlines for providing members with documentation, and the Chairman ensures that each director can contribute effectively to Board discussions. The same documentation is provided to the Statutory Auditors.

In addition to meeting to perform the duties assigned to the Board of Statutory Auditors by Italian law, including in its capacity as the “Internal Control and Audit Committee”, and by US law in its capacity as the “Audit Committee”, the Statutory Auditors also participate in the meetings of the Board of Directors and the Control and Risk Committee to ensure the timely exchange of key information for the performance of their respective duties within the Company’s internal control and risk management system.

On an annual basis, the Board of Directors, with the support of an external advisor and the oversight of the Nomination Committee, conducts a self-assessment (the Board Review)⁸, for which benchmarking against national and international best practices and an examination of Board dynamics are essential elements. Following the

Board Review, the Board of Directors develops an action plan, if necessary, to improve the operation of the Board and its Committees. On the basis of the experience of the Board of Directors, the Board of Statutory Auditors also elected to conduct its own self-assessment. In addition, in determining the procedures for the performance of the Board Review, the Eni Board also assesses whether to perform a “Peer Review” of the Directors, in which each director expresses his or her view of the contribution made by the other Directors to the work of the Board. The Peer Review, which has been conducted four times in recent years, most recently in February 2018 in conjunction with the Board Review, is an important innovation among Italian listed companies.

In addition, as noted previously, bearing in mind the outcome of the self-assessment, the Board, subject to assessment by the Nomination Committee and prior to election of the Board itself, provided the shareholders with guidance on the managerial and professional profiles it felt should be present on the Board.

For a number of years now, Eni has supported the Board of Directors and the Board of Statutory Auditors with an induction programme, which involves the presentation of the activities and organization of Eni by top management. More specifically, with the start of the new term, in continuity with previous initiatives, additional training sessions were held on corporate topics and business issues, sessions that included visits to operational sites.

Eni’s Remuneration Policy for its Directors and top management is established in accordance with the Governance model adopted by the Company and the recommendations of the Corporate Governance Code. The Policy seeks to retain with high-level professionals and skilled managers and to align the interests of management with the priority objective of creating value for shareholders over the medium/long-term.

Under Eni Remuneration Policy relating to executive roles, considerable importance is given to the variable component, also on a per-share basis, which is linked to the achievement of preset performance and financial targets, business development and operational objectives, also considering the long-term sustainability of the results,

in line with the Company’s Strategic Plan. For this purpose, the remuneration of Eni’s top management is established on the basis of the position and the responsibilities assigned, with due consideration given to market benchmarks for similar positions in companies similar to Eni in dimension and complexity. Remuneration is composed of a balanced mix of fixed and variable elements. In particular, the variable remuneration of Eni’s executive officers having a greater influence on the business performance is characterized by a significant percentage of long-term incentive components, driven by proper deferral periods and/or at least three-year vesting period to reflect the long-term nature of the business and the related risk profiles.

With regard to sustainability issues, the

CEO objectives set for the year 2018, are focused on environmental matters as well as on human capital aspects.

The objectives of the Chief Officers of Eni business segments and other Managers with strategic responsibilities are assigned on the base of those assigned to top management focused on stakeholders’ perspectives, as well as on individual objectives assigned in relation to the responsibilities inherent the single managerial position, under the provisions of Company’s Strategic Plan.

The Remuneration Policy is described in the first section of the Remuneration Report, available on the Company’s website (www.eni.com) and is presented, on an annual basis, for an advisory vote at the Shareholders Meeting⁹.

Eni has adopted an integrated and comprehensive internal control and risk management system based on reporting tools and flows that, involving all Eni personnel, reach all the way up to the top management of the Company and its subsidiaries. The members of the Board, as well as the members of the other corporate bodies and all Eni personnel, are required to comply with Eni’s Code of Ethics (as an essential part of the Company’s Model 231), which sets out the rules of conduct for the fair and proper management of the Company’s business.

Eni adopted a regulatory instrument for the integrated governance of the internal control and risk management system, the

guidelines of which, approved by the Board, set out the duties, responsibilities and procedures for coordinating between the primary system actors.

An integral part of the Eni internal control system is the internal control system for financial reporting, the objective of which is to provide reasonable certainty of the reliability of financial reporting and the ability of the financial report preparation process to generate such reporting in compliance with generally accepted international accounting standards.

Eni’s CEO and Chief Financial Officer (CFO) are responsible for planning, establishing and maintaining the internal control system for financial reporting. The CFO also

serves as the officer in charge of preparing financial reports.

A central role in the Company’s internal control and risk management system is played by the Board of Statutory Auditors, which in addition to the supervisory and control functions provided for in the Consolidated Law on Financial Intermediation, also monitors the financial reporting process and the effectiveness of the internal control and risk management systems, consistent with the provisions of the Corporate Governance Code, including in its capacity as the “Internal Control and Audit Committee” pursuant to Italian law and as the “Audit Committee” under US law.

production sites and programs to improve plant set-up. These results confirm that we are well on track on our long-term targets of a reduction of 43% in 2025 vs. 2014.

by the recovery in crude oil prices (with the Brent price up by 24%), production growth and significant reduction of tax rate.

reference Brent price of $54 per barrel. The organic reserves replacement ratio was 103%. The ratio increased to 151%

when excluding the reclassification of proved undeveloped reserves in Venezuela to the unproved category in

accordance with the applicable US SEC regulation. The reserves life index was 10.5 years (11.6 years in 2016).

Eni achieved production start-up of the super-giant Zohr gas field in a record time-to-market, in less than two years from the FID and two and a half years from discovery. The Zohr project is one of Eni's seven record-breaking project that were

performed by means of the achievement of integrated model of exploration and development implemented over the last few years. Leveraging on parallelizing exploration, appraisal and development phases, we achieve a faster time-to-market

and a lower cost to production start-up of discoveries. The Zohr discovery is located in the Shorouk offshore block (Eni operator with a 60% interest) in Egypt offshore with estimated resources of over 30 TCF gas in place (approximately 5.5 billion boe).

The Dual Exploration Model is a pillar of Eni's strategy which aims to create cash flow in advance of exploration successes by means of the partial diluition of the stakes in exploration leases where Eni retains the operatorship and control of the asset. During the year the following

dispoals were closed with this approach: 

interest. The transaction is subject to the fulfillment of certain conditions and all necessary authorizations from Egypt’s Authorities;

technical and environmental areas such as the Caspian basin.

in estimated hydrocarbons in place of the block to 2 billion boe, of which approximately 90% oil. Eni submitted an integrated development plan of all the three discoveries to the relevant Authorities. Production start-up is expected in 2019.

Egypt, Libya and Ivory Coast as well as related to the completion of the 25 new exploratory wells (15.9 net to Eni).

In addition, 78 exploratory drilled wells are in progress at year-end (41.2 net to Eni).

oil basin few explored in the north of the country, where Eni will leverage on the mining knowledge acquired in exploration and development activities progressed in nearby areas of the Republic of Congo. In case of exploration success, the block will benefit from the existing infrastructures. In addition, Eni and Sonangol signed a Memorandum of Understanding to define joint projects throughout the value chain of the energy sector.

of energy from renewable sources leveraging all the industrial, logistic, contractual and commercial synergies. Eni's commitment to achieve these targets is confirmed by the recent agreements in Algeria, Angola and Ghana as well as by ongoing projects in particular in Mozambique, Egypt and Indonesia.

RESERVES

OVERVIEW¹ 

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

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

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

RESERVES GOVERNANCE

Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production segment is in charge 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 regulations².

D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by others entities, Eni estimates its share of proved reserves on the basis of the above guidelines.

The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department and the operations unit at the head office verify the production profiles of such properties where significant changes have occurred and operating expenses, respectively; (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 Physics Degree in 1988. He has more than 25 years of experience in the oil and gas industry and more than 15 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested by the role and complies with the required 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 evaluation³ 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 report⁴. 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, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/ gas/water production/injection data of wells, reservoir studies, technical analysis relevant to field performance, development plans, future capital and operating costs.

In order to calculate the net present 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 2017⁵, Ryder Scott Company and DeGolyer and MacNaughton confirmed, as in previous years, the fairness of Eni internal evaluation.

In particular, in 2017 approximately 29% of Eni's total proved reserves were subject to independent evaluation at December 31, 2017⁶. In the 2015-2017 three-year period, 96% of Eni total proved

reserves were subject to independent evaluation. As of December 31, 2017, the principal Eni property, which did not undergo an independent evaluation in the last three years, was Blacktip (Australia).

MOVEMENTS IN NET PROVED RESERVES

Eni's net proved reserves were determined taking into account Eni's share of proved reserves of equity-accounted entities. Movements in Eni's 2017 proved reserves were as follows:

Net proved reserves as of December 31, 2017 were 6,990 mmboe, of which 6,430 mmboe of consolidated subsidiaries. Organic additions to proved reserves were 999 mmboe. These additions were partly offset by the reclassification of 315 million boe of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC regulation. Net organic additions in 2017 were 684 mmboe and derived from: (i) extensions and discoveries were up by 483 mmboe mainly due to the final investment decisions made for the Coral project offshore Mozambique and the Johan Castberg project offshore Norway; (ii) revisions of previous estimates were up by 181 mmboe and derived from progress in development activities at the following projects such as Zohr in Egypt, Jangkrik in Indonesia and Kashagan in Kazakhstan partly offset by the reclassification of PUD in Venezuela, as above-mentioned; and (iii) improved recovery were 20 mmboe mainly reported in Iraq and Egypt.

All sources additions were marginally impacted by unfavourable price effect, leading to a downward revision of 7 mmboe, due to an increased

Brent price used in the reserves estimation process up to $54.4 per barrel in 2017 compared to $42.8 per barrel in 2016.

The organic reserves replacement ratio⁷ was 103%. The ratio increased to 151% when excluding the reclassification of PUD in Venezuela. Adjusted all-sources replacement ratio was 77% considering the disposal of a 25% interest in Area 4 offshore Mozambique, while the divestment of a 40% stake in Zohr, substantially finalized in 2016, is considered in reduction of the reserves opening balance. The reserves life index was 10.5 years (11.6 years in 2016).

PROVED UNDEVELOPED RESERVES

Proved undeveloped reserves as of December 31, 2017 totalled 2,629 mmboe, of which 1,159 mmbbl of liquids mainly concentrated in Africa and Asia and 8,021 bcf of natural gas mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,042 mmbbl of liquids and 7,755 bcf of natural gas. Movements in Eni's 2017 proved undeveloped reserves were as follows:

In 2017, total proved undeveloped reserves decreased by 586 mmboe mainly due to: (i) progress in maturing PUD to proved developed (down by 489 mmboe); (ii) extensions and discoveries (up by 483 mmboe) due to the FID made for the Coral project offshore Mozambique and the Johan Castberg project offshore Norway; (iii) reclassification of 315 million boe of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC regulation; (iv) revisions of previous estimates (up by 240 mmboe) mainly reported in Egypt due to the development activity of the Zohr project; (v) improved recovery (up 18 mmboe) in particular Iraq and Egypt; and (vi) divestments (down by 523 mmboe) related to Mozambique and Egypt disposals, as mentioned above.

During 2017, Eni converted 489 mmboe of proved undeveloped reserves to proved developed reserves due to the progress of the development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Zohr (Egypt), Jangkrik (Indonesia); Cabaca South East (Angola), Sankofa (Ghana) and Nené (Congo).

In 2017, capital expenditure amounted to approximately €7.1 billion.

Most proved undeveloped reserves are converted to proved developed reserves within five years. Reserves that remain proved undeveloped for five or more years are a result of several physical factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1 bboe of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.2 bboe), related to forthcoming development phases (for further information see Main exploration and development projects - Kashagan); (ii) the Zubair field in Iraq (0.2 bboe).

Zubair is an infrastructure-driven large scale project, where the development of PUDs has been conditioned by the completion of such infrastructures. The large part of the planned expenditures for such project have already been made by Eni and the installation of the production facilities required to achieve and maintain the full field production plateau of 700 kbbl/d is almost complete. Eni's planned conversion activities contemplate the drilling of additional production and injection wells to be linked to the facilities currently in place; (iii) the Junin 5 field in Venezuela (0.1 bboe) where the development activities concerned several optimization activities which are not expected to involve high technical complexities; and (iv) certain Libyan gas fields (0.5 bboe) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force.

DELIVERY COMMITMENTS

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

Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 534 mmboe from producing assets located mainly in Algeria, Australia, Egypt, Indonesia, Libya, Nigeria, Norway and Venezuela.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company's proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 88% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2017.

In 2017, oil and natural gas production averaged a record level of 1,816 kboe/d, up by 3.2%. This performance was driven by new project start-ups and the ramp-ups at fields started up in 2016, mainly in Angola, Egypt, Ghana, Indonesia and Kazakhstan as well as by restarting production at certain Libyan fields thanks to better safety conditions. These positive results were partly offset by OPEC production cuts, negative price effects at PSAs contracts and lower production as a result of planned and unplanned shutdowns in Norway, the United Kingdom and the Gulf of Mexico, as well as declines from mature fields. When excluding price effects at PSAs contracts and OPEC cuts (overall 35 kboe/d), hydrocarbons production increased by 5.3%. The share of oil and natural gas produced outside Italy was 93% (92% in 2016).

Liquids production (852 kbbl/d) decreased by 26 kbbl/d, or 3% from the full year of 2016. Price effect, OPEC cuts and shutdowns

in Norway, the United Kingdom and the Gulf of Mexico were partly offset by start-ups and ramp-ups of the year mainly in Angola, Ghana and Kazakhstan as well as higher production in Libya. Natural gas production (5,261 mmcf/d) increased by 454 mmcf/d, or 9.6% compared to the full year of 2016. Start-ups and ramp-ups of producing assets in Indonesia and Egypt and the increasing production in Libya were partly offset by shutdowns, mature fields decline and price effect.

Oil and gas production sold amounted to 622.3 mmboe. The 40.4 mmboe difference over production (662.7 mmboe in 2017) mainly reflected volumes of natural gas consumed in operations (35.2 mmboe), changes in inventory levels and other variations. Approximately 70% of liquids production sold (308.3 mmbbl) was destined to Eni's mid-downstream business. About 20% of natural gas production sold (1,713 bcf) was destined to Eni's Gas & Power segment.

In 2017, oil and gas productive wells were 9,147 (3,725.5 of which represented Eni's share). In particular, oil productive wells were 6,492 (2,520.3 of which represented Eni's share); natural gas productive wells amounted to 2,655 (1,205.2 of which represented Eni's share).

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