ENI S.p.A. Annual Report 2018

Plain-text annual report

Eni Annual Rep ort 2018 FINANCIAL HIGHLIGHTS Net sales from operations Operating profit (loss) Adjusted operating profit (loss)(a) Adjusted net profit (loss)(a)(b) Net profit (loss)(b) Net profit (loss) - discontinued operations(b) Group net profit (loss)(b) (continuing and discontinued operations) Net cash flow from operating activities Capital expenditure of which: exploration development of hydrocarbon reserves Dividend to Eni’s shareholders pertaining to the year(c) Cash dividend to Eni’s shareholders Total assets at year end Shareholders’ equity including non-controlling interests at year end Net borrowings at year end Net capital employed at year end of which: Exploration & Production Gas & Power Refining & Marketing and Chemicals Share price at year end Weighted average number of shares outstanding Market capitalization(d) (a) Non-GAAP measures. (b) Attributable to Eni’s shareholders. (c) The amount of dividend for the year 2018 is based on the Board’s proposal. (d) Number of outstanding shares by reference price at year end. SUMMARY FINANCIAL DATA Net profit (loss) - per share(a) - per ADR(a)(b) Adjusted net profit (loss) - per share(a) - per ADR(a)(b) Cash flow - per share(a) - per ADR(a)(b) Adjusted Return on average capital employed (ROACE) Leverage Gearing Coverage Current ratio Debt coverage Net Debt/EBITDA adjusted Dividend pertaining to the year Total Share Return (TSR) Pay-out Dividend yield(c) (€ million) (€) (million) (€ billion) (€) ($) (€) ($) (€) ($) (%) (€ per share) (%) 2018 75,822 9,983 11,240 4,583 4,126 4,126 13,647 9,119 463 6,506 2,989 2,954 118,373 51,073 8,289 59,362 50,358 3,143 7,371 13.8 3,601.1 50 2017 66,919 8,012 5,803 2,379 3,374 3,374 10,117 8,681 442 7,236 2,881 2,880 114,928 48,079 10,916 58,995 49,801 3,394 7,440 13.8 3,601.1 50 2016 55,762 2,157 2,315 (340) (1,051) (413) (1,464) 7,673 9,180 417 7,770 2,881 2,881 124,545 53,086 14,776 67,862 57,910 4,100 6,981 15.5 3,601.1 56 2018 2017 2016 1.15 2.72 1.27 3.00 3.79 8.95 8.5 16 14 10.3 1.4 164.6 45.2 0.83 4.8 72 5.9 0.94 2.12 0.66 1.49 2.81 6.35 4.7 23 18 6.5 1.5 92.7 80.6 0.80 (5.6) 85 5.7 (0.29) (0.65) (0.09) (0.20) 2.13 4.72 0.2 28 22 2.4 1.4 51.9 144.7 0.80 19.2 (197) 5.4 (a) Fully diluted. Ratio of net profit/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by Reuters (WMR) for the period presented. (b) One American Depositary Receipt (ADR) is equal to two Eni ordinary shares. (c) Ratio of dividend for the period and the average price of Eni shares as recorded in December. EMPLOYEES Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Group INNOVATION R&D expenditure First patent filing application (number) 2018 11,645 3,040 11,136 5,880 31,701 2017 11,970 4,313 10,916 5,735 32,934 2016 12,494 4,261 10,858 5,923 33,536 (€ million) (number) 2018 197 43 2017 185 27 2016 161 40 HEALTH, SAFETY AND ENVIRONMENT TRIR (Total Recordable Injury Rate) of which: Exploration & Production employees contractors Gas & Power employees contractors Refining & Marketing and Chemicals employees contractors Corporate and other activities employees contractors Direct GHG emissions of which: CO2 equivalent from combustion and process CO2 equivalent from flaring CO2 equivalent from venting CO2 equivalent from methane fugitive emissions Direct GHG emissions - Exploration & Production Direct GHG emissions - Gas & Power Direct GHG emissions - Refining & Marketing and Chemicals Volumes of hydrocarbon sent to flaring - upstream Total volume of oil spills (> 1 barrel) of which: due to sabotage and terrorism operational % produced water reinjected - upstream Groundwater treated or used in production or reinjected % of groundwater used in production/reinjected vs. total treated groundwater Electricity produced from renewable sources % of recovered waste vs. recoverable waste (Syndial) OPERATING DATA EXPLORATION & PRODUCTION Hydrocarbon production Net proved reserves of hydrocarbons Average reserve life index Organic reserve replacement ratio Profit per boe(a) Opex per boe(b) Finding & Development cost per boe(c) GAS & POWER Worldwide gas sales of which: Italy outside Italy LNG sales Installed capacity power plants Electricity produced Electricity sold REFINING & MARKETING AND CHEMICALS Retail sales of petroleum products in Europe Retail market share in Italy Service stations in Europe at year end Refinery throughputs on own account Average throughput of service stations in Europe Balanced capacity of refineries Capacity of biorefineries Production of biofuels Production of petrochemical products Average petrochemical plant utilization rate (a) Related to consolidated subsidiaries. (b) Includes Eni’s share in joint ventures and equity-accounted entities. (c) Three-year average. (total recordable injuries/worked hours) x 1,000,000 (mmtonnes CO2eq) (bcm) (barrels) (%) (mmcm) (%) (GWh) (%) (kboe/d) (mmboe) (years) (%) ($/boe) (bcm) (GW) (TWh) (mmtonnes) (%) (number) (mmtonnes) (kliters) (kbbl/d) (ktonnes/year) (ktonnes) (ktonnes) (%) 2018 0.35 0.30 0.29 0.30 0.56 0.34 0.99 0.56 0.49 0.62 0.53 0.55 0.48 43.35 33.89 6.26 2.12 1.08 24.06 11.08 8.19 1.9 6,362 3,697 2,665 60 4.8 21 19.3 58 2017 0.33 0.28 0.23 0.30 0.37 0.45 0.23 0.62 0.56 0.69 0.41 0.21 1.00 43.15 33.03 6.83 2.15 1.14 24.02 11.30 7.82 2.3 6,559 3,236 3,323 59 4.2 21 16.1 48 2016 0.35 0.34 0.34 0.34 0.29 0.28 0.31 0.38 0.44 0.32 0.50 0.40 0.76 42.15 32.39 5.40 2.35 2.01 22.46 11.17 8.50 1.9 5,913 4,682 1,231 58 3.2 17 13.5 30 2018 2017 2016 1,851 7,153 10.6 100 9.3 6.8 10.4 76.71 39.03 37.68 10.3 4.7 21.62 37.07 8.39 24.0 5,448 23.23 1,776 548 360 219 9,483 76 1,816 6,990 10.5 103 8.7 6.6 10.4 80.83 37.43 43.40 8.3 4.7 22.42 35.33 8.54 24.3 5,544 24.02 1,783 548 360 206 8,955 73 1,759 7,490 11.6 193 2.0 6.2 13.2 86.31 38.43 47.88 8.1 4.7 21.78 37.05 8.59 24.3 5,622 24.52 1,742 548 360 191 8,809 72 Index 2 | M A N A G E M E N T R E P O R T Activities Business model Responsible and sustainable approach Letter to shareholders Eni at a glance Stakeholders engagement Scenario and Strategy Integrated Risk Management Governance Operating review Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Financial review and other information Financial review Risk factors and uncertainties Outlook Consolidated disclosure of non-financial information (NFI) Other information Glossary 2 4 5 7 12 14 16 20 24 30 50 55 61 63 87 103 104 134 135 1 3 7 | C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 2 5 9 | A N N E X Eni Annual Report 2018 Disclaimer This Annual Report contains certain forward-looking statements in particular under the section “Outlook” regarding capital expenditures, dividends, allocation of future cash flow from operations, financial structure evolution, future operating performance, targets of production and sale growth and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new oil and gas fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and oil and natural gas pricing; operational problems; general macroeconomic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors. “Eni” means the parent company Eni SpA and its consolidated subsidiaries. Ordinary Shareholders’ Meeting of May 14, 2019. The extract of the notice convening the meeting was published on April 5, 2019. ACTIVITIES Eni engages in oil and natural gas exploration, fields development and production, mainly in Italy, Algeria, Angola, Congo, the United Arab Emirates, Egypt, Ghana, Libya, Mozambique, Nigeria, Norway, Oman, Kazakhstan, the UK, and the United States, for overall 43 Countries. Eni sells gas, electricity, LNG and oil products in the European and extra-European markets, also leveraging on trading activities. Products availability is ensured by oil and gas production in the upstream business, long-term gas supply contracts, CCGT power plants, Eni’s refinery system as well as by Versalis’ chemical plants. The supply of commodities is optimized through trading activity. Integrated business units enable the company to capture synergies in operations and reach cost efficiencies. OFFSHORE TRADING & SHIPPING INTERNATIONAL OIL AND GAS MARKETS EXPLORATION DEVELOPING OIL AND GAS FIELDS REFINERIES AND PETROCHEMICAL PLANTS (traditional and green) FUEL /BIOFUEL CHEMICAL PRODUCTS /BIO-BASED CHEMICALS LIQUEFYING GAS LUBRICANTS TRANSMISSION NETWORK ONSHORE RIGASSIFYING LNG GAS AND POWER RENEWABLE ENERGY PRODUCTION POWER GENERATION ENI WORLDWIDE PRESENCE 18 5 3 7 13 14 7 11 3 6 1 67 Countries E&P G&P R&M&C B2B B2C 16 ACTIVITIES Eni engages in oil and natural gas exploration, fields development and production, mainly in Italy, Algeria, Angola, Congo, the United Arab Emirates, Egypt, Ghana, Libya, Mozambique, Nigeria, Norway, Oman, Kazakhstan, the UK, and the United States, for overall 43 Countries. Eni sells gas, electricity, LNG and oil products in the European and extra-European markets, also leveraging on trading activities. Products availability is ensured by oil and gas production in the upstream business, long-term gas supply contracts, CCGT power plants, Eni’s refinery system as well as by Versalis’ chemical plants. The supply of commodities is optimized through trading activity. Integrated business units enable the company to capture synergies in operations and reach cost efficiencies. REFINERIES AND PETROCHEMICAL PLANTS (traditional and green) OFFSHORE TRADING & SHIPPING INTERNATIONAL OIL AND GAS MARKETS EXPLORATION DEVELOPING OIL AND GAS FIELDS FUEL /BIOFUEL CHEMICAL PRODUCTS /BIO-BASED CHEMICALS LIQUEFYING GAS TRANSMISSION NETWORK LUBRICANTS ONSHORE RIGASSIFYING LNG GAS AND POWER RENEWABLE ENERGY PRODUCTION POWER GENERATION ENI WORLDWIDE PRESENCE 18 5 3 7 13 14 7 11 3 6 1 67 Countries E&P G&P R&M&C B2B B2C 16 BUSINESS MODEL Eni’s business model is focused on creating value for its stakeholders and shareholders. Eni recognizes that the main challenge in the energy sector is providing efficient and sustainable access of local communities to energy resources, while combating climate change. This challenge may trigger new paradigms of development affecting patterns of consumption and supply, as well as on industrial processes. In this framework, Eni has adopted a systemic approach to pursue efficiency, resilience and growth, which organically integrates sustainability to make it business, incorporates emerging trends of decarbonisation and inclusive development including them in its industrial plan and in the operating model. Eni, therefore, adopts a business model, fuelled by the application of own innovative technologies and the digitalization process, leveraging on the following levers: 1 operational excellence, 2 carbon neutrality in the long term, 3 promotion of local development. VALUE CREATION FOR STAKEHOLDERS AND SHAREHOLDERS A S Y S T E M I C A P P R O A C H T O WA R D S E F F I C I E N C Y, R E S I L I E N C E A N D G R O W T H OPERATIONAL EXCELLENCE Low cash neutrality Low time to market High value reserves CARBON NEUTRALITY IN THE LONG TERM PROMOTION OF LOCAL DEVELOPMENT Energy mix Circular economy Carbon offset Dual flag approach T E C H N O L O GICAL INNOVATION & DIGITALIZATION Production for domestic market Access to electricity Economic diversification Access to water and hygiene Health and education Public-private partnerships Job creation Know-how and expertise transfer Efficiency and integration are the strategic drivers leading Eni’s business towards operational excellence. This allows the achievement of low cash neutrality, a low time-to-market and a high value resource portfolio, resilient also in low carbon scenario. The excellence of the operating model is also characterized by a steady commitment to minimize risks and create opportunities all along the value chain through the valorization of human resources, the safeguard of health and safety, the environmental protection, respect and promotion of human rights and focus on transparency and anti-corruption. Secondly, Eni’s business model envisages a path to decarbonisation with the ambition to lead the Company to become carbon neutral in the long term, aiming at maximize efficiency and reduce direct emissions through the compensation of residual emissions, promoting an energy mix with a low carbon impact. In the long term, Eni supports a change of energy paradigm and a conversion of the current consumption pattern towards a more sustainable and rational one, leveraging on the principles of circular economy, pursuing a path to conversion by exploiting the group’s expertise and positioning in the downstream business. Promotion of local development in Eni’s Countries of activities is the third lever of the business model. First of all, we supply our gas production to the local market, expanding access to electricity and by promoting a large portfolio of initiatives addressed to local communities: from local economies diversification, to projects for health, education, access to water and hygiene. This “Dual Flag” approach leverages on the collaboration with institutions, cooperation agencies and local stakeholders in order to identify actions to satisfy the needs of communities in accordance with the national development plans and the 2030 UN Agenda. Eni is also committed to create job opportunities and transfer its know-how and expertise to the local partners. RESPONSIBLE AND SUSTAINABLE APPROACH The responsible and sustainable approach represents for Eni the logic for creating value in the medium and long term for the company and all stakeholders, combining financial solidity with social and environmental sustainability. This approach is fundamental to operate in the complex current context and respond to the crucial challenge of the energy sector: the transition to a low carbon future and access to energy resources for a growing world population. The 17 Sustainable Development Goals (SDGs) of Agenda 2030, promoted by the United Nations, are a reference framework for Eni, to guide activities and seize new business opportunities, also in partnership with various national and international organizations to share knowledge and resources and contribute to the achievement of development goals. I L A N O T A R E P O L E D O M E C N E L L E C X E PEOPLE SAFETY COMMITMENT PERFORMANCE SDGs Eni focuses on the growth, enhancement and training of its people, recognizing diversity as a resource • 31,701 employees at year end • 23.3% women • Over 1 million of training hours (+5% vs. 2017) Eni considers safety in the workplace an essential value to be shared between employees, contractors and local communities • TRIR 0.35 • TRIR down by 51% vs. 2014 ENVIRONMENTAL IMPACT REDUCTION Eni promotes the efficient use of natural resources and the safeguard of protected areas that are relevant to biodiversity, identifying potential impacts and mitigation actions • 87% of freshwater reused • -2% of freshwater withdrawals vs. 2017 • Recovered waste equal to 40% of disposed waste from production activities • -20% operational oil spills vs. 2017 • 60% of reinjected production water HUMAN RIGHTS Eni is committed to respect human rights in its operations and to promote their respect towards partners and stakeholders • Published Eni’s Statement on respect for human rights • 91% of employees trained on human rights • 90% of security contracts containing clauses on human rights • 100% of new suppliers screened using social criteria TRANSPARENCY AND ANTI-CORRUPTION Eni carries out its business activities with loyalty, fairness, transparency, honesty and integrity and in compliance with the laws • Membership of EITI(a) since 2015 • 8 Countries where Eni supports EITI’s local Multi Stakeholder Groups • 32 audit actions on risk of corruption activities COMBATING CLIMATE CHANGE Eni has defined a clear decarbonization strategy developing short, medium and long term actions to promote the energy transition O T H T A P I I N O T A Z N O B R A C E D LOCAL DEVELOPMENT THROUGH PUBLIC-PRIVATE PARTNERSHIP To support local development, Eni promotes access to energy, economic diversification, education and training, access to water and hygiene, health also through public-private partnerships L A C O L F O N O T O M O R P I : T N E M P O L E V E D I L E D O M N O T A R E P O O C • -20% of GHG emission intensity index (upstream) vs. 2014 • -16% of volumes of hydrocarbons sent to flaring vs. 2014 • -66% upstream methane fugitive emissions vs. 2014 • Net zero carbon footprint on direct emissions of upstream activities (in equity) at 2030 • €94.8 million on community investment in 2018 • Partnerships signed with UNDP and FAO TECHNOLOGICAL INNOVATION Eni invests in new solutions that can increase the efficiency and sustainability of activities, reducing costs and environmental impact • €197 million invested for research and technological development (+7% vs. 2017) • 43 first patent filing applications of which 13 filed on renewable sources (a) Extractive Industries Transparency Initiative: Global initiative to promote a responsible and transparent use of financial resources generated in the mining sector. CONSOLIDATED DISCOLOSURE OF NON-FINANCIAL INFORMATION This Annual Report includes the consolidated disclosure of non-financial information (NFI), prepared in accordance with Legislative Decree No. 254/2016, relating to the following topics: ˙ environment; ˙ social; ˙ people; ˙ human rights; ˙ anti-corruption. The disclosure on these topics and KPIs included in this report are defined in accordance with the “Sustainability Reporting Standards” published by the Global Reporting Initiative (GRI Standards). INTEGRATED ANNUAL REPORT Eni’s 2018 Annual Report is prepared in accordance with principles included in the “International Framework”, published by International Integrated Reporting Council (IIRC). It is aimed at representing financial and sustainability performance, underlining the existing connections between competitive environment, group strategy, business model, integrated risk management and a stringent corporate governance system. THE GLOBAL GOALS Global goals for a sustainable development The 2030 Agenda for Sustainable Development, presented in September 2015, identifies the 17 Sustainable Development Goals (SDGs) which represent the common targets of sustainable development on the current complex social problems. These goals are an important reference for the international community and Eni in managing activities in those Countries in which it operates. LETTER TO SHAREHOLDERS 7 EMMA MARCEGAGLIA Chairman CLAUDIO DESCALZI Chief Executive Officer and General Manager In 2018, Eni made outstanding progress both at optimizing the existing asset portfolio and at strengthening it for the future. These results owed to the process of transformation of our business model started in 2014 in anticipation of the oil downturn, at the end of which Eni has become more financially sustainable and resilient to the volatile scenario as it has never been in the past. Several drivers have underpinned our transformation: a track record of exploration successes coupled with the dual exploration strategy which allowed us to early monetize discoveries, the optimization of the time-to-market of hydrocarbon reserves, the operational efficiency, the restructuring of our downstream businesses aimed at reducing the breakeven and financial discipline in investment decisions. Synergies within our businesses have been optimized and our commitment at empowering local communities and at preserving the environment has become a driver of our business model. At the core of our progress are our intangible assets: technologies, skills and know-how. Leveraging on these drivers, we have built a new Eni based on efficiency, integration, deployment of new technologies and an optimized asset portfolio. With a view to the future we strengthened and geographically diversified our upstream portfolio, expanding our growth prospects with the building of a significant presence in the Middle East, while keeping costs low and maintaining a high level of profitability by means of the creation of a strategic equity-accounted joint venture with the ADNOC oil State company in Abu Dhabi. In these years, we have consistently delivered on strategy guidelines leading to excellent results in terms of growth, returns and a healthy balance sheet: 2018 marked a record in hydrocarbon production at 1.85 million boe/d, the cash neutrality for funding capex and the floor dividend lowered to 52 $/bbl, which compares well to the 2014 baseline of 114 $/bbl, net borrowings declined to €8.3 billion, with a leverage at 0.16, the lowest level of the last twelve years and among the best of the industry, after having paid a total of €16.2 billion of dividends in the last five years in a challenging oil scenario. In these years, exploration was at the core of our growth and cash generation. For the fourth consecutive year, Eni has been nominated best exploration company in the oil business. This demonstrates the excellence of our discoveries and the effectiveness of the dual exploration model, whereby Eni has elected to acquire high working interest in exploration leases to achieve fast monetization of the discovered resources through the dilution of participation interests, while retaining operatorship. Since 2013, the dual exploration model allowed us to cash in approximately $10 billion mainly by diluting Eni’s interest in the giant gas projects Zohr in Egypt and Area 4 in Mozambique. Leveraging the dual exploration model, a number of strategic partnerships have been signed as well as the agreements signed in March 2018 to divest a 10% interest in the Zohr field and the concurrent acquisition of interests in the producing concession agreements Lower Zakum (5%) and Umm Shaif and Nasr (10%) located offshore the United Arab Emirates (UAE). 8 In the last five years, we have discovered some 5 billion boe of resources, of which 620 million in 2018 at competitive costs, replacing more than 130% of our cumulative production with proved reserves. Growth has been driven by a strengthened Exploration & Production portfolio. We aimed at diversifying our geographical footprint by building a strong presence in the Middle East through strategic alliances such as the one in Abu Dhabi, which was complemented with the assignment to Eni of a 25% interest in the offshore Ghasha concession, a huge gas project where we were appointed technical operator with expected start-up by the end of the plan period and a production target of 1.5 bcf/d. We enhanced the producing platform in Norway, by merging our subsidiary Eni Norge with Point Resources, and setting up the joint venture Vår Energi (Eni’s interest 69.6%), an independent company, leader in the upstream segment in Norway. Hydrocarbon production is expected to target 250 kboe/d in 2023. The reloading of the exploration asset portfolio was made with the objective of expanding the geographic reach of our operations, targeting material assets with high working interests located in strategic areas. In the Middle East we acquired seven high-potential, low-risk exploration leases totaling approximately 70 thousand square kilometers of new acreage, notably in Abu Dhabi we were awarded Blocks 1/2 in the offshore area, promising synergies with the project in Ghasha, onshore Oman with the signing of an EPSA on the Block 47, in the Sharjah Emirate with the entry in three onshore blocks and in Bahrain, with the acquisition of Block 1, located in an offshore unexplored basin. In 2018, we acquired other exploration assets of great interest in Lebanon, Mexico, Alaska, Morocco, Indonesia and Mozambique where Eni was awarded mineral interests on an offshore area of 5 thousand square kilometers balancing these acquisitions with the swap of exploration licenses in Mexico with Lukoil (farm-in of 40% interest in Area 12 PSC) and the dilution of the interest in the exploration block located offshore Nour in Egypt (45% to BP/Mubadala). In 2018, hydrocarbon production set a new record at 1.85 million boe/d (up by 2.5% vs. 2017 at constant prices) thanks to the five scheduled start-ups for the year – Wafa compression and Bahr Essalam phase 2 in Libya, OCTP gas phase in Ghana and Ochigufu and Vandumbu in Angola –, the highest plateau on record in Iraq and, above all, the extraordinary success in the ramp-up of Zohr field where we reached the first production target to more than 2.1 bcf/d, nine months ahead the schedule and we revised the target to 3.2 bcf/d. Overall, in the year start-ups and ramp-ups of fields started up in 2017 added approximately 300 kboe/d to the full year plateau. Future production growth will be fuelled by the six FIDs made in the year related to projects in Area 1 in Mexico targeting the development of 2.1 billion of boe in place, Merakes in Indonesia, in synergy with the Jangkrik producing field, Cassiopea in Italy, Baltim South West in Egypt, Nenè phase 2 in Congo and Cabaca in Angola. Finally, relevant progress was made towards the FID on the first phase of the giant Rovuma LNG project, which includes the design and construction of two trains for the liquefaction of natural gas with a capacity of 7.6 million tonnes of LNG each, thanks to the LNG long-term purchase commitments obtained by the partners of Area 4. Results obtained in the development activity leveraged on our strategy of reducing the time-to-market of the reserves based on the parallelization of different stages of the project (exploration, pre-fid activity and construction), control of the project risks through the insourcing of critical phases (such as detailed engineering, construction supervision and commissioning) as well as applying a phased approach which allow to reduce idle capital and financial debt. We replaced with new organic proved reserves the 100% of the production thanks to new discoveries and progress in maturing reserves. On an all sources base, the RRR stood at 124%, while the three-year average organic RRR reached 131%. At year end, total proved reserves amounted to 7.2 billion of boe, with a life index of 11 years. Our leadership in the exploration, the reduction in time-to-market, the effectiveness of the phase-development activity and opex control contributed to reduce Eni’s development projects breakeven overall at $25/boe. In 2018, adjusted operating profit of the E&P segment was €10.85 billion, more than doubling y-o-y, with a Brent price increasing by 31%. A larger portion of more valuable barrels boosted the cash flow per barrel to $22.5, well ahead of our guidance set for 2022. The downstream businesses reported robust results driven by the finalization of the turnaround implemented in these five years, which made these businesses sustainable also in an unfavorable environment. The Gas & Power segment reported an adjusted operating profit of €0.54 billion, more than doubling 2017 results and significantly better than the announced guidance. This performance was due to the restructuring the portfolio of long- term gas contracts, leveraging on the associated flexibilities to capture scenario upsides, the optimizations in the power business, trading and logistics as well as the growth in the LNG business with 8.8 MTPA of contracted volumes (up by 70% compared to 2017). All along the value chain we leveraged on the integration with the upstream segment contributing to the acceleration of FIDs at gas reserves development projects. The retail business performed strongly, driven by value creation at the European customer portfolio which reached 9.2 million clients, efficiency gains from the operations, digitalization programs and automatization of post-selling activities and working capital monitoring. In the oil downstream, technological innovation was the driver of the turnaround, which allowed Eni to revamp certain unprofitable plants, thus reducing the exposure to the volatility of the oil feedstock. Today we are proud to announce the LETTER TO SHAREHOLDERS9 start of a new growth phase in our refining business. The strategic acquisition of a 20% interest in the Ruwais refinery in Abu Dhabi for a consideration of $3.3 billion gives us the possibility to deal with one of the better opportunity to expand our presence in the market in terms of efficiency and profitability. This acquisition will allow us to increase by approximately 35% our refinery capacity and to significantly improve the profitability outlook by reducing the breakeven margin from 3 $/bbl to 2.7 $/bbl by 2020 and till to 1.5 $/bbl by completing the refinery upgrading, with a conversion capacity of 1.1 million bbl/d at 2023. Further value will be extracted by the set-up of a trading joint venture in partnership with the partners of the refinery, aiming at catching marketing opportunities in Europe, the Middle and Far East and Africa. In 2018, on the back of an unfavorable scenario, the Refining & Marketing reported an adjusted operating profit of €390 million and a surplus of cash flow after funding capex for the year, thanks to excellent results of the marketing activity, the contribution of margins of green throughputs and optimization actions and feedstock flexibility. Also in Versalis the technological driver was the engine of the value creation with the development of the green chemical business and specialties, by reducing the incidence of plastic commodities in the Company’s portfolio, which are subject to the volatility of the oil cycle. In line with this strategic guideline, in 2018 a new production unit of high range of elastomers EPDM for the automotive industry was started up. Furthermore, was finalized the acquisition of the activities of the Mossi & Ghisolfi Group, focused on biochemical technologies and processes based on the use of renewable sources from biomasses and the establishment of a joint venture with Mazrui Energy Services in the Middle East to market specialties based on Versalis’ technology for the Oil & Gas industry. In 2018, in a particularly unfavourable petrochemical scenario, Versalis targeted the breakeven in profitability, leveraging on business’ restructuring. Integration is on the base of the renewable segment development. This is managed by the New Energy Solutions division which in 2018 completed and started up three photovoltaic plants (Assemini in Sardinia, a unit in Gela and one in the Green Data Center) among the “Italia Project” which includes certain initiatives aimed to create sustainable value in the reclaimed industrial areas, mainly in the Southern region of Italy. Outside Italy, we started up a solar plant in Algeria with a capacity of 10 MW at the Bir Rebaa North oil field, jointly operated by Eni and Sonatrach, which will make the upstream activity energy self-sufficient. Furthermore, we started the project to build a 50 MW wind farm at Badamsha in Kazakhstan, to supply renewable energy to the Country. Our businesses growth is even more focused on the long-term sustainability. Climate change is a pillar of our industrial strategies and is also factored in the evaluation of our projects which have to be sustainable also in a low carbon scenario. Progress achieved so far in the evolution of our business model is based on a clear decarbonization strategy focused on a constant commitment to achieving increasing operational efficiency and finding innovative and technological solutions to foster energy transition and reduce emissions, thus also leveraging projects of circular economy and carbon offset. In 2018, we achieved significant results on E&P GHG emission intensity index reporting 21.44 tCO2eq/kboe, a 20% reduction compared to the baseline 2014 and in line with the target at 2025 declared to the market, a 43% reduction. Also the downstream business turnaround is a founding part of this long-term growth strategy. It is based on the “green” conversion of the least competitive sites, extending their life in low carbon optics, through the use of renewable feedstock and raw materials such as food waste, urban waste and secondary, alternative commodities to the traditional feedstocks and in line with the principles of the circular economy. In order to optimize resources all along the life cycle, Eni has launched eco-design projects. We are also engaged in developing technologies for the chemical-physical and mechanical recycling of polymers at the end of use, such as the reuse of expanded polystyrene for thermal insulation. These projects leverage both on internal research and on partnership and collaboration with associations/consortia. Broad partnerships have been established with Pertamina, the state oil company of Indonesia, and in Italy with Coldiretti for large-scale applications of the Eni’s technologies for the enhancement of biomasses and waste. At the heart of our values is the commitment to promote and improve access to energy mainly in Africa according to the “dual flag” business model, such as the OCTP project in Ghana providing the supply of the gas equity produced by our investment in the Country, contributing to the local socio-economic development. Our future plans in Africa will be supported and developed by leveraging on the prestigious collaboration with UNDP (United Nations Development Programme). In September 2018, Eni and UNDP signed a partnership to improve access to sustainable energy in Africa and to contribute to accomplishing the United Nations Sustainable Development Goals (SDGs). The first phase of the cooperation will involve ten African Countries in order to promote sustainable energy contributing to the achievement of four of the SDGs of the United Nations, in particular the number 7 on accessible and clean energy. This partnership is the first signed between the UNDP and a global energy company, and underpins the credibility of our strategies. Finally, our performance on safety continued on its track record of results within the industry’s low average range, with a Total Recordable Injury Rate (TRIR) of 0.35 in 2018. Our financial results for 2018 were excellent. Adjusted operating profit was €11.24 billion and adjusted net profit €4.58 billion, LETTER TO SHAREHOLDERSEni Annual Report 201810 both almost doubled compared to 2017, supported by a better trading environment with Brent prices increasing by 31% , which showed the ability of our business model to create extra-value in a favorable market scenario. The drivers of these results were the robust performance of the E&P segment (up by 110%) and the recovery in the G&P (up by 154%). Also the downstream oil and chemical businesses reported a positive contribution notwithstanding a challenging trading environment. At the Brent price scenario of 71 $/barrel, in 2018 cash flow from operations was €13.45 billion. Other positive cash flows were associated with positive changes in receivables and payables associated with investing activities (mainly including the cash-in of the deferred price of the Zohr disposals made in 2017), which amounted to €0.9 billion. These inflows funded the reassessed amount of capital expenditures of €7.94 billion and the dividend of €2.95 billion, leaving a surplus of around €3.5 billion. Consequently, on the basis of the Group’s cash flow sensitivity to the Brent scenario which assumes a change of approximately €0.19 billion in cash flow for each one-US dollar change in the Brent price, the cash neutrality for funding the capital expenditure for the year and the floor dividend would have been achieved at 52 $/barrel. This is re-determined in 55 $/barrel when excluding from cash inflows the deferred tranches of the consideration on the disposal of Eni’s interests in Zohr made in 2017 (€450 million), being this the unique non-organic components of the cash flow. Net borrowings reduced to €8.3 billion with a leverage of 16%, seven percentage points lower than in 2017; return on average capital employed almost doubled to 8.5% (compared to 4.7%). STRATEGIES AND TARGETS Considering a volatile trading environment, we will retain a financially-disciplined approach to capital spending. At the long-term Brent scenario of 70 $/barrel, in the next four years we plan to invest approximately €33 billion, a slight increase compared to the previous plan. Approximately 80% is allocated to the exploration and production of hydrocarbon reserves. 9% of group capex will be devoted to growing the green business, in particular by increasing the installed capacity to generate power from renewables, decarbonization projects and circular economy initiatives designed to produce advanced biofuels, renewable chemicals and new products from waste and biomasses as well as to extend the useful life of abandoned and decommissioned industrial sites. The strategic guidelines of the E&P segment are to monetize and enhance the exploration portfolio and to maximize cash generation driven by production growth. We forecast to grow production organically at an annual average rate of 3.5% till 2022, to reach a plateau of 2.13 million boe/d. New projects start-ups and the ramp-ups of producing fields will contribute about 660 thousand boe per day in 2022. New projects are geographically well balanced: Mexico with the start-up of Area 1, Indonesia with Merakes, Italy, upgradings/new phases of producing areas in Egypt, Algeria, Congo and Angola, initiatives in Norway and, at the end of the plan period, the start-ups of giant gas projects such as Coral in Mozambique and the first development of Ghasha in the UAE. The visibility of our production target is excellent because the expected increases are tied to the ramp-up of several operated fields which are currently performing, and the projects sanctioned in 2018. The other drivers of cash generation will be integration with G&P to extract value from the equity gas, strict control on drilling and field operations risks and asset integrity with a view of minimizing production losses due to unplanned downtime. In exploration we intend to adopt a disciplined approach with planned capex of $0.9 billion/year relating to initiatives in frontiers areas or in high-equity, conventional basins also looking for a possible deployment of our dual exploration model, as well as initiatives in proven and near field areas with short time-to-market to contribute rapidly to production increases and cash flow. Our exploration campaign will be focused offshore Mexico, in the Middle East and in mature and high potential areas close to existing facilities in Norway, Angola, Ghana and Egypt. We expect to discover 2.5 billion boe in the plan period at the unit cost of below $2/barrel, contributing to expand the geographical reach of our operations. In the Gas & Power segment we confirm the structural sustainability in the plan period and we expect a significant contribution to cash generation notwithstanding a challenging trading environment, characterized by the continuing pressure on gas and power spreads. The main driver will be the enhanced synergies with all Eni’s businesses in order to optimize the trading of oil and products to capture market upsides, as well as to develop the LNG portfolio by increasing contracted volumes from 8.8 MTPA in 2018 to 14 MTPA by 2022 and 16 MTPA by 2025, capitalizing on equity gas and maximizing margins all along the value chain. Long-term gas contracts will be de-risked and continuously renegotiated with suppliers to align prices at market conditions. In the retail business we will deliver a robust profitability leveraging on the development and full monetization of the customer portfolio, which will be increased to reach 12 million customers. Growth will also be pursued through focused and synergic acquisitions, while margin expansion will leverage on the contribution of extra-commodity products and services and continuous focus on efficiency. We reaffirm the G&P financial targets of an adjusted operating profit of €0.7 billion in 2022 and a cumulative organic free cash flow of €2.3 billion over the plan. In the R&M business we intend to target the breakeven margin of 3 $/bbl at our legacy refineries, with full operability of our refineries, by maximizing plant reliability, optimizing setup and supply and by increasing the licensing of proprietary technologies. LETTER TO SHAREHOLDERS11 The integration of Eni’s 20% interest in ADNOC Refining will leverage on technological synergies and will allow to halve the breakeven margin to 1.5 $/bbl by delivering on the identified projects for plant upgrading. The bio-refining segment is expected to grow thanks to the start-up and full operation of the Gela plant and the upgrading of Venice. Our green diesel production will grow to 1 million tonnes per year by 2021. In the Marketing activity we target robust results fuelled by quality and innnovation in our services, the contribution of premium products’ margins and the development of the non-oil segment and the sustainable mobility. Versalis’ strategy is focused to make the business more resilient to the volatility of the trading environment by shifting the product portfolio towards high-value specialties and green chemicals, by using proprietary technologies to sustain margin expansion and international growth, and by executing a number of optimization initiatives such as better vertical integration, increasing feedstock flexibility and reduction in variable production costs. In addition, these initiatives will contribute to the accomplishment of the Company’s targets on the development of the circular economy and decarbonization. In addition to the already stated target of 43% reduction compared to the 2014 baseline of the upstream intensity emission rate by 2015 through zero gas flaring projects and methane fugitive emissions (the 80% reduction target compared to the 2014 baseline by 2025), we intend to achieve zero net carbon footprint in our upstream business by 2030. We will do this by increasing efficiency to minimize direct upstream CO2 emissions, maximizing decarbonization initiatives and developing forestry initiatives offsetting residual upstream emissions, while providing benefits to local communities. The identified strategic guidelines include also the acceleration in growing low carbon sources such as gas and bio-fuels and the development of power generation capacity from renewable sources (solar photovoltaic, wind and other) leveraging on synergies with Eni's business up to 1.6 GW of installed capacity to 2022 and 5 GW to 2025, with the ambition to reach more than 10 GW at 2030. Another lever of our strategy is the development of circular economy initiatives aiming to exploiting waste and biomasses to extract new energy, new products or materials and give new life to decommissioned or reclaimed assets. On these activities, Eni intends to invest more than €950 million ranging from the recovery of biomasses and waste, to the recycling of polymers and processes of eco-design, up to the extension of the useful life of the assets and products from a low carbon side. Further €220 million will be addressed to research and development as well as to technological innovation. On these bases and given the constant reduction of breakeven of new development projects, we believe that our portfolio will be resilient also under severe decarbonization scenarios. Another driver of our sustainability is the empowerment of the communities in the Countries where we operate, in line with our dual flag approach and consistently with the national Development Plans on the 2030 Agenda of the United Nations. All in all, while being aware of the magnitude of our efforts during the downturn in terms of growth, efficiency and sustainability, we intend to make even more robust Eni’s competitive position and its resilience to the oil scenario. We will accomplish this by leveraging on asset portfolio which is geographically better diversified and more balanced along the entire hydrocarbon value chain and on the planned initiatives from now to the first half of the next decade. Our medium-term objectives are to reduce the cash neutrality to 50 $/barrel, to ensure a growing remuneration to shareholders and to enhance the Company’s contribution to the achievement of the SDGs of the United Nations. We are extremely proud of the global Eni team. Without the women and men of Eni, we would not have been able to transform the business over the past five years to drive the Company to those achievements. On the basis of 2018 results, we will propose the payment of a dividend of €0.83 per share, of which €0.42 already paid, at the Annual Shareholders meeting to be held on 14 May. Our strong outlook underpins our progressive shareholder remuneration that envisage, for 2019, a 3.6% dividend increase to €0.86 per share and the start of a four-year buyback programme with an initial capital allocation of €400 million in 2019. In the following three years, assuming a leverage steadily below 20%, the annual capital allocation will amount either to €400 million in a $60-65 per barrel Brent scenario or €800 million with a Brent scenario above $65 per barrel. March 14, 2019 In representation of the Board of Directors Emma Marcegaglia Chairman Claudio Descalzi Chief Executive Officer and General Manager LETTER TO SHAREHOLDERSEni Annual Report 201812 ENI AT A GLANCE 2018: year of outstanding financial and industrial results achieved thanks to the fast implementation of our strategy. 2018 results were driven by our successful exploration activity supported by the “dual exploration” strategy allowing Eni to early monetize discoveries, to achieve efficiency through the optimization of hydrocarbon reserves time-to-market, the breakeven decrease in downstream businesses and the financial discipline on spending. The optimization of existing portfolio, the geographical diversification strategy and the improved balance of assets portfolio along the value chain through a robust growth in the Middle East, together with our commitment in promoting local development, in environmental protection and in fostering Eni’s expertise and technologies enabled Eni to seize synergies and growth opportunities. Public-private partnerships started-up in 2018 will enable us to share resources, know-how and expertise with the United Nations Development Programme (UNDP) for sustainable development and to aim at achieving SDGs, in particular the universal access to energy by 2030, the actions to combat climate changes and the protection, restoration and sustainable use of the earth’s ecosystem and with the Food and Agricultural Organization (FAO) for clean and safe water access in Nigeria. €11.24 BLN up by 94% vs. 2017 €13.45 BLN up by 35% vs. 2017 GROUP ADJUSTED OPERATING PROFIT ADJUSTED NET CASH FLOW FROM OPERATIONS €8.29 BLN down by 24% vs. 2017 NET BORROWINGS BRENT DATED ($/barrel) 2018 2017 2016 71.04 54.27 43.69 SERM ($/barrel) 2018 2017 2016 3.7 5.0 4.2 AVERAGE EUR/USD EXCHANGE RATE 2018 2017 2016 1.181 1.130 1.107 PSV vs. TTF (€/kmc) 2018 2017 2016 17 28 20 The outstanding financial results of the year were achieved against a backdrop of highly volatile Brent prices, due to signs of weakening global growth, oversupply, uncertainty tied to the commercial dispute between the USA and China, the Brexit, as well as geopolitical issues. ENI GROUP Operating profit (loss) Adjusted operating profit (loss) Net cash from operations TRIR (Total recordable injury rate) Leverage 2018 2017 2016 (€ million) 9,983 8,012 2,157 ▲ +25% -6% vs. 2017 (total recordable injuries/ worked hours) x 1,000,000 11,240 5,803 2,315 ▲ +94% 13,647 10,117 7,673 ▲ +35% 0.35 0.16 0.33 0.35 ▼ +6% 0.23 0.28 ▲ -0.07 UPSTREAM GHG INTENSITY INDEX 0.35 TRIR AMONG THE LOWEST LEVEL COMPARED TO THE AVERAGE OF THE INDUSTRY 2018 SOURCES AND USES (€ bln) ORGANIC CASH FLOW VS. NET BORROWINGS (€ bln) €3.8 bln cash flow disposals surplus capex dividends acquisitions 7 6 5 4 3 2 +123% -40% 2014 2018 net borrowings organic cash flow 14 13 12 11 10 9 8 0.16 leverage THE LOWEST LEVEL IN THE LAST 12 YEARS 52$/barrel 2018 CASH NEUTRALITY 13 EXPLORATION & PRODUCTION 2018 2017 2016 Adjusted operating profit (loss) (€ million) 10,850 5,173 2,494 Hydrocarbon production (kboe/d) 1,851 1,816 1,759 Opex per boe Profit per boe ($/boe) 6.8 9.3 6.6 8.7 6.2 2.0 GHG emissions/100% operated hydrocarbon gross production (mmtonnes CO2eq/kboe) 21.44 22.75 23.56 1.85 million boe/d NEW RECORD IN HYDROCARBON PRODUCTION +110% vs. 2017 UPSTREAM PROFITABILITY GAS & POWER Adjusted operating profit (loss) (€ million) 2018 543 2017 214 2016 (390) Worldwide gas sales LNG sales GHG emissions/kWheq (EniPower) (gCO2eq/kWheq) Retail customers in Italy (million) (bcm) 76.71 80.83 86.31 10.3 402 7.74 8.3 395 7.65 8.1 398 7.68 +154% vs. 2017 G&P PROFITABILITY REFINING & MARKETING AND CHEMICALS Adjusted operating profit (loss) (€ million) 2018 380 2017 991 2016 583 Retail sales of petroleum products in Europe (mmtonnes) 8.39 8.54 8.59 Refinery throughputs on own account 23.23 24.02 24.52 €380 MLN R&M and Chemicals GHG emissions/products (crude oil and semifinished) processed in refineries (tonnes CO2eq/kt) 253 258 278 ADJUSTED OPERATING PROFIT Sales of petrochemical products (ktonnes) 4,938 4,646 4,745 Thanks to the deep transformation process started in 2014, Eni today, after years of oil market downturn, owns a sustainable financial structure and is resilient to the volatility of scenario as never before. Through the strict implementation of our strategic guidelines Eni was able to combine growth, profitability and soundness of financial position, achieving record hydrocarbon production at 1.85 million boe/d in 2018, reducing net borrowings to €8.3 billion, with a leverage of 0.16, the lowest level in the last 12 years, among the best in the industry, thus distributing €16.2 billion of dividend in last five years, on the backdrop of a challenging trading environment. PRODUCTION VS. CAPEX (mmboe/d) 1.90 1.80 1.70 1.60 FINANCIAL SOUNDNESS DIVIDENDS PAID 18 12 6 (€ bln) 14 10 6 2 4 1 0 2 5 1 0 2 6 1 0 2 7 1 0 2 8 1 0 2 30 20 10 €16.2 billion in the last 5 years 2014 2015 2016 2017 2018 production (mmboe/d) capex (€ bln) net borrowings (€ bln) leverage (%) 2014 2017 2015 2018 2016 ENI AT A GLANCEEni Annual Report 201814 STAKEHOLDERS ENGAGEMENT Our stakeholders are first and foremost people who live in the areas where Eni works: their knowledge and sharing of their concerns and expectations are the basis of our commitment to build lasting relationships in order to contribute, together, to a sustainable development. The direct involvement of stakeholders in each phase of the activities, the promotion and sharing of common principles and dialogue are at the basis of the creation of long-term value. Eni is present in 67 Countries, characterized by social, economic and cultural contexts, which may also be very different from one another: in carrying out the activities, the daily and proactive dialogue, in place with different stakeholders, is essential in order to establish a solid and transparent relationship of trust, which can be a promoter for shared development processes. For this reason, Eni has set up an IT platform called the Stakeholder Management System (SMS) dedicated to support the management of the complex network of relationships in the territories, monitoring the expectations of the populations and the results of development projects. Topics arisen from the dialogue with stakeholders 15 This tool allows to survey and visualize, through a map, the relations with each category of stakeholder, highlighting any areas for improvement, with the possibility of better investigating the potential impacts on human rights, tracing the presence of vulnerable groups and the presence of areas of naturalistic and/or cultural value around the areas of activity, enabling a more conscious management of the operational realities. Main stakeholder engagement activities during the year PU ENI’S PEOPLE AND NATIONAL AND INTERNATIONAL LABOUR UNIONS LC LOCAL COMMUNITIES & COMMUNITY BASED ORGANIZATIONS SP CONTRACTORS, SUPPLIERS AND COMMERCIAL PARTNERS ˛ Internal communication plan focused on strategy, targets, Eni’s results through events and meetings on strategic issues ˛ Integrating skills and experiences (best practices sharing, storytelling, support to organization and communication of defined initiatives) ˛ Sample climate analysis ˛ Meeting with national and international labour unions, in the field of Global Framework Agreement, finalized to a dialogue on certain social and working situations in Countries of worker representatives’ origin ˛ Involvement of over 200 communities in the territories in which Eni operates ˛ Consultation activities with authorities and local communities for new exploration activities or for the development of new projects ˛ Collaboration with the authorities and the local communities for planning, management and realization of initiatives for the community (Congo: CATREP(a) project; Mozambique: educational and agro-livestock development projects; Ghana: Livelihood Restoration Plan and water access project; Iraq: educational projects) ˛ Involvement of suppliers with Human Rights Assessment ˛ Communication, feedback and improvement plans ˛ Sharing the draft of the Supplier Code of Conduct on Eni’s values of sustainability ˛ Participation in the IPIECA(b) WG: Forum on Oil & Gas Sustainability best practices ˛ Green sourcing project: identification of the levers in the supply chain for the reduction of environmental impacts FC FINANCIAL COMMUNITY CC CUSTOMERS AND CONSUMERS ˛ Launch of the 2018 strategic plan in London, Milan and New York ˛ Road-show of top management and of the President on governance issues ˛ Conference call on quarterly results ˛ Participation of top management in thematic conferences organized by financial institutions ˛ Engagement with investors about industrial topics, financial and ESG themes also relating to Shareholders’ Annual meetings UR UNIVERSITIES AND RESEARCH CENTRES ˛ Meetings with representatives of Universities, Research Centers and third- party companies with which Eni collaborates or interfaces for the development of innovative technologies concerning the topics of greatest interest ˛ Collaborations with institutions with which Eni has a framework agreement, such as the Polytechnic of Milan and Turin, University of Bologna, MIT, CNR, INSTM, ENEA and INGV(e) ˛ Collaborations for the development of impact assessment models (Columbia University and Milan Polytechnic) ˛ Meetings and workshops with Presidents and managers of the energy sector of national and local CA(c) on topics such as sustainability, circular economy, reclamation and environmental remediation ˛ Sponsorization of CA initiatives on the issues of sustainability and the circular economy to which Eni’s senior officials have taken part, bearing witness to our initiatives in this regard ˛ Territorial meetings organized with the Customers’ Associations of the CNCU(d) OA VOLUNTARY PARTECIPATION IN ORGANIZATIONS AND CATEGORY ASSOCIATIONS ˛ Membership and participation to OGCI, IPIECA, WBCSD, UN Global Compact, CIDU, EITI(f) ˛ Collaboration with DIHR(g) and IHRB(h) ˛ Conventions, debates, seminars and training initiatives on sustainability issues: creation of guidelines and sharing of best practices ˛ Participation to associative organism and specialized worktables ˛ Meetings with local business associations on the supplier qualification process II DOMESTIC, EUROPEAN AND INTERNATIONAL INSTITUTIONS ˛ Meetings with local, national and international political and institutional members on energy and climate issues ˛ Active participation in technical-institutional worktables, mixed commissions on energy opportunities of dialogue promoted by Government and the Italian Parliament ˛ Meetings with national and local institutional delegations during State visits and at industrial sites CD ORGANIZATIONS FOR COOPERATION AND DEVELOPMENT ˛ Promotion of public-private partnerships to carry out projects in line with Country development plans ˛ Sharing of internationally adopted policies and methodologies ˛ Capacity building activities carried out with institutions a) Centre d’Appui Technique et de Ressources Professionnelles. b) Oil & Gas Association active in environmental and social issues. c) Consumers’ Association. d) Italian National Council of Consumers and Users. e) Massachusetts Institute of Technology; National Research Council (Consiglio Nazionale delle Ricerche); National Interuniversity Consortium for Materials Science and Technology (Consorzio Interuniversitario Nazionale per la Scienza e Tecnologia dei Materiali); National agency for new technologies, energy and sustainable economic development (Agenzia nazionale per le nuove tecnologie, l’energia e lo sviluppo economico sostenibile); National Institute of Geophysics and Volcanology (Istituto nazionale di geofisica e vulcanologia). f) Oil and Gas Climate Initiative; World Business Council for Sustainable Development; Comitato Interministeriale Diritti umani; Extractive Industries Transparency Initiative. g) The Danish Institute for Human Rights. h) Institute for Human Rights and Business. STAKEHOLDERS ENGAGEMENTEni Annual Report 2018 16 SCENARIO AND STRATEGY The reference market and the competitive environment Transition towards a low carbon energy mix Companies operating in the energy sector are facing with two challenges: satisfy growing energy needs, guaranteeing everyone an adeguate access to energy 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 worldwide population is expected to grow from 7.5 billion to 9 billion and the energy demand will increase by approximately 30%. There will be also a geographical shift in energy consumption and the additional total demand will come from non-OECD Countries, representing in 2040 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 replacing coal in electricity generation. Recovery and volatility 2018 was characterized by a sharp increase in oil prices, supported by production cuts of the OPEC and non-OPEC Countries, the announcement of new sanctions to Iran and a robust growth in demand. This trend was stopped at the end of the year when signs of a new surplus emerged. The decline of exports from Iran, combined with the Venezuelan crisis, pushed large producers to compensate losses in the market. The record productions of USA, Russia and Saudi Arabia generated a perception of oversupply. At the same time, concern of a slowdown in demand increased, particularly in emerging economies, while Trump urged lower prices in order to support US consumers. The Brent price stands on an average of 71 $/barrel (up by 17 $/barrel vs. 2017), with a decrease of 30% from October to December, boosted by heavy speculative sales on future markets. 2019, not only OPEC The decision of new cuts taken at the end of 2018, the geopolitical losses in Iran and Venezuela and a slowed-down US growth, due to logistics and financial constraints, contribute to ensure a measured supply in 2019. Despite an expected declining economic growth, oil demand is still expected robust. In the second half of the year, the IMO which will be effective since January 2020 will require worldwide ships to use lower sulphur fuels (0.5%) is expected to be a strong discontinuity driver which could generate higher crude oil prices and refining margins. New challenges for refining industry The refining industry has moved from significant overcapacity to a rebalancing phase thanks to the rationalization and the closing of plants in the 2009-2015 period. The rationalization phase slowed down in 2016-2017 to stop in 2018. In 2018 and 2019 a new wave of refining capacity restarted, particularly in Asia and the Middle East, with an impact on assets in the less competitive regions, not only in Europe but particularly in Latin America and Africa. In Europe, following the 2018 start-up of the new refinery in Turkey, the capacity is expected to remain stable. The IMO impact at 2020 will foster the profitability of complex refineries in place of simple ones subject at risk of shut- down. However, European refiners could be less penalized because of already achieved capacity reduction. New challenge for sustainability The environmental, social and governance performance are more crucial on the evaluation of a company, in particular large companies are requested to contribute to the achievement of the Sustainable Development Goals (SDGs) including access to energy and contrast to climatic changes. Relating to the energy access (SDG 7), IEA estimates that people without access to energy (now estimated at 990 million) in 2030 will be still 650 million, with a large part located in Africa, while those without access to clean sources for cooking will be 2.2 billion (today 2.7 billion). Facing with challenges of this magnitude, the achievement of the SDGs requires an unprecedented cooperation between public and private sectors, involving organizations representing both civil society and businesses. Particular responsibility in public-private partnerships (PPP) is assigned to multinational companies, whose involvement, together with different players as bilateral and multilateral governmental institutions and NGOs, opens a new perspective relating to operational effectiveness and allocation of the necessary resources for financing development projects. Respect of Human Rights is a relevant issue for companies, in particular the gradual integration of the Guideline principles of the United Nations for the Human Rights and Enterprise (UN Guiding Principles on Business and Human Rights, 2011) in the main company’s processes, which are supported at country level by the National Action Plans on Corporations and Human Rights and various legislative initiatives (i.e. laws against modern forms of slavery in the United Kingdom, 2015 and Australia, 2018). 17 Industrial Plan In a strongly volatile scenario, Eni completed the deep transformation process of its businesses, which allowed to continue to grow by strengthening the financial structure. This transformation has been successfully achieved thanks to the speed of action based on skills, know-how and technologies, by placing at the heart of the strategy the sustainability of Eni’s business model. Now, Eni is an integrated and flexible company with all the businesses able to contribute to long-term value creation. The 2019-2022 plan gives a new input to growth and consolidates the integration of the sustainability in the business model. The plan consists in the following strongly synergic strategic levers: EFFICIENT AND RESILIENT GROWTH (operating model) AMBITION TO CARBON NEUTRALITY PROMOTION OF LOCAL DEVELOPMENT (cooperation model) The efficient and resilient growth will be supported by a strategy aimed at increasing integration of businesses, geographic diversification of the activities and rebalancing of the upstream vs. mid-downstream business through those actions already taken or characterized by an advanced maturity level and soundness. The main planned actions are: replacement of resources through exploration, start-up/ramp-up of producing fields or of new projects, the sanctioning of projects to support medium and long-term growth, the renegotiations of gas supply contracts, the development of the global LNG portfolio, the enhancement and growth of gas and power retail customers also through portfolio activities, the reduced breakeven of refining activity and international development, the integration and specialization of chemical business. These actions will be pursued leveraging on the operating model which assumes the continuous commitment to minimize risk and the central role of human capital, environment and security. The balanced development of activities portfolio will allow to contain cash neutrality and maintain a solid financial structure. Eni also pursues a strategy targeted to the long-term carbon neutrality through a defined path that includes: (i) actions on energy mix and maximization of energy efficiency and reduction of direct emissions; (ii) development of forest conservation, reforestation or afforestation projects to increase CO2 absorption capacity in the atmosphere, with positive effects on local communities; (iii) development of circular economy initiatives aiming at the valorization of waste and biomass and the recovery of disused or reclaimed assets. Eni, confirming its tradition, will also continue to promote local development leveraging on the cooperation model (dual flag approach), focused on supporting Countries in their social and economic development, involving all the stakeholders. Development will be reached by promoting access to electricity and water, developing health, education and hygiene projects, as well as know-how sharing. Drivers of the integrated model for a sustainable growth will be the innovation and the spread of digital technology which will allow to improve safety at the workplace and to catch new opportunities of development and efficiency SCENARIO AND STRATEGYEni Annual Report 201818 PRODUZIONE IDROCARBURI CAGR RISORSE ESPLORATIVE COPERTURA ORGANICA DEGLI INVESTIMENTI € FREE CASH FLOW CUMULATO BREAKEVEN COMPLESSIVO NUOVI PROGETTI IN ESECUZIONE +3,6 % 2018-2022 produzione organica 2.5 mld boe nel quadriennio <40 $/boe nel quadriennio ~€22 mld nel quadriennio 25 $/boe Upstream HYDROCARBON PRODUCTION CAGR DISCOVERED RESOURCES ORGANIC CAPEX CASH NEUTRALITY € CUMULATED FREE CASH FLOW TOTAL BREAKEVEN OF NEW PROJECTS IN EXECUTION +3.5 % 2018-2022 organic production 2.5 bln boe in the four-year plan ~37 $/boe in the four-year plan €22 bln in the four-year plan 25 $/boe Valorization and growth of the exploration portfolio, with the target to discover 2.5 billion boe and contribute to the geographical diversification. ● Exploration with operatorship on conventional assets and high- equity according to the “Dual Exploration Model”. 2018-2022 period focusing on value, leveraging on the ramp- ups at fields started up in 2018 and new planned production in the next four years with a level of cash flow per boe higher than the portfolio average and sustainable even at lower Brent prices. ● Focus on near-field exploration with reduced time-to-market and ● Start-up and strengthening of integration with the Gas & Power rapid cash flow in Countries with operated infrastructures. ● Build-up of exploration activities in “high risk-high reward” areas. ● Drilling of more than 140 wells located in more than 25 Countries. Cash generation growth with a cumulative free cash flow at €22 billion in the 2019-2022 period. ● Production growth at an average annual rate of 3.5% in the segment to monetize gas equity. ● Strengthened phasing and design-to-cost approach in projects execution enabling the Company to reduce financial exposure and execution risks. ● Optimizing efficiency by means of several initiatives to reduce operating costs and “Non-Productive Time”. ● Use of Digital Transformation to support asset integrity and operational efficiency. Mid-downstream LNG PRODUZIONE CONTRACTED IDROCARBURI VOLUMES CAGR 14 MTPA +3,6 % 2018-2022 @ 2022 produzione organica BREAKEVEN SERM RISORSE ESPLORATIVE COPERTURA ORGANICA GREEN DEGLI PRODUCTIONS INVESTIMENTI € MID-DOWN- STREAM ADJUSTED OPERATING PROFIT FREE CASH FLOW CUMULATO MID-DOWN- STREAM ORGANIC FREE CASH FLOW BREAKEVEN COMPLESSIVO NUOVI PROGETTI IN ESECUZIONE ~1.5 $/bbl 2.5 mld boe in the long term nel quadriennio 1 mln ton/year <40 $/boe from 2021 nel quadriennio €1.8 bln ~€22 mld @ 2022 €4.7 bln in the four-year plan 25 $/boe nel quadriennio GAS & POWER Growth in economic and financial results in the four-year plan: adjusted operating profit expected at €0.7 billion in 2022; cumulated organic free cash flow at €2.3 billion in the 2019-2022 period. ● Growth in LNG business benefitting from the development of the Asian market, the entry in the new markets and the greater integration with upstream business for the enhancement and monetization of gas equity; LNG contracted volumes to 14 MTPA in 2022 and 16 MTPA in 2025. ● Ongoing restructuring of Eni supply portfolio and reduction of logistic costs, through contracts renegotiations. ● Increasing integration with other Eni’s businesses, in particular in LNG and Trading. ● Growth and enhancement of the retail business’ customer base also by developing new products/services and implementing transformation initiatives leveraging on accelerating channels and digitalization. In 2022 customers will increase to around 12 million, up by 22% vs. 2019. ● Geographical rebalancing in Italy in the retail business leveraging on acquisitions, catching the opportunities arising from the market consolidation process. REFINING & MARKETING Sustainable financial results in the four-year plan with a cumulated organic free cash flow at €2.6 billion in the 2019- 2022 period. ● Geographical rebalancing of the refining activities, leveraging on opportunities from Countries characterized by competitive profitability, in particular the Middle East with the acquisition of ADNOC Refining share (Abu Dhabi, up by 35% vs. 2018 capacity). ● Breakeven refining margin at 2.7 $/barrel by 2020, following Ruwais acquisition, maximization of asset integrity and logistic optimizations. In the long-term breakeven refining margin at 1.5 $/barrel. ● Ongoing development of green projects (start-up of the Gela biorefinery and increase of the Venice biorefinery performance), final market diversification and development of projects of waste conversion based on circular economy. ● In marketing business, consolidation of market position in Italy combined with a selective growth abroad, development of sustainable mobility (increase of alternative fuels offer and enhanchment in “enjoy” activity). ● Increasing integration with other businesses. SCENARIO AND STRATEGY$$$$$$$€€19 CHEMICALS Adjusted operating profit to €0.3 billion in 2022; cumulated cash flow from operations expected at €1.1 billion in the four-year plan. ● Consolidation of resilience to scenario fluctuations, by increasing balance of the ethylene-polyhethylene supply chain and higher integration among productive sites. ● Focus of portfolio on differentiated products with higher value added, through the enhancement of production processes. ● Development of circular economy projects and bio-tech to react to legislative challenges and market requests on sustainability issues. ● Reduction of GHG emissions in the production processes, increasing energy efficiency and flexibility of cracker feedstock. ● Development of international presence in the low-cost feedstock areas, to increase resilience of the industrial system and in areas with higher growing rates, leveraging on technological driver. Dividend policy Eni is committed to a progressive remuneration policy linked to our underlying earnings and free cash flow growth. In light of the achieved performance and the expected growth in all businesses, Eni intends to increase the 2019 cash dividend by 3.6% to €0.86 per share. In addition, in 2019 we start a buyback programme with an initial capital allocation of €400 million. In the following years, assuming a leverage steadily below 20%, the annual capital allocation will amount either to €400 million in a $60-65 Brent scenario or €800 million with a Brent scenario above $65/barrel. Focus on decarbonization EMISSIONI DIRETTE GHG UPSTREAM Eni defined a clear strategy to decarbonization integrated in the business model based on short, medium and long-term actions. Research and development will play a key role in our decarbonization strategy and in finding the innovative solutions vs. 2014 to promote energy transition. -43 % GAS FLERED ZERO ROUTINE vs. 2014 -80 % GNL CONTRAT- TUALIZZATO In the short term, Eni’s strategy is based on the following levers: ● increase of efficiency and reduction of direct GHG emissions: by 2025 we target to reduce the upstream emission intensity of Eni’s operated assets by 43% compared to 2014 through projects aiming at zero gas flaring, reduction of methane fugitive emissions and the realization of projects based on energy efficiency; CAPACITÀ INSTALLATA DA ENERGIE RINNOVABILI 16 mton/a 5 GW ● “low carbon” and resilient Oil & Gas portfolio: Eni’s portfolio is characterized by a high share of natural gas (more than 50%), a bridge towards reduced future emissions. The main upstream projects in execution present an average breakeven at a Brent price of approximately 25 $/barrel, resilient to low carbon scenario; ● development of renewable sources and green business: 2025 targets EMISSIONI FUGGITIVE the promotion of renewable sources targets an installed power capacity of approximately 5 GW by 2025. PRODUZIONE +3,5 % vs. 2022 Relating to green business, the second phase of Venice biorefinery will be completed by 2021 with an increase of capacity to 560 kton/year (compared to the current value of 360 kton/year) and the start-up, by 2019, of the Gela plant, with a capacity of 720 kton/year. The consolidation of green chemicals is confirmed by the acquisition in 2018 of the Mossi & Ghisolfi Group bio-activities and by the development of recycling and recovering projects. In the medium term, Eni targets the net zero carbon footprint by 2030, relating to direct emissions of the upstream equity assets, by maximizing the decarbonization initiatives and developing forestry projects offsetting residual upstream emissions. A central role will be played by those solutions addressed to capture, store and reuse CO2. Another lever of our decarbonization path is the devolopment of circular economy initiatives aimed at waste and bio-mass valorization in order to extract new energy, new products or materials and revitalized dismissed or decommissioned assets. DIRECT GHG UPSTREAM EMISSIONS INTENSITY -43 % vs. 2014 GAS FLARED 0 routine UPSTREAM METHANE FUGITIVE EMISSIONS -80 % vs. 2014 HYDROCARBON PRODUCTION CAGR +3.5 % vs. 2022 LNG CONTRACTED VOLUMES INSTALLED CAPACITY FROM RENEWABLES 16 MTPA 5 GW SCENARIO AND STRATEGYEni Annual Report 2018 20 INTEGRATED RISK MANAGEMENT The integrated risk management (IRM) process is aimed at ensuring that management takes risk-informed decisions, with adequate consideration of actual and prospective risks1, including medium and long-term ones, within the framework of an organic and comprehensive vision. IRM Model also aims to strengthen the organization awareness, at any level, that suitable management and evaluation risk may impact the delivery of corporate targets and value. Integrated Risk Management Model 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 29), 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. INTEGRATED RISK MANAGEMENT MODEL BOARD CONTROL AND RISK COMMITTEE/BOARD OF AUDITORS CHAIRMAN CEO RISK COMMITTEE COMPLIANCE COMMITTEE Integrated Risk Management Integrated Compliance 1st line “Line” managers - risk owners 2nd line Risk & Control functions* 3rd line Internal Audit (*) Including Integrated Risk Management function. (1) Potential events that can affect Eni’s activities and whose occurance could hamper the achievement of the main corporate objectives. 21 Integrated Risk Management Process The IRM Model is implemented through a process of integrated management which is both continuous and dynamic and leverages on the risk management systems already adopted by each business unit and corporate processes, promoting harmonization with methodologies and specific tools of the IRM Model. The process, regulated by the “Management System Guideline (MSG) Integrated Risk Management” published on July 2016, has been revised and broadened 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 approval. 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 multidimensional arrays 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 18 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 2018, two assessment sessions were performed: the Annual Risk Profile Assessment performed in the first half of the year, involving 80 subsidiaries in 27 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 the main business risks. The two assessment results were submitted to Eni’s management and control bodies in July and December 2018. 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 top risks monitoring results were submitted to the management and control bodies in March, July and October 2018. INTEGRATED RISK MANAGEMENT PROCESS 1 RISK MANAGEMENT GUIDELINES IRM INTEGRATED RISK MANAGEMENT Top-down and risk-based approach 2 3 4 5 RISK STRATEGY RISK ASSESSMENT & TREATMENT RISK MONITORING RISK REPORTING 6 RISK CULTURE The risk culture develops a common language and spread an appropriate risk management culture across all organizational levels to build awareness that suitably identifying, assessing and managing various types of risk can affect the achievement of objectives and the value of the company. Risk culture, moreover, promotes a greater inclusion of risk management in the company’s processes to ensure consistency in methodology, and in general, in management tools and in risk control. INTEGRATED RISK MANAGEMENTEni Annual Report 2018 22 Targets, risks and treatment measures K S I R L A N R E T X E K S I R I C G E T A R T S K S I R I L A N O T A R E P O COUNTRY MAIN RISK EVENTS Political and social instability in Eni’s Countries of operations may lead to acts of internal conflicts, civil unrests, violence, sabotage and attacks, with consequent production interruptions and losses as well as interruptions in gas supplies via pipe. Global security risk relates to actions or fraudulent events which may negatively affect people and material and immaterial assets. TREATMENT MEASURES • Geographic diversification of asset portfolio since the exploration phase and business diversification; • Reduction of the exposure through the Dual Exploration Model; • Keeping efficient and long-lasting relationships with producing Countries and local stakeholders through local social development and sustainability projects in order to enhance local content and welfare promotion within local communities (production for domestic market, access to energy, economic diversification, local development, health and education); Implementation of the security management system supported by specific site’s analysis of the preventive measures. • → Ref. pages 94-96 CLIMATE CHANGE MAIN RISK EVENTS Climate change referred to the possibility of change in scenario/climatic conditions which may generate phisical risks and connected to energy transition (legislative, market, technological and reputational risks) on Eni’s businesses in the short, medium and long term. TREATMENT MEASURES • Decarbonization strategy integrated in Eni’s business model based on: carbon footprint reduction, resilient Oil & Gas portfolio, development of renewables and green energy businesses, commitment in R&D and climate partnership; • Structured governance on climate with a central role of the Board in managing main issues connected with climate change; presence of specific committees to support the Board; establishment of the Advisory Board and Eni’s programs focused on climate change issues; Inclusion of targets related to “climate strategy” in incentive plan for managers, consistent with guidelines of Eni’s Strategic Plan; • • Leadership on climate-related financial disclosures and other initiatives: joining in the Task Force on Climate-related Financial Disclosures (TCFD) of Financial Stability Board and in “TCFD European Oil & Gas Preparers’ Forum” for drawing up industry guidelines to support the implementation of the Recommendations issued by TCFD and participation in different initiatives at international level. → Ref. pages 99-100 ACCIDENTS MAIN RISK EVENTS Blow-out risks and other relevant accidents affecting the upstream assets, refineries and petrochemical plants, as well as the transportation of hydrocarbons by sea and land (i.e. fires, explosions, etc.) with impact on people and assets damages, company profitability and reputation. TREATMENT MEASURES • Upgrading methodology to classify complex wells (Well Complexity & Economic Index) and geologic “Real time monitoring” of well drilling phases; • Asset Integrity Management, Maintenance Management; • BART (Baseline Assessment Risk Tool) implementation, Simultaneous Operations Operating Plans; • Process Safety Reinforcement Plan, Emergency Preparedness and Response Plans; • Identification of Safety Critical Equipment and use of the “risk based inspection” methodology (API 581 standard) and Fitness for Service (API 579 standard) for the definition of the optimum inspection programmes and the identification of the intervention priorities of preventive maintenance on the basis of identified defects and of the plant components executability; • Development of innovative digital tools and big data analystics to improve operational performance and asset integrity. Particularly, the implementation of the Digital Lighthouse project from Val d’Agri to other upstream and downstream top value assets (e.g. centralized room for real time monitoring of productive assets, smart operators, integrated operating centres, strategic equipment modelling and integrated competence centre); Involvement of First Parties to strengthen the culture of security in joint-control JV; • Specific technological development and emergency management plans; specific HSE audit and plants monitoring; • • Management and continuous monitoring of shipping operation through third operators, vetting activities. → Ref. pages 89-94 INTEGRATED RISK MANAGEMENT 23 Eni’s target ˛ Company profitability Corporate Reputation Relationship with Stakeholders, Local development COUNTRY/COUNTERPARTY EVOLUTION IN G&P LEGISLATION Upstream Credit and Financing risk related to the credit proceeds delay or cost recovery from National Oil Companies (credit) or joint venture partners (financing). Potential deteriorating legislative/regulatory, national and international environment, in the Gas & Power segment with potential impacts to corporate profitability. UPSTREAM • Finalization of specific agreements on repayment plans of third parties • Control of legislative and regulatory framework evolution in order to simplify/mitigate impacts on business; receivables; • Securitization package with in-kind withdrawals and/or utilization of dedicated escrow account; • Mitigation collaterals (sovereign guarantees, parent company guarantees, credit letters); • Carry agreement negotiations and offsetting with the NOC’s through debt positions in the Country. → Ref. page 101 • Recovery/optimization actions on logistical costs through asset backed trading activities and contractual revision on capacity. → Ref. pages 97-98 STAKEHOLDER LONG-TERM GAS CONTRACTS Relationships with local and international stakeholders on Oil & Gas industry activities, with impacts also in the media. Potential differences between the cost of supply and the minimum off take obligations in take-or-pay long-term gas supply contracts compared to current market conditions and management of arbitrations/ negotiations with gas suppliers. • Integration of targets and sustainability projects (i.e. Community Investment) within the Strategic Plan and incentive program; • Prolonged supply portfolio restructuring process through the renegotiation of price-volume conditions; • Focused communication plan and communication initiatives aimed at • Portfolio balancing by the sale to hubs of volumes not intended to spreading Eni’s strategy and activities, also through social media with a mainly institutional target; • Meeting and dialogue with stakeholders initiatives and strenghtening of presence in the critical areas in order to intensify the relationship management with local authorities and territories; • Development of measurement instruments and monitoring of corporate reputation (RepLab) for all stakeholders categories. → Ref. pages 94-96 commercial segments, both in Italy and in Northern Europe; • Continuous control of arbitration management and negotiations by dedicated units. → Ref. pages 96-97 INVESTIGATIONS AND PROCEEDINGS CYBER SECURITY Environmental and health proceedings as well as evolution in HSE legislation may trigger contingent liabilities, impact on company profitability (costs for remediation activities and/or plant implementation), operating activities and corporate reputation. Involvement in anti-corruption investigations and proceedings. Cyber Security and industrial Espionage. • Continuous monitoring of regulatory developments and constant evaluation of the adequacy of existing presidium and control models; • Internal training activities at all levels on the topics of interest; • Monitoring of relations with the Public Administration and definition of routes for the management of relevant problems and for the development of the territory; • Continuous monitoring of the efficacy and efficiency of reclamation activities; • Focused communication initiatives; • Specialized assistance supporting Eni SpA and Italian and foreign subsidiaries; • Centralized governance model of Cyber Security, with units dedicated to cyber intelligence and prevention, monitoring and management of cyber attacks; • Rules dedicated to IT security management and information protection; • Operating plans aimed at increasing security of industrial sites (in Italy and abroad), training and awareness initiatives dedicated to Eni’s employees; • Evolution of methodology aimed at evaluation of Cyber Security risk for a more efficient and effective management of cyber risk, in particular through a model review of economic and operational estimated impact and risk exposure for each asset. • Audit activities on compliance with anti-corruption regulations and 231 → Ref. pages 101-102 Legislative Decree. → Ref. page 100 INTEGRATED RISK MANAGEMENTEni Annual Report 201824 GOVERNANCE 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 shareholders’ rights. With this in mind, recognising the need for a deeper dialogue with the market and in continuity with initiatives undertaken since 2013, on January 30, 2018, Eni organised a “corporate governance roadshow” in London involving the Chairman of the Eni Board of Directors and the main institutional investors of Eni to present among other things the main initiatives Eni has undertaken, with a focus on the internal control and risk management system, the Advisory Board and the Company’s commitment (from the Board on down) to an even stronger compliance culture and to climate change actions. The Eni Corporate Governance Eni corporate governance model 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. Appointment and composition of corporate bodies Eni’s Board of Directors and Board of Statutory Auditors, and their respective Chairmen, are elected by the Shareholders’ Meeting. To ensure the presence of Directors and Statutory Auditors selected by non-controlling shareholders a slate voting mechanism is used. Eni’s Board of Directors and Board of Statutory Auditors, whose term runs from April 2017 until the Shareholders’ Meeting called to approve the 2019 financial statements, are made up of 9 and 5 members, respectively. Three directors and two standing 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. 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 structure of the Board of Directors The Board of Directors appointed a Chief Executive Officer and established four internal committees with advisory and recommendation functions: the Control and Risk Committee3, COMPOSITION OF THE BOARD OF DIRECTORS Slate 3 Independence(a) Gender diversity Age(b) 2 2 3 2 6 7 6 5 majority minority independent non independent male female 40–50 years 51–60 years 61–70 years (a) Independence as defined by applicable law. (b) Figures at December 31, 2018. (1) For more detailed information on the Eni Corporate Governance system, please see the Corporate Governance and Shareholding Structure Report, which is published on the Company’s website in the Governance section. (2) Independence as defined by applicable law, to which the Eni By-laws refer. Under the Corporate Governance Code, 6 of the 9 serving directors are independent. (3) As regards the composition of the Control and Risk Committee, Eni requires that at least two members shall have appropriate experience with accounting, financial or risk management issues, exceeding the requirements of the Corporate Governance Code, which recommends only one such member. In this regard, on April 13, 2017 the Eni Board of Directors determined that 3 of the 4 members of the Committee, including the Chairman, have the appropriate experience. The level of experience of the Committee members therefore exceeds that provided for in the Committee Rules. 25 the Remuneration 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 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. 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 requirements5. The following chart summarises the Company’s corporate governance structure at March 14, 2019: BOARD OF DIRECTORS CHIEF EXECUTIVE OFFICER (CEO) CHAIRMAN Claudio Descalzia Emma Marcegagliab DIRECTORS (NON-EXECUTIVE) Andrea Gemmad Pietro A. Guindanic Karina Litvackc Alessandro Lorenzic Diva Morianid Fabrizio Paganie* Domenico Livio Tromboned C C C C M M M S U ST AIN A BILIT Y MITTEE MITTEE MITTEE C O N T R O L MIN A TIO N MIT TEE R E M U N E R A TIO N C O A N D S C E N A RIO S C O A N D RIS K C O C O N O CHAIRMAN C M OFFICER IN CHARGE OF PREPARING FINANCIAL REPORTS Massimo Mondazzi (Chief Financial Ofﬁcer) Eni SpA Shareholders' Meeting SENIOR EXECUTIVE VICE PRESIDENT INTERNAL AUDIT Marco Petracchini BOARD SECRETARY AND CORPORATE GOVERNANCE COUNSEL (Company Secretary) Roberto Ulissi*** ENI WATCH STRUCTURE AND GUARANTOR OF THE CODE OF ETHICS Attilio Befera (Chairman)f Ugo Draettaf Claudio Varronef Luca Franceschinig Marco Petracchinih Stefano Speronii Domenico Noviellol BOARD OF STATUTORY AUDITORS (SOA Audit Committee) CHAIRMAN Rosalba Casiraghic STATUTORY AUDITORS** Enrico Maria Bignamic Paola Camagnid Andrea Parolinid Marco Seracinid AUDIT FIRM EY SpA MAGISTRATE OF THE COURT OF AUDITORS Manuela Arrigucci**** a Member appointed from the majority list. b Member appointed from the majority list non-executive and independent pursuant to law. c Member appointed from the minority list and independent pursuant to law and Corporate Governance Code. d Member appointed from the majority list and independent pursuant to law and Corporate Governance Code. e Member appointed from the majority list, non-executive and non independent. External member. Executive Vice President Integrated Compliance. f g h i l * ** Senior Executive Vice President Internal Audit. Senior Executive Vice President Legal Affairs. Until December 31, 2018 Marco Bollini. Executive Vice President Labour Law and Dispute. The Advisory Board is chaired by Director Fabrizio Pagani and composed of leading international energy experts: Ian Bremmer, Christiana Figueres, Philip Lambert and Davide Tabarelli. The following are Alternate Auditors: Stefania Bettoni - Member appointed from the majority list. Claudia Mezzabotta - Member appointed from the minority list. *** Also Senior Executive Vice President Corporate Affairs and Governance. **** Adolfo Teobaldo De Girolamo until February 28, 2019. (4) The Rules of the Remuneration Committee require that at least one member shall have adequate expertise and experience in finance or compensation policies. These qualifications are assessed by the Board of Directors at the time of appointment. In this regard, on April 13, 2017 the Eni Board of Directors determined that 3 of the 4 members of the Committee have the appropriate expertise and experience. The level of expertise and experience of the Committee members therefore exceeds that provided for in the Committee Rules. (5) The Charter of the Board Secretary and Corporate Governance Counsel (Company Secretary) is available on the Eni website, in the Governance section. GOVERNANCEEni Annual Report 2018 26 The following is a chart setting out the current macro-organizational structure of Eni SpA at March 14, 2019: R. Ulissi Board Secretary and Corporate Governance Counsel (Company Secretary)(a) M. Petracchini Internal Audit Senior Executive Vice President(b) BOARD OF DIRECTORS E. Marcegaglia (Chairman of the Board) C. Descalzi (Chief Executive Ofﬁcer) P. Longhini Assistant to the Chairman of the Board Ofﬁce of the CEO (A. Muccioli) S. Speroni R. Ulissi L. Pistelli M. Bardazzi L. Franceschini J. Trevisan Legal Affairs Senior Executive Vice President(c) Corporate Affairs & Governance Senior Executive Vice President International Affairs Executive Vice President External Communication Executive Vice President Integrated Compliance Executive Vice President Integrated Risk Management Executive Vice President M. Bollini Commercial Negotiations Senior Executive Vice President(d) L. Lusuriello Chief Digital Ofﬁcer(e) M. Mondazzi Chief Financial Ofﬁcer C. Granata Chief Services & Stakeholder Relations Ofﬁcer L. Bertelli Chief Exploration Ofﬁcer A. Puliti Chief Development, Operations & Technology Ofﬁcer L. Cosentino Energy Solutions Executive Vice President A. Vella Chief Upstream Ofﬁcer M. Mantovani Chief Gas & LNG Marketing and Power Ofﬁcer G. Ricci Chief Reﬁning & Marketing Ofﬁcer (a) The Board Secretary and Corporate Governance Counsel (Company Secretary) reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman. (b) The Senior Executive Vice President Internal Audit reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and to the CEO in his capacity as Director in charge of the Internal Control and Risk Management System. (c) In office since January 1st, 2019. (d) From January 1st, 2019. Until 31 December 2018, Senior Executive Vice President Legal Affairs. (e) Since September 18, 2018. Decision making The Board of Directors entrusts the management of the Company to the Chief Executive Officer, while retaining key strategic, operational and organizational powers for itself, especially as regards governance, sustainability6, internal control and risk management. Organizational arrangements 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 and compliance. 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 (6) More specifically, the Board of Directors has reserved for itself decisions concerning the establishment of sustainability policies, the results of which are reported together with financial results in an integrated manner in the Annual Report, as well as the examination and approval of reports covering areas not included in the integrated reporting framework. For more information concerning non-financial disclosures, please see the section of the Report on the Consolidated Disclosure of Non-Financial Information (NFI), pursuant to Legislative Decree No. 254/2016. GOVERNANCE27 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. Reporting flows 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. Ongoing training and self-assessment 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)7, for which benchmarking against national and international best practices and an examination of Board dynamics are essential elements, also with a view to provide shareholders with guidance on the most appropriate professional profiles for members of the Board. Following the Board Review, the Board of Directors develops an action plan, if necessary, to improve the operation of the Board and its Committees. In addition, in 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 the last seven years, most recently in February 2018 in conjunction with the Board Review, is a best practice among Italian listed companies. Eni was among the first Italian companies to perform one, starting in 2012. The Board of Statutory Auditors also conducted its own self- assessment in 2018. 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. Moreover, in order to improve the understanding of Eni’s industrial processes, the Board Induction is accompanied by an ongoing training programme with visits to sites in Italy and abroad. In 2018, in continuity with previous initiatives, additional training sessions were held with visits to labs in the upstream and renewables operational areas, as well as to the Zohr plant in Egypt on the occasion of a meeting of the Board held abroad. The governance of sustainability Eni’s governance structure reflects the Company’s willingness to integrate sustainability into its business model. The Board of Directors has a central role in defining sustainability policies and strategies, acting upon proposal of the CEO, in the identification of annual, four-year and long-term objectives shared between functions and subsidiaries and in verifying the related results, which are also presented to the Shareholders’ Meeting. In detail, a central theme in which the Board of Directors plays a key role is challenge related to the process of energy transition to a low carbon future. The Board of Directors plays a key role in these issues, approving strategic initiatives and long-term objectives on the matter both for the CEO and for Eni management. During 2018, Eni ensured its contribution at the World Economic Forum (WEF) “Climate Governance”8 initiative, with the participation of Eni’s Board of Directors. Another central theme that the Board of Directors oversees is the respect for Human Rights. Indeed, in December 2018, the Board of Directors of Eni SpA approved the Eni Statement on respect for human rights. This document renews the Company’s commitment, aligning it with the main international standards on Human Rights and Business, starting from the United Nations Guiding Principles, highlighting also the priority areas on which this commitment is concentrated. (7) For more information on the Board Review process, see the section devoted to that process in the Corporate Governance and Shareholding Structure Report 2018. (8) The initiative seeks to increase the level of Board awareness on climate-related issues, also in the light of the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD). GOVERNANCEEni Annual Report 201828 THE MAIN SUSTAINABILITY ISSUES ADDRESSED BY THE BOARD IN 2018 • 2017 ﬁnancial statements9, including the Consolidated Non-Financial Statement; • the Remuneration Report, including sustainability targets in the deﬁnition of performance plans; • 2017 HSE Performance; • Voluntary Eni Report on Sustainability (so called “Eni for”); • Sustainability scenario; • Update of the Statement in compliance with the UK Modern Slavery Act; • Eni’s Statement on respect for human rights; • Climate Governance. The Sustainability and Scenarios Committee In performing its duties in the field of sustainability, the Board is supported by the Sustainability and Scenarios Committee, established for the first time in 2014 by the Board itself, which provides advice and recommendations on scenario and sustainability issues. The Committee plays a key role in addressing the sustainability issues integrated into the Company’s business model10. The Advisory Board At its meeting of July 27, 2017, the Eni Board of Directors established an Advisory Board11, chaired by the Director Fabrizio Pagani and composed of international experts (Ian Bremmer, Christiana Figueres, Philip Lambert and Davide Tabarelli). The Advisory Board is charged with analysing major geopolitical, technological and economic trends, including issues associated with decarbonization, to support the Board itself and the Chief Executive Officer. In 2018, the Advisory Board met three times, in April, June and September, to address matters related to geopolitical developments, Eni’s strategic positioning in a decarbonization scenario, energy market developments, the energy industry transformation and renewable energy. Remuneration Policy Eni’s Remuneration Policy for its Directors and top management is established in accordance with the Governance model adopted by the Company and the recommendations of the Corporate Governance Code. The Policy seeks to attract, motivate and retain 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. 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. Under Eni Remuneration Policy, considerable importance is given to the variable component, also on a per-share basis, which is linked to the achievement of certain results, through incentive plans connected to the fulfilment of preset, measurable and complementary targets which represent the main Company’s priorities in line with the Company’s Strategic Plan and the expectations of shareholders and stakeholders, in order to promote a strong focus on results and combine the operating, economic and financial soundness with social and environmental sustainability, coherently with the long-term nature of the business and the related risk profiles. With regard to sustainability issues, the CEO objectives set for the year 2019 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 basis 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’ Meeting. (9) This is an integrated report that enables Eni’s stakeholders, including non-investors, to understand the connections between financial performance and the outcomes of actions in the environmental and social fields, in accordance with Eni’s integrated business model. (10) For more information on the Committee activities in 2018, please see the relevant section in the Corporate Governance and Shareholding Structure Report 2018. (11) For more information, please see the Eni website, in the Governance section. GOVERNANCE29 2018 TARGETS FOR THE 2019 SHORT-TERM INCENTIVE PLAN WITH DEFERRAL ECONOMIC AND FINANCIAL RESULTS (25%) OPERATING RESULTS AND SUSTAINABILITY OF ECONOMIC RESULTS (25%) ENVIRONMENTAL SUSTAINABILITY AND HUMAN CAPITAL (25%) EFFICIENCY AND FINANCIAL STRENGTH (25%) INDICATORS Earning Before Tax (12.5%) Free Cash Flow (12.5%) INDICATORS Hydrocarbon production (12.5%) Exploration resources (12.5%) INDICATORS CO2 emissions (12.5%) Severity Incident Rate (12.5%) INDICATORS ROACE adjusted (12.5%) Net Debt/EBITDA adjusted (12.5%) LEVERS Upstream expansion Strengthen Gas & Power operations Resilience in downstream Green business LEVERS Fast track approach Expanding exploration acreage Diversiﬁcation LEVERS Decarbonization HSE and sustainability LEVERS Financial discipline Efﬁciency of operating costs and G&A Optimisation of working capital The internal control and risk management system12 Eni has adopted an integrated and comprehensive internal control and risk management system at different levels of the organizational and corporate structure, based on reporting tools, organizational units, regulations, corporate rules and reporting flows between the various control levels and to the management and control bodies of the Company and its subsidiaries. The internal control and risk management system is also based on Eni’s Code of Ethics (as an essential part of the Company’s Model 231), which sets out the rules of conduct for the appropriate management of the Company’s business and which must be complied with by all the members of the Board, as well as of the other corporate bodies and all Eni personnel. Eni has adopted rules 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. At its meeting of October 25, 2018, the Board updated these guidelines, also to reflect recent developments in internal organization and rules concerning Integrated Compliance. Indeed, in 2018 Eni completed the definition of the reference model for Integrated Compliance, which together with Model 231 and the Code of Ethics, is aimed at ensuring that all Eni personnel who are contributing to the achievement of business objectives operate in full compliance with the rules of integrity and applicable laws and regulations in an increasingly complex national and international regulatory framework, defining a comprehensive process, developed using a risk-based approach, for managing activities to prevent non-compliance. With this in mind, risk assessment methodologies were developed aimed at modulating controls, calibrating monitoring activities and planning training and communication activities based on the compliance risk underlying the various cases, to maximize their effectiveness and efficiency. The Integrated Compliance process was designed to stimulate integration between those who work in the business activities and the corporate functions that oversee the various compliance risks, both internal or external to the Integrated Compliance Department. Furthermore, in October 2018, acting on the proposal of the Chief Executive Officer, having obtained a favourable opinion from the Control and Risk Committee, the Board of Directors of Eni approved the internal rules concerning the Market Information Abuse (Issuers). These, by updating the previous Eni rules for the aspects relating to “issuers”, incorporate the amendments introduced by Regulation No. 596/2014/EU of April 16, 2014 and the associated implementing rules, as well as the national regulations, taking account of Italian and foreign institutional guidelines on the matter. The updated internal rules lay down principles of conduct for the protection of confidentiality of corporate information in general, to promote maximum compliance, as also required by Eni’s Code of Ethics and corporate security measures. Eni recognizes that information is a strategic asset to be managed in such a way as to ensure the protection of the interests of the company, shareholders and the market. 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. (12) For more information, please see the Corporate Governance and Shareholding Structure Report 2018. 07_Governance_ING.indd 29 10/05/19 09:21 GOVERNANCEEni Annual Report 2018 30 EXPLORATION & PRODUCTION PERFORMANCE VS. BRENT EXCELLENCE IN OPERATIONS MOVEMENTS IN NET PROVED RESERVES (bboe) Adjusted operating performance (€ million) Brent ($/boe) 43.69 +24% 54.27 +31% +110% +107% 3 7 1 , 5 7 1 0 2 4 9 4 2 , 6 1 0 2 71.04 0 5 8 0 1 , 8 1 0 2 Oil and gas production (mmboe/d) GHG emissions/100% operated hydrocarbon gross production (tonnes CO₂eq/kboe) Proved reserves Net organic additions 2015–2018 Production 2015–2018 Portfolio 2015–2018 23.56 9 5 7 . 1 6 1 0 2 22.75 21.44 6 1 8 . 1 7 1 0 2 1 5 8 . 1 8 1 0 2 0 6 2 . 8 9 . 1 6 3 0 . Organic reserve replacement ratio 2015–2018 131% 9 8 6 . 5 1 0 2 5 1 . 7 8 1 0 2 Performance of the year ● Total recordable injury rate (TRIR) was 0.30, a level that is in the lowest range of the industry average; confirming Eni’s commitment to awareness and dissemination of the safety culture, achieving a reduction of 46% compared to 2014. ● Emissions from flaring were down by 8% from 2017 due to the achievement of the zero flaring configuration in the Burun field in Turkmenistan and the reduction of emergency flaring. This result confirms that we are well on track on our long- term target of zero routine flaring in 2025. In 2018, capital expenditure of flaring down projects was €39 million, in particular in Nigeria and Libya. ● Upstream GHG intensity index was positive with a reduction of 6% from 2017 and 20% from 2014. We achieved these results leveraging on the reduction of emissions from flaring, the gas production of the Zohr field in Egypt and the Jangkrik field in Indonesia as well as an increase production of Goliat field in Norway, which is an asset with lower intensity emission than the upstream average. This performance is in line with the target of 43% reduction in 2025 compared to 2014. ● Water reinjection was 60% in 2018, leveraging on the ongoing programs in certain operational plants, in particular in Egypt and Ecuador. ● In 2018, the E&P segment recorded the best result of the last four years, with an adjusted operating profit more than doubled compared to 2017. This performance reflected more than proportionally strong trend registered in hydrocarbons price scenario in the first ten months of 2018 (a rise of 31% in price of the Brent market benchmark in dollar term) and production growth, which was boosted by a larger weight of barrels with a higher profit per boe. ● Oil and natural gas production was a record level of 1.851 million boe/d, up by 2.5% from 2017 net of price effects. Start-ups and ramp-ups added more than 300 kboe/d to the production level of 2018. ● Net proved reserves at December 31, 2018 amounted to 7.15 bboe based on a reference Brent price of $71.4 per barrel. The all sources replacement ratio was 124%, 100% of organic replacement ratio (105% net of price effects); 131% three-year average organic replacement ratio. The reserves life index was 10.6 years (10.5 years in 2017). DISCOVERED RESOURCES 600 mmboe at a unit cost of 1.5 $/boe EXPANDING FOOTPRINT IN THE MIDDLE EAST ~400 kboe/d production target in the long term RECORD PRODUCTION 1.85 mmboe/d +2.5% from 2017 CASH FLOW PER BOE 22.5 $/boe achieved earlier than planned €$31 Portfolio management ● Signed strategic agreements with the United Arab Emirates, Oman and Bahrain. In particular, the agreements reached in the United Arab Emirates and Oman include exploration, development and production of oil and gas fields, offshore and onshore. The agreement with Bahrain will create further exploration offshore opportunities. Technological innovation, scientific expertise, accelerated start-up and collaboration with host Countries allowed Eni to expand its footprint in a strategic area of the energy industry development: - signed two Concession Agreements related to the acquisition of a 5% participating interest in the Lower Zakum oil field and a 10% participating interest in the Umm Shaif and Nasr oil, condensates and natural gas fields, in the offshore of Abu Dhabi, with duration of 40 years; - awarded a 25% interest of the Ghasha offshore concession in the Abu Dhabi. The concession includes Hal, Ghasha, Dalma gas fields and certain offshore fields in the Al Dhafra area. Production start-up is expected in 2022. In January 2019, Eni was awarded the operatorship of the Block 1 and 2 with a 70% interest, located offshore of the Country; - awarded the offshore exploration Block 47 in Oman and signed a Head of Agreement for the exploration Block 77, located onshore of the Country. Eni will operate both blocks with a 90% interest and 50% interest, respectively; - signed a Memorandum of Understanding with the National Oil and Gas Authority of the Kingdom of Bahrain (NOGA). The Exploration activity ● Exploration activity is also a distinctive approach of Eni’s upstream model, ensuring a large amount of resources at low costs, flexibility in the short-term and fueling growth over the long term. In 2018 additions to the Company’s reserve backlog were 620 million boe of new equity resources. Main discoveries or appraisal activities were in Egypt, Cyprus, Norway, Angola, Nigeria, Mexico and Indonesia. The overall commercial success rate was 66% net to Eni, best performance of the last eighteen years. ● Finalized an agreement with BP and National Oil Company in Libya to boost exploration activities in the Country. The agreement strengthened the parties’ commitment to social development in the Country through the implementation of specific education and technical training programs. ● Awarded a 40% interest of the Blocks 4 and 9 located in the offshore Lebanon. ● Awarded a 100% interest of 124 exploration licenses located in the Eastern North Slope in Alaska with high mineral potential and nearby to existing production facilities. ● Signed the contract for the exploration and development rights of the offshore block A5-A, in the deep offshore of Zambesi. agreement includes an exploration program for the offshore Block 1, an area still largely unexplored, located in the offshore northern territorial area of the Country; - awarded three onshore exploration concessions in the Emirate of Sharjah. ● Dual Exploration Model: - disposal of 10% interest of the Shorouk concession in Egypt, where is located the supergiant gas Zohr field, to Mubadala Petroleum, an United Arab Emirates oil company; - farm-out of part of Eni’s interest in the Nour exploration license in Egypt to BP and Mubadala companies. These companies purchased a 25% interest and 20% interest, respectively; - finalized swap agreements of stake in explorations assets located in Mexico with Lukoil company; - signed an agreement to divest a 35% interest in the Area 1 license, where 2.1 billion of boe in place discovered, to Qatar Petroleum oil company. ● Strengthened the upstream activity in Norway with the the business combination between Eni Norge and Point Resources, leading to the creation of Vår Energi, an equity-accounted joint venture (Eni’s interest 69.6%) that will develop the activities of the two partners in Norway targeting a production plateau of 250 kboe/d in 2023. Eni was awarded the operatorship of the block with a 59.5% interest. ● Awarded a 65% interest in the Area 24 license and a 75% interst in the Area 28 license located in offshore Mexico. Eni operates both licenses. ● Replacing portfolio of exploration leases in the year, added approximately 29,300 square kilometers of new acreage. ● Exploration and appraisal activity was €750 million (€715 million in 2017) and included exploration expenditure and prospecting, geological and geophysical expenses in the year. Exploration and appraisal activity covered approximately 45% of total activity in 2018 and were conducted in particular in Indonesia, Norway, United States, Angola and Vietnam. ● In 2018 exploration expenses were €380 million (€525 million in 2017) and included the write-off of unsuccessful wells amounting to €93 million (€252 million in 2017), which also related to the write-off of unproved exploration rights, if any, associated to projects with negative outcome. The write-off of expenses related to unsuccesful drilling activities mainly concerned projects in Vietnam and Morocco. In addition, 80 exploratory drilled wells are in progress at year-end (40.3 net to Eni). Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION32 Development activity ● During the year production ramp-up was achieved earlier than scheduled at the giant project with a higher profit per boe such as the Zohr and Noroos fields in Egypt, the Jangkrik field in Indonesia, the OCTP project in Ghana as well as the Nenè Marine Phase 2 project in Congo. In addition as planned production started up at the Ochigufu, Vandumbu and UM8 fields in the operated Block 15/06 in Angola, the OCTP gas project to support domestic market in Ghana and the Bahr Essalam Phase 2 and the Wafa compression projects in Libya. ● The co-venturers of Area 4 secured long-term agreements for the purchase of LNG volumes, an important step towards making the final investment decision of the first phase of the Rovuma LNG Project, for the construction of two LNG trains with a capacity of 7.6 mmtonnes/y each and obtaining the project financing. ● Sanctioned the Cabaça North & Cabaça South-East UM4/5 development programs within the East Hub project in the Block 15/06 in Angola. Start-up is expected in 2021. Furthermore, Eni signed an amendment of the Block 15/06 PSA contract that defines an additional exploration acreage in the western area of the block. The agreement confirms Eni’s strategy of the fast-track discoveries developments leveraging on the synergies with existing facilities. ● Sanctioned the operated projects of Area 1 in Mexico with the pilot project’s planned start-up in 2019 and the Merakes discovery in Indonesia, leveraging on the synergy with the existing infrastructures of the Jangkrik field. Overall, in 2018, six projects were sanctioned (in addition to those previously mentioned, in Italy, Egypt and Congo). ● Signed an agreement to purchase of 70% interest and the extension strengthen Eni’s gas portfolio and confirm the success of Eni’s strategy of near field exploration which revamped production in the Nile Delta area. In addition, Egyptian Authorities approved five-years extension of the Ras Qattara concession. Following this agreement, a new exploration campaign will start-up to discover additional hydrocarbons reservers and will allow further exploration activities in the Western Desert Area. ● In March 2019, Eni signed an agreement to divest a 30% interest in the Tarfaya Offshore Shallow exploration license in Morocco to Qatar Petroleum, retaining the operatorship of the permit with a 45% interest. The agreement is subject to approval by the relevant Authorities. ● Signed a memorandum of understanding with the United Nations Development Programme (UNDP) to support sustainable development and help achieve the Sustainable Development Goals (SDGs), in particular access to energy by 2030, climate change initiatives and the protection, restoration and sustainable use of the ecosystem. The agreement confirmed Eni’s commitment to support access to energy, particularly in Africa, and as integrated in our business model. ● Signed with the Food and Agriculture Organization (FAO) a collaboration agreement to promote access to safe and clean water in Nigeria, in particular in the northeast areas, by drilling boreholes, both for domestic use and irrigation purposes. In particular, FAO will support to identify the operations areas as well as technical and know-how collaboration while Eni drilling boreholes which will be powered by photovoltaic systems and will provides for training program of use and maintenance to sustainability in the long term. operatorship of the Oooguruk field, where Eni already holds 30% interest. The Oooguruk field is already productive from 2008, in the Beaufort Sea of the North Slope in Alaska. Production facilities provide for safe and environmentally responsible operations. Additionally, Eni will leverage on the existing excellent relationships and cooperation with the local communities. This agreement will add immediately production and implement significant operational synergies and optimizations with the operated Nikaitchuq field. ● Net capex amounted to approximately €6 billion (€6 billion in 2017) and excluded the capex pertaining to a 10% divested interest in the Zohr project (€170 million) incurred from January 1, 2018 to the closing of the transaction (end of June 2018), which were reimbursed to Eni by the buyer and, as part of the financing agreements with the Egyptian partners relating to the Zohr project, the Company cashed in €280 million as an advance on future gas supplies to Egyptian state-owned companies. ● Approved ten-years extension of the Great Nooros Area’s assets, the most rich basin in the Nile Delta in offshore Egypt. This lease ● In 2018, overall R&D expenditure of the Exploration & Production segment amounted to €96 million (€83 million in 2017). OPERATING REVIEW | EXPLORATION & PRODUCTION33 RESERVES OVERVIEW 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 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 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 stated that those guidelines comply with the SEC regulations1. 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 30 years of experience in the oil and gas industry and more than 20 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 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, 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 (1) The reports of independent engineers are available on Eni website eni.com section Publications/Integrated Annual Report 2016. (2) From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. In 2018, the SGS Company also provided an independent certification. (3) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2018. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION34 adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third party evaluators. In 2018 Ryder Scott Company, DeGolyer and MacNaughton and Societé Generale de Surveillance (SGS) provide an independent evaluation of approximately 26% of Eni’s total proved reserves at December 31, 20184, confirming, as in previous years, the reasonableness of Eni internal evaluation5. In the 2016-2018 three-year period, 95% of Eni total proved reserves were subject to independent evaluation. As at December 31, 2018, the M’Boundi field in Congo was the main Eni property, which did not undergo an independent evaluation in the last three years. 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 2018 proved reserves were as follows: Estimated net proved reserves at December 31, 2017 Extensions, discoveries, revisions of previous estimates and improved recovery, excluding price effect Price effect Reserve additions, total Portfolio Production of the year Estimated net proved reserves at December 31, 2018 Reserves replacement ratio, all sources Reserves replacement ratio, organic Organic reserves replacement ratio, net of price effect (mmboe) Consolidated subsidiaries 6,430 Equity-accounted entities 560 813 (41) (102) 3 711 (38) 772 (196) (650) 6,356 (99) 362 (26) 797 % Total 6,990 673 166 (676) 7,153 124 100 105 Net proved reserves as of December 31, 2018 were 7,153 mmboe, of which 6,356 mmboe of consolidated subsidiaries. Net additions to proved reserves were 673 mmboe and derived from: (i) extensions and discoveries were up by 169 mmboe mainly due to the final investment decisions made for the operated projects of Area 1 in offshore Mexico, Merakes in Indonesia and Argo and Cassiopea offshore Italy; (ii) revisions of previous estimates were up by 491 mmboe and derived from progress in development activities at the Zohr and Nidoco NW projects in Egypt and at the Kashagan project in Kazakhstan; and (iii) improved recovery were up by 13 mmboe mainly reported in particular in Egypt and Iraq. These increases were partly offset the de-booking of 106 mmboe of proved undeveloped reserves at a certain project driven by a deteriorating local operational environment. Net additions were impacted by unfavorable price effects, leading to a downward revision of 38 mmboe, due to an increased Brent price used in the reserves estimation process up to 71.4 $/bbl in 2018 compared to 54.4 $/bbl in 2017. Portfolio transactions of 166 mmboe comprised: (i) the purchase of interests in the Concessions Agreements of Lower Zakum and Umm Shaif and Nasr in Abu Dhabi; (ii) the business combination between Eni Norge AS and Point Resources AS; and (iii) the disposal of a 10% interest in the Zohr project to Mubadala Petroleum and other minor assets. The organic reserves replacement ratio6 was 100% and all sources additions was 124%. These ratios include the de-booking of proved undeveloped reserves at a certain project (down 15 percentage points of reserves replacement ratio). The reserves life index was 10.6 years (10.5 years in 2017). PROVED UNDEVELOPED RESERVES Proved undeveloped reserves as of December 31, 2018 totalled 2,309 mmboe, of which 1,127 mmbbl of liquids mainly concentrated in Africa and Asia and 6,458 bcf of natural gas mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 975 mmbbl of liquids and 6,121 bcf of natural gas. Movements in Eni’s 2018 proved undeveloped reserves were as follows: (mmboe) Proved undeveloped reserves as of December 31, 2017 Reclassification to proved developed reserves Extensions and discoveries Revisions of previous estimates Improved recovery Purchases of minerals in place Sales of minerals in place Proved undeveloped reserves as of December 31, 2018 2,629 (777) 166 278 6 280 (273) 2,309 (4) Includes Eni’s share of proved reserves of equity accounted entities. (5) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2018. (6) Organic ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions and discoveries, to production for the year. All sources ratio includes sales or purchases of minerals in place. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserves Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and environmental risks. OPERATING REVIEW | EXPLORATION & PRODUCTION35 In 2018, total proved undeveloped reserves decreased by 320 mmboe mainly due to: (i) progress in maturing PUDs to proved developed (down by 777 mmboe); (ii) extensions and discoveries (up by 166 mmBOE) due to the final investment decision made for the Area 1 project offshore Mexico and the Merakes project in Indonesia; (iii) revisions of previous estimates (up by 278 mmboe) mainly reported in Egypt due to the development activity of the Zohr project and included the de-booking of 106 mmboe of proved undeveloped reserves at a certain project driven by a deteriorating local operational environment; (iv) improved recovery (up by 6 mmboe) in particular in Iraq; (v) sales of minerals-in-place (down by 273 mmboe) related to disposals in Egypt and other minor assets as described above; and (vi) purchase of minerals-in-place (up by 280 mmboe) related to Abu Dhabi transaction and the business combination in Norway as above mentioned. During 2018, Eni matured 777 mmboe of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects: Zohr (Egypt), Kashagan (Kazakhstan), Bahr Essalam and Wafa (Libya) and Sankofa (Ghana). In 2018, capital expenditures amounted to approximately €6.2 billion and was made to progress the development of proved undeveloped reserves. Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 0.6 bboe of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and decreased 0.4 bboe from 2017 due to the progress in development activities made in Kazakhstan, Iraq and Libya as well as the de-booking of of proved undeveloped reserves at a certain project driven by a deteriorating local operational environment. The proved undeveloped reserves that have remained undeveloped for five years or more at the balance sheet date mainly related to: (i) the Kashagan project in Kazakhstan (0.1 bboe) due to the completion of ongoing development activity (for further information see Main exploration and development projects - Kashagan); (ii) the Zubair field in Iraq (0.1 bboe), where development of PUDs has been conditioned by the drilling of additional production and injection wells to be linked to the production facilities, which were already completed to achieve the full field production plateau of 700 kbbl/d; and (iii) certain Libyan gas fields (0.4 bboe) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreements currently in force. In order to secure fulfillment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields which are expected to be put in production over the next several years. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION36 Estimated net proved hydrocarbons reserves ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 208 156 52 48 44 4 493 317 176 279 153 126 718 551 167 704 587 117 476 252 224 252 143 109 5 5 3,183 2,208 975 297 154 143 11 11 12 8 4 37 32 5 357 205 152 2018 1,199 980 219 320 300 20 2,890 1,447 1,443 5,275 3,331 1,944 3,506 1,871 1,635 1,989 1,846 143 1,217 822 395 277 154 123 651 452 199 17,324 11,203 6,121 360 276 84 14 14 310 57 253 1,716 1,716 2,400 2,063 337 s n o b r a c o r d y H ) e o b m m ( 428 336 92 106 99 7 1,022 582 440 1,246 764 482 1,361 895 466 1,066 925 141 700 403 297 302 170 132 125 87 38 6,356 4,261 2,095 363 205 158 14 14 68 17 51 352 347 5 797 583 214 ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 215 169 46 360 219 141 476 306 170 280 203 77 764 546 218 766 547 219 232 81 151 162 144 18 7 5 2 3,262 2,220 1,042 12 12 12 6 6 136 25 111 160 43 117 2017 1,131 987 144 896 771 125 3,145 1,233 1,912 4,351 1,421 2,930 3,660 1,693 1,967 2,108 1,878 230 1,065 862 203 225 171 54 709 519 190 17,290 9,535 7,755 14 14 349 83 266 1,819 1,819 2,182 1,916 266 s n o b r a c o r d y H ) e o b m m ( 422 350 72 525 360 165 1,052 532 520 1,078 463 615 1,436 856 580 1,150 891 259 427 238 189 203 176 27 137 101 36 6,430 3,967 2,463 14 14 75 20 55 1 1 470 359 111 560 394 166 ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 176 132 44 264 228 36 454 287 167 281 205 76 809 507 302 767 556 211 307 124 183 163 143 20 9 8 1 3,230 2,190 1,040 13 13 15 8 7 140 22 118 168 43 125 2016 977 845 132 878 801 77 3,738 1,732 2,006 5,520 799 4,721 2,767 1,651 1,116 2,485 2,239 246 1,003 280 723 353 338 15 741 559 182 18,462 9,244 9,218 15 15 368 104 264 4 4 3,484 1,782 1,702 3,871 1,905 1,966 s n o b r a c o r d y H ) e o b m m ( 354 287 67 426 374 52 1,139 605 534 1,293 352 941 1,317 809 508 1,221 966 255 491 175 316 227 205 22 145 111 34 6,613 3,884 2,729 14 14 82 26 56 2 2 779 349 430 877 391 486 Consolidated subsidiaries Italy Developed Undeveloped Rest of Europe Developed Undeveloped North Africa Developed Undeveloped Egypt Developed Undeveloped Sub-Saharan Africa Developed Undeveloped Kazakhstan Developed Undeveloped Rest of Asia Developed Undeveloped Americas Developed Undeveloped Australia and Oceania Developed Undeveloped Total consolidated subsidiaries Developed Undeveloped Equity-accounted entities Rest of Europe Developed Undeveloped North Africa Developed Undeveloped Sub-Saharan Africa Developed Undeveloped Rest of Asia Developed Undeveloped Americas Developed Undeveloped Total equity-accounted entities Developed Undeveloped Total including equity-accounted entities Developed Undeveloped 3,540 2,413 1,127 19,724 13,266 6,458 7,153 4,844 2,309 3,422 2,263 1,159 19,472 11,451 8,021 6,990 4,361 2,629 3,398 2,233 1,165 22,333 11,149 11,184 7,490 4,275 3,215 OPERATING REVIEW | EXPLORATION & PRODUCTION 37 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 536 mmboe from producing assets located mainly in Algeria, Australia, Egypt, Ghana, 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 is expected to account for approximately 88% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2018. OIL AND GAS PRODUCTION In 2018, oil and natural gas production averaged 1,851 kboe/d, the highest level ever achieved. This performance was driven by ramp- ups at fields started up in 2017, mainly in Egypt, Indonesia, Angola, Congo and Ghana and the 2018 start-ups (with a total contribution of over 300 kboe/d), higher productions at the Kashagan field, Goliat field in Norway and Val d’Agri in Italy, as well as the acquisition of the two Concession Agreements Lower Zakum (5%) and Umm Shaif and Nasr (10%) producing offshore in the United Arab Emirates. These positives were partly offset by negative price effects at PSAs contracts, lower-than-expected produced gas volumes due to the impact of exogenous factors in certain Countries, the decline of mature fields as well as certain one-off events (termination of the Intisar contract in Libya and unplanned shutdowns). When excluding price effects (down approximately 10 kboe/d), hydrocarbon production increased by 2.5% in the full year. Liquids production amounted to 887 kbbl/d. The ramp-ups of the period and the acquisition in the United Arab Emirates were partly offset by price effects and mature field declines. Natural gas production amounted to 5,261 mmcf/d. Production ramp-ups and start-ups were offset by exogenous factors in certain Countries Oil and gas production sold amounted to 625 mmboe. The 50.6 mmboe difference over production (675.6 mmboe in 2018) mainly reflected volumes of hydrocarbons consumed in operations (43.5 mmboe), changes in inventory levels and other variations. Approximately 70% of liquids production sold (320 mmbbl) was destined to Eni’s mid-downstream business. About 20% of natural gas production sold (1,665 bcf) was destined to Eni’s Gas & Power segment. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION38 Annual oil and natural gas production(a)(b) Consolidated subsidiaries Italy Rest of Europe Croatia Norway United Kingdom North Africa Algeria Libya Tunisia Egypt Sub-Saharan Africa Angola Congo Ghana Nigeria Kazakhstan Rest of Asia China Indonesia Iraq Pakistan Turkmenistan United Arab Emirates Americas Ecuador Trinidad & Tobago United States Australia and Oceania Australia Equity-accounted entities Angola Indonesia Tunisia Venezuela ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 2018 22 41 33 8 56 24 31 1 28 89 41 24 5 19 35 28 1 1 10 2 14 19 4 15 1 1 319 1 1 3 5 155 162 4 88 70 474 38 431 5 445 185 31 55 7 92 97 202 137 14 39 10 2 43 13 30 42 42 1,805 32 2 81 115 s n o b r a c o r d y H ) e o b m m ( 50 71 1 49 21 144 31 111 2 110 123 46 34 7 36 52 65 1 26 13 7 4 14 27 4 2 21 8 8 650 7 1 18 26 ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 2017 19 37 29 8 58 25 32 1 26 90 43 23 3 21 30 20 1 1 15 3 23 4 19 1 1 304 1 1 1 4 7 161 174 6 97 71 640 43 592 5 315 162 17 41 1 103 96 126 69 7 48 2 71 20 51 38 38 1,783 32 4 2 99 137 s n o b r a c o r d y H ) e o b m m ( 49 69 1 47 21 175 33 140 2 84 119 46 30 3 40 48 43 1 14 16 9 3 36 4 4 28 8 8 631 8 1 1 22 32 ) l b b m m ( s d i u q i L s a g l a r u t a N ) f c b ( 2016 17 40 31 9 60 28 31 1 28 91 40 26 25 24 28 1 1 23 3 25 4 21 1 1 314 1 1 5 7 172 184 10 95 79 584 43 536 5 218 170 18 54 98 93 90 18 7 63 2 94 26 68 42 42 1,647 11 7 2 93 113 s n o b r a c o r d y H ) e o b m m ( 49 73 2 48 23 167 36 129 2 68 122 43 36 43 41 45 1 4 25 12 3 43 4 5 34 8 8 616 2 2 2 22 28 Total 324 1,920 676 311 1,920 663 321 1,760 644 (a) Includes Eni’s share of equity-accounted equities. (b) Includes volumes of hydrocarbons consumed in operations (43.5, 35.2 and 32.1 mmboe in 2018, 2017 and 2016, respectively). OPERATING REVIEW | EXPLORATION & PRODUCTION 39 Daily oil and gas production(a)(b) Consolidated subsidiaries Italy Rest of Europe Croatia Norway United Kingdom North Africa Algeria Libya Tunisia Egypt Sub-Saharan Africa Angola Congo Ghana Nigeria Kazakhstan Rest of Asia China Indonesia Iraq Pakistan Turkmenistan United Arab Emirates Americas Ecuador Trinidad & Tobago United States Australia and Oceania Australia Equity-accounted entities Angola Indonesia Tunisia Venezuela s d i u q i L ) d / l b b k ( s a g l a r u t a N ) d / f c m m ( 2018 426.2 444.9 11.4 241.8 191.7 1,299.1 105.5 1,180.3 13.3 1,218.5 505.4 84.2 150.3 19.3 251.6 265.2 550.7 376.5 36.7 106.1 27.2 4.2 118.9 35.7 83.2 114.3 114.3 4,943.2 89.2 2.2 4.4 221.7 317.5 60 113 89 24 154 65 86 3 77 244 111 65 15 53 94 77 1 3 28 6 39 52 12 40 2 2 873 3 3 8 14 s n o b r a c o r d y H ) d / e o b k ( 138 194 2 134 58 392 85 302 5 300 337 127 92 18 100 143 177 1 71 34 20 11 40 75 12 7 56 23 23 1,779 19 1 4 48 72 s d i u q i L ) d / l b b k ( s a g l a r u t a N ) d / f c m m ( 2017 441.6 476.4 16.9 265.4 194.1 1,753.0 117.2 1,623.1 12.7 862.7 444.3 45.9 112.6 2.7 283.1 263.7 345.9 0.1 188.8 19.6 131.5 5.9 194.0 55.4 138.6 105.0 105.0 4,886.6 89.0 11.0 4.1 270.5 374.6 53 102 81 21 158 68 87 3 72 247 119 63 8 57 83 53 2 3 40 8 63 12 51 2 2 833 3 1 3 12 19 s n o b r a c o r d y H ) d / e o b k ( 134 189 3 129 57 479 90 384 5 230 327 126 83 9 109 132 116 2 38 43 24 9 99 12 10 77 22 22 1,728 20 3 4 61 88 s a g l a r u t a N ) d / f c m m ( 2016 471.2 501.8 26.5 258.3 217.0 1,594.8 115.5 1,464.8 14.5 597.4 464.3 49.0 148.5 266.8 254.0 245.8 48.5 19.2 172.1 6.0 256.4 69.7 186.7 113.9 113.9 4,499.6 29.1 18.8 4.9 254.8 307.6 s d i u q i L ) d / l b b k ( 47 109 86 23 165 77 84 4 76 247 108 71 68 65 78 2 3 64 9 69 10 59 3 3 859 1 1 3 14 19 s n o b r a c o r d y H ) d / e o b k ( 133 201 5 133 63 458 98 353 7 185 333 118 98 117 111 123 2 12 67 32 10 116 10 13 93 24 24 1,684 6 4 4 61 75 Total 887 5,260.7 1,851 852 5,261.2 1,816 878 4,807.2 1,759 (a) Includes Eni’s share of equity-accounted equities. (b) Includes volumes of hydrocarbons consumed in operations (119,97 and 88 kboe/d in 2018, 2017 and 2016, respectively). Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 40 PRODUCTIVE WELLS In 2018, oil and gas productive wells were 8,170 (2,836.6 of which represented Eni’s share). In particular, oil productive wells were 6,640 (2,070.1 of which represented Eni’s share); natural gas productive wells amounted to 1,530 (766.5 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 and Gas (Topic 932). Productive oil and gas wells(a) Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania (units) 2018 Oil wells Natural gas wells Gross 202.0 477.0 592.0 1,194.0 2,747.0 200.0 955.0 270.0 3.0 6,640.0 Net 157.0 86.5 242.8 508.3 550.4 55.1 336.7 132.1 1.2 2,070.1 Gross 479.0 135.0 116.0 147.0 181.0 167.0 284.0 21.0 1,530.0 Net 415.9 65.3 63.2 48.3 23.0 62.0 81.7 7.1 766.5 (a) Includes 1,445 gross (420.8 net) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well. DRILLING ACTIVITIES EXPLORATION ACTIVITIES In 2018, a total of 24 new exploratory wells were drilled (15.6 of which represented Eni’s share), as compared to 25 exploratory wells drilled in 2017 (15.9 of which represent Eni’s share) and 16 exploratory wells drilled in 2016 (10.2 of which represented Eni’s share). The following tables show the number of net productive, dry and in progress exploratory wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). The overall commercial success rate was 62% (66% net to Eni) as compared to 60% (52% net to Eni) in 2017 and 50% (50% net to Eni) in 2016. Exploratory Well Activity 2018 Net wells completed(a) 2017 2016 Wells in progress at Dec. 31(b) 2018 Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania (units) productive 1.8 dry(c) productive dry(c) productive 0.5 0.5 1.5 2.6 5.1 1.2 0.5 2.5 2.9 0.5 7.6 1.3 5.4 0.3 0.1 0.5 5.5 0.1 7.0 6.2 1.7 0.4 2.2 4.0 10.1 dry(c) 1.0 0.4 1.0 0.8 1.1 0.9 1.0 6.2 gross 1.0 12.0 8.0 11.0 31.0 6.0 8.0 2.0 1.0 80.0 net 0.5 3.5 7.0 8.9 15.1 1.0 2.5 1.5 0.3 40.3 (a) Includes number of wells in Eni’s share. (b) Includes temporary suspended wells pending further evaluation. (c) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well. OPERATING REVIEW | EXPLORATION & PRODUCTION 41 DEVELOPMENT ACTIVITIES In 2018, a total of 209 development wells were drilled (80.2 of which represented Eni’s share) as compared to 178 development wells drilled in 2017 (90.7 of which represented Eni’s share) and 296 development wells drilled in 2016 (118.7 of which represented Eni’s share). The drilling of 38 development wells (10.6 of which represented Eni’s share) is currently underway. The following tables show the number of net productive, dry and in progress development wells in the years indicated by the Group and its equity-accounted entities in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). Development Well Activity 2018 Net wells completed(a) 2017 2016 Wells in progress at Dec. 31 2018 (units) productive dry(b) productive dry(b) productive dry(b) gross Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania 3.0 2.8 9.6 30.7 7.3 0.9 21.9 2.3 0.8 79.3 0.3 0.5 0.1 0.9 2.6 2.7 5.1 49.7 8.6 1.2 15.0 3.1 88.0 0.2 2.3 0.2 4.0 5.6 6.2 32.4 21.2 4.6 31.6 9.9 2.7 115.5 0.7 0.5 0.2 0.5 1.3 3.2 net 1.3 1.4 2.1 2.5 0.3 3.0 16.0 3.0 5.0 6.0 1.0 7.0 38.0 10.6 (a) Includes number of wells in Eni’s share. (b) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well. ACREAGE In 2018, Eni performed its operations in 43 Countries located in five continents. As of December 31, 2018, Eni’s mineral right portfolio consisted of 902 exclusive or shared rights of exploration and development activities for a total acreage of 406,505 square kilometers net to Eni (414,918 square kilometers net to Eni as of December 31, 2017). Developed acreage was 28,386 square kilometers and undeveloped acreage was 378,119 square kilometers net to Eni. In 2018, main changes derived from: (i) new leases mainly in the United Arab Emirates, Indonesia, Lebanon, Morocco, Mexico, Norway and the United States for a total acreage of approximately 31,000 square kilometers; (ii) the total relinquishment of licenses mainly in Australia, China, Egypt, Indonesia, Morocco, Pakistan, Russia, the United Kingdom and Ukraine covering an acreage of approximately 35,000 square kilometers; (iii) interest increase mainly in Angola and Ireland for a total acreage of approximately 2,000 square kilometers; and (iv) partial relinquishment in Cyprus, Gabon and Indonesia or interest reduction mainly in Egypt, Norway and Pakistan for approximately 6,400 square kilometers. In October 2018, Eni submitted to the relevant Authorities of Portugal the documentation required for voluntary release of exploration concessions, with effective date as of January 31, 2019. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 42 Oil and natural gas interests December 31, 2017 December 31, 2018 ) a ( e g a e r c a t e n l a t o T EUROPE Italy Rest of Europe Croatia Cyprus Greenland Montenegro Norway Portugal United Kingdom Other Countries AFRICA North Africa Algeria Libya Morocco Tunisia Egypt Sub-Saharan Africa Angola Congo Gabon Ghana Ivory Coast Kenya Liberia Mozambique Nigeria South Africa Other Countries ASIA Kazakhstan Rest of Asia China India Indonesia Iraq Lebanon Myanmar Oman Pakistan Russia Timor Leste Turkmenistan United Arab Emirates Vietnam Other Countries AMERICAS Ecuador Mexico Trinidad & Tobago United States Venezuela Other Countries AUSTRALIA AND OCEANIA Australia 51,206 16,380 34,826 987 17,967 1,909 614 2,117 3,182 5,805 2,245 161,981 25,797 1,141 13,294 9,804 1,558 9,192 126,992 4,367 1,471 5,283 579 2,905 43,948 585 978 7,370 26,202 33,304 184,029 1,543 182,486 7,154 5,244 22,889 446 13,558 77,146 7,401 20,862 1,230 180 23,132 3,244 6,641 1,985 1,146 66 1,052 1,066 1,326 11,061 11,061 t s e r e t n i f o r e b m u N 317 140 177 6 2 1 106 3 57 2 261 64 42 11 1 10 53 144 58 25 4 3 3 6 6 34 1 4 61 7 54 7 1 13 1 2 4 1 12 2 1 1 3 5 1 252 1 8 230 6 7 11 11 l d e p o e v e d s s o r G ) b ( ) a ( e g a e r c a s s o r G l d e p o e v e d n u ) a ( e g a e r c a s s o r g l a t o T ) a ( e g a e r c a l d e p o e v e d t e N ) b ( ) a ( e g a e r c a l d e p o e v e d n u t e N ) a ( e g a e r c a ) a ( e g a e r c a t e n l a t o T 13,757 9,962 3,795 2,886 909 46,263 8,846 3,283 1,963 3,600 5,423 31,994 8,200 1,430 226 22,138 13,024 2,391 10,633 77 2,943 1,074 3,390 200 2,949 4,419 1,985 1,173 1,261 1,140 1,140 58,376 8,871 49,505 22,790 4,890 1,228 9,630 4,547 3,719 2,701 258,232 48,760 187 24,673 23,900 10,480 198,992 13,241 1,320 4,107 1,127 4,010 50,677 3,911 8,631 65,505 46,463 285,289 3,890 281,399 5,215 13,110 27,230 3,653 24,080 90,760 11,486 53,930 1,538 5,020 30,777 14,600 12,543 4,387 1,949 1,543 4,664 4,611 4,611 72,133 18,833 53,300 22,790 4,890 1,228 12,516 4,547 4,628 2,701 304,495 57,606 3,470 26,636 23,900 3,600 15,903 230,986 21,441 2,750 4,107 1,353 4,010 50,677 3,911 30,769 65,505 46,463 298,313 6,281 292,032 5,292 13,110 30,173 1,074 3,653 24,080 90,760 14,876 53,930 1,538 200 7,969 30,777 14,600 16,962 1,985 4,387 3,122 2,804 4,664 5,751 5,751 9,409 8,303 1,106 492 614 11,844 3,640 1,124 958 1,558 2,018 6,186 1,064 843 100 4,179 3,368 442 2,926 13 1,198 446 872 180 217 3,056 1,985 574 497 709 709 36,923 6,684 30,239 17,111 1,909 614 2,136 3,182 3,404 1,883 153,855 30,292 31 12,336 17,925 3,230 120,333 4,239 628 4,107 479 2,905 43,948 978 3,543 26,202 33,304 178,046 1,101 176,945 5,215 5,244 22,571 1,461 13,558 77,146 4,914 17,975 1,230 1,255 23,132 3,244 6,247 3,000 1,617 569 1,061 3,048 3,048 46,332 14,987 31,345 17,111 1,909 614 2,628 3,182 4,018 1,883 165,699 33,932 1,155 13,294 17,925 1,558 5,248 126,519 5,303 1,471 4,107 579 2,905 43,948 978 7,722 26,202 33,304 181,414 1,543 179,871 5,228 5,244 23,769 446 1,461 13,558 77,146 5,786 17,975 1,230 180 1,472 23,132 3,244 9,303 1,985 3,000 2,191 1,066 1,061 3,757 3,757 Total 414,918 902 78,603 619,051 697,654 28,386 378,119 406,505 (a) Square kilometers. (b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves. OPERATING REVIEW | EXPLORATION & PRODUCTION 43 Main producing assets (Group share in %) and the year in which Eni started operations ITALY REST OF EUROPE (1926) Operated Adriatic and Ionian Sea Barbara (100%), Cervia/Arianna (100%), Annamaria (100%), Clara NW (51%), Luna (100%), Angela (100%), Hera Lacinia (100%) and Bonaccia (100%) Basilicata Region Val d’Agri (60.77%) Sicily Region Gela (100%), Tresauro (45%), Giaurone (100%), Fiumetto (100%), Prezioso (100%) and Bronte (100%) Norway(a) (1965) Operated Goliat (45.24%), Marulk (13.92%), Balder & Ringhorne (69.6%) and Ringhorne East (53.85%) United Kingdom Non-operated Åsgard (10.31% ), Kristin (5.74%), Heidrun (3.60%), Mikkel (10.37%), Tyrihans (4.32%), (1964) Operated Morvin (20.88%), Great Ekofisk Area (8.62%), Boyla (13.92%), Brage (8.53%) and Snorre (0.7%) Liverpool Bay (100%) and Hewett Area (89.3%) Non-operated Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%) NORTH AFRICA Algeria(b) (1981) Operated Blocks 403a/d (from 65% to 100%), Block ROM North (35%), Blocks 401a/402a (55%), Block 403 (50%) and Block 405b (75%) Non-operated Block 404 (12.25%) and Block 208 (12.25%) Libya(b) (1959) Non-operated Onshore contract areas Tunisia (1961) Operated EGYPT(b)(c) (1954) Operated Area A (former concession 82 - 50%), Area B (former concession 100/ Bu-Attifel and Block NC 125 - 50%), Area E (El Feel - 33.3%), Area F (Block 118 - 50%) and Area D (Block NC 169 - 50%) Area C (Bouri - 50%) and Area D (Blocco NC 41 - 50%) Offshore contract areas Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%), Djebel Grouz (50%), MLD (50%) and El Borma (50%) Shorouk (Zohr - 50%), Nile Delta (Abu Madi West/Nidoco - 75%), Sinai (Belayim Land, Belayim Marine and Abu Rudeis - 100%), Melehia (76%), North Port Said (Port Fouad - 100%), Temsah (Tuna, Temsah and Denise - 50%), Baltim (50%), Ras Qattara (El Faras e Zarif - 75%), West Abu Gharadig (Raml - 45%), Ashrafi (50%) and North Razzak (100%) Non-operated Ras el Barr (Ha’py and Seth - 50%) and South Ghara (25%) SUB-SAHARAN AFRICA Angola (1980) Operated Block 15/06 (36.84%) Congo (1968) Non-operated Block 0 (9.8%), Development Areas in the Block 3 and 3/05-A (12%), Development Areas in the Block 14 (20%), Lianzi Development Area in the Block 14 K/A IMI (10%) and Development Areas in the Block 15 (20%) Nené Marine (65%), Litchendjili (65%), Zatchi (55.25%), Loango (42.5%), Ikalou (100%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi (82%), Kouakouala (74.25%), Zingali (100%) and Loufika (100%) Operated Ghana Nigeria Non-operated Pointe-Noire Grand Fond (35%) and Likouala (35%) (2009) Operated Offshore Cape Three Points (44.44%) (1962) Operated OMLs 60, 61, 62 and 63 (20%), OML 125 (100%) and OPL 245 (50%) Non-operated(d) OML 118 (12.5%) and OML 116 service contract KAZAKHSTAN(b) (1992) Non-operated(e) Karachaganak (29.25%) Non-operated Kashagan (16.81%) REST OF ASIA Indonesia (2001) Operated Jangkrik (55%) Iraq (2009) Operated(f) Zubair (41.6%) Pakistan (2000) Operated Bhit/Bhadra (40%) and Kadanwari (18.42%) Non-operated Latif (33.3%), Zamzama (17.75%) and Sawan (23.7%) Turkmenistan (2008) Operated Burun (90%) United Arab Emirates (2018) Non-operated Lower Zakum (5%) and Umm Shaif and Nasr (10%) AMERICAS United States (1968) Operated Gulf of Mexico Allegheny (100%), Appaloosa (100%), Pegasus (85%), Longhorn (75%), Devils Towers (75%) and Triton (75%) Alaska Nikaitchuq (100%) Non-operated Gulf of Mexico Alaska Texas Europa (32%), Medusa (25%), Lucius (8.5%), K2 (13.4%), Frontrunner (37.5%) and Heidelberg (12.5%) Oooguruk (30%) Alliance area (27.5%) Venezuela (1998) Non-operated Perla (50%), Corocoro (26%) and Junín 5 (40%) (a) Assets held by the Vår Energi equity-accounted entities (Eni’s interest 69.6%). (b) In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so‐called operating company. The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni. (c) Eni’s working interests (and not participating interests) are reported. Those include Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the Country. (d) As partners of SPDC JV, Eni holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks. (e) Eni and Shell are co-operators. (f) Eni is leading a consortium of partners including international companies and the national oil company Missan Oil. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION44 MAIN EXPLORATION AND DEVELOPMENT PROJECTS Eni’s exploration and production activities are conducted in many Countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and condition of the leases, licenses and contracts under which these Oil & Gas interests are held vary from Country to Country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These contractual arrangements usually take the form of concession agreements or production sharing agreements: Concessions contracts. Eni operates under concession contracts mainly in Western Countries. Concessions contracts regulate relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation. Both exploration and production licenses are granted generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases): the term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Proved reserves to which Eni is entitled 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. Production Sharing Agreement (PSA). Eni operates under PSA in several of the foreign jurisdictions mainly in African, Middle Eastern, Far Eastern Countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from Country to Country. 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 Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. 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 some service contracts. ITALY Development activities in the Adriatic offshore concerned: (i) maintenance and production optimization; and (ii) within the agreement with the Municipality of Ravenna, planned activities in the field of the environmental protection projects. In addition, during the first half of 2018, as planned, school-work alternation projects and first-level apprenticeship were completed. In the Val d’Agri concession (Eni operator with a 60.77% interest) a digital transformation program of the Viggiano Oil Center was launched. Leveraging on the digital technologies developed by Eni, the project plans to upgrade and increase monitoring processes of plant and environmental safety in site the to improve operational performance. During the year, five projects were completed, reaching a total of 35 projects of the 42 planned projects as part of the 2014 Addendum to the agreement memorandum with the Basilicata Region, which provides environmental and social initiatives as well as sustainable development programs. In the first half of the year, as planned, school-work alternation projects and first-level apprenticeship were completed. Activities defined by the Gas Agreement progressed with a grant to support the energy consumption in the Municipalities of Val d’Agri and for energy efficiency programs. Following the Memorandum of Understanding for the Gela area, signed with the Ministry of Economic Development in November 2014, the Argo and Cassiopea offshore (Eni’s interest 60%) development projects progressed. The optimized project, to reduce significantly the environmental impact, provides the transportation of natural gas produced by offshore wells through a pipeline to a new onshore treatment and compression plant, that will be realized in certain reclaimed area of the Gela Refinery. In addition, within the framework of sustainable local development programs defined by Memorandum of Understanding and in agreement with the Municipality of Gela and the Sicily Region were: (i) school-work alternation projects, first-level apprenticeship, programs to reduce school drop-out as well as university scholarship progressed; and (ii) signed an agreement for the project “Safety food in Gela” to support vulnerable groups through a public-private partnership between Eni, the Municipality of Gela and the Rete del Banco Alimentare NGO. REST OF EUROPE Norway In December 2018 it was finalized the business combination between Point Resources AS and Eni Norge AS, fully-owned by HitecVision and Eni respectively, with the creation of Vår Energi AS, an equity-accounted joint venture. The exchange rate of shares was established so that Eni and the Point Reources shareholders would retain participation interests of 69.6% and 30.4% respectively, in the combined entity. The governance of the new entity is designed to establish joint control of the two shareholders over the combined entity. OPERATING REVIEW | EXPLORATION & PRODUCTION45 The transaction intends to strengthen Eni’s operational structure in the Country and the increase/diversification of the asset portfolios which will ensure a production growth higher than the current portfolio. The combined entity will be a leading Norwegian exploration & production company, built on the existing organizations and leveraging on complementary strengths. The portfolio of the combined company will have 17 producing oil and gas field with a wide geographical reach, from the Barents Sea to the North Sea, thanks to the entry of new assets, including the fields in production of Balder & Ringhorne (Eni’s interest 69.6%), Ringhorne East (Eni’s interest 53.85%), Boyla (Eni’s interest 13.92%), Brage (Eni’s interest 8.53%) and Snorre (Eni’s interest 0.7%). The company will have reserves and resources of more than 1,250 mmboe. Production is expected to achieve 250 kboe/d in 2023 after developing more than 500 mmboe in ten existing assets, with a breakeven price of less than 30 $/bbl. In total, the company plans to invest more than $8 billion over the next five years to bring these projects on stream, revitalize older fields and explore for new resources. Finally, Eni will retain a first offer right in case the Norwegian private equity funds, managed by HitecVision, decide to divest their interest in the venture. In 2019 Vår Energi awarded 13 exploration licenses: (i) the operatorship of two licenses in the North Sea and of two licenses in the Barents Sea; and (ii) the interest of five licenses in the North Sea and of four licenses in the Norway Sea. Exploration activities yielded positive results with: (i) delineation well of the Cape Vulture oil and gas discovery in the PL 128/128D license (Eni’s interest 8%), nearby to the production facilities of the Norne field (Eni’s interest 4.8%). The results of the well confirm the commerciality of the discovery with recoverable volumes between 50 and 70 million boe; (ii) new oil discovery in the PL 532 license (Eni’s interest 20.88%). The well is located nearby to the Johan Castberg developing project in the area and Eni estimates the resources in place of oil and gas to be between 50 and 60 million boe; (iii) the Goliat West oil well in the PL 229 license (Eni’s interest 45.24%), increasing the estimated reserves of the Goliat production field; and (iv) an oil and gas discovery in the PL 869 which is participated by Vår Energi AS with a 20% interest. Development activities concerned: (i) the Trestakk project (Eni’s interest 5,5%), with start-up expected in 2019 and a production of 4 million boe net to Eni; and (ii) the Johan Castberg development project which was sanctioned in June 2018. Start-up is expected in 2022. NORTH AFRICA Algeria In April 2018, Eni signed a framework agreement with Sonatrach to revamp exploration and development program in the Berkine area and to continue a collaboration in the R&D sector. In particular: (i) in July 2018 defined an agreement for upgrading existing facilities of the BRN fields in the Block 403 (Eni operator with a 50% interest) and of the MLE fields in the Block 405b (Eni operator with a 75% interest) leveraging on synergies with the new forthcoming facilities. The agreement also includes the construction of a pipeline to link the BRN fields with MLE assets, targeting to transform the area in a gas hub; and (ii) in October 2018 signed an agreement to assign to Eni a 49% interest in the Sif Fatima II, Zemlet El Arbi and Ourhoud II concessions, in the North Berkine basin. Management plans an exploration campaign and fast-track development of the estimated reserves of 75 mmboe net to Eni. The production start-up is planned in the third quarter of 2019 leveraging on the completion of the BRN-MLE pipeline that will link the BRN associated gas as well as associated gas and condensates of the Berkine North development project to the MLE treatment facilities. In addition, Eni and Total signed two partnership agreements for an exploration campaign in the offshore Algeria. In particular, in December 2018, two exploration permits were assigned to launch a seismic data acquisition in 2019. Development activities concerned: (i) production optimization at the ROM North (Eni’s interest 35%) and ROD (Eni’s interest 55%) operated fields as well as in the non-operated Block 404 (Eni’s interest 12.25%); (ii) drilling activities in the Block 405b at the CAFC Oil and MLE projects, as well as upgrading activity of existing treatment facilities; and (iii) progress in the development program of the El Merk field in the Block 208 (Eni’s interest 12.25%) with the drilling of production and water injection wells. Libya In 2018, Eni finalized an agreement with NOC oil state company and BP to award a 42.5% interest and the operatorship in the BP contractual areas, in particular in the onshore areas A and B and in the offshore area C. The agreement provides for a revamp exploration and development activities in the Country leveraging on Eni’s facilities existing in the areas. In addition, the agreement strengthens the partnership in the social development initiatives through implementation of education and training programs. During the year, development activities concerned: (i) production start-up of the Bahr Essalam Phase 2 offshore project (Eni’s interest 50%) where the planned activities progressed and the completion is expected in the second quarter of 2019. The development plan provided for drilling ten wells, out of which seven were completed and started up in 2018, as well as upgrading the existing facilities to increase production capacity; (ii) upgrading of gas treatment plants at the Mellitah area (Eni’s interest 50%) and Sabratha platform (Eni’s interest 50%); and (iii) production optimization plan in the Wafa field (Eni’s interest 50%). The activity provided for drilling additional wells and the construction of new compression units. In particular, the infilling wells campaign started in 2018: a first gas well was completed in November 2018 and a second one in March 2019. The project is expected to be completed in 2019. Following the Memorandum of Understanding signed in 2017 to promote health and education initiatives of local communities, two starting programs were defined: (i) support to the local Health Authorities, in particular with a renovation program of the hospital in the Jalo area, technical assistance and medical training initiatives; and (ii) the construction of a pipeline for the desalination plant in the Zuara area to provide drinking water to local communities. In 2018, Eni signed a Memorandum of Understanding with the GECOL national power company and NOC oil state company that includes the start-up of a rehabilitation project for power plants to support access to energy for local communities. In addition, other Eni’s programs to support local communities progressed. In particular: (i) initiatives in the field of health, water and access to energy nearby to the Bu-Attifel (Eni’s interest 50%) and the El Feel (Eni’s interest 33.3%) production areas; (ii) health and oil & gas training program; and (iii) renovation and construction of facilities for social purposes as well as drugs supplies. Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION46 EGYPT In February 2019, Eni was awarded two onshore exploration blocks: (i) a 100% interest in the South East Siwa block in the western desert nearby to the South West Meleiha concession (Eni’s interest 100%); and (ii) the operatorship with a 50% interest in the West Sherbean block in the onshore Nile Delta nearby to the operated Nooros producing fields (Eni’s interest 75%). In case of exploration success, the development activities will benefit from the existing facilities. Exploration activities yielded positive results with: (i) the Faramid- S1X gas well in the East Obayed concession (Eni’s interest 100%); (ii) the A-2X and B1-X oil discoveries and the A-1X gas and condensates discovery in the South West Meleiha concession; and (iii) the Nour-1 gas well in the Nour exploration license. In June 2018, Eni completed the disposal of a 10% interest of the Zohr project (Eni’s interest 50%) to Mubadala Petroleum, for a cash consideration of $934 million. In August 2018, Egyptian Authority approved the following agreements: (i) Eni was awarded an 85% interest in the Nour exploration license in the eastern offshore Nile Delta. In December 2018, Eni divested a 20% and 25% interest of Nour license to Mubadala Petroleum and BP, respectively. Currently Eni holds 40% interest; (ii) ten years extension from 2021 of the Nile Delta concession (Eni’s interest 75%) which includes Abu Madi West concession with Nooros producing field; (iii) an extension of exploration campaign in the El Qar’a permit (Enis’ interest 75%), which is located in the Great Nooros sizeable producing area; (iv) five years extension of the Ras Qattara concession (Eni’s interest 75%) in the western desert; and (v) an extension of the Faramid development lease (Enis’ interest 100%). In September 2018, one-year earlier than scheduled, the Zohr project achieved the targeted production plateau of 365 kboe/d (110 kboe/d net to Eni) with the completion of the drilling activities and the construction and commisioning of the planned four gas treatment units onshore in addition to the one started at the end of 2017, which increased available treatment capacity to more than 2.1 bcf/d. Management plans to step up the production plateau to 3.2 bcf/d during 2019 by building and commissioning other three gas treatment units and by drilling three additional production wells to reach 13 production wells. As of December 31, 2018, the aggregate development costs incurred by Eni for the Zohr project capitalized in the financial statements amounted to $4.3 billion (€3.8 billion at the EUR/USD exchange rate of December 31, 2018). The capital expenditures of the four-year plan for the production ramp-up at the Zohr field will be financed with the operating cash-flow at the Eni Brent marker scenario. As of December 31, 2018, Eni’s proved reserves booked for the Zohr field amounted to 782 mmboe. Development activities concerned: (i) the Baltim South West project (Eni operator with a 55% interest) in the offshore of the Country. The project sanctioned in 2018 and start-up is expected during 2019; (ii) the completion and start-up of two additional productive wells of the Nooros field (Eni operator with a 75% interest) and the construction of a pipeline for transporting gas to the treatment plan of El Gamil. The completion of the activities is expected in 2019; and (iii) infilling activities and production optimization in the operated Sinai (Eni’s interest 100%), Meleiha (Eni’s interest 76%) and Ras Qattara (Eni’s interest 75%) concessions. In particular, the water reinjection project is completed in the Sinai area, achieving the zero water discharge. Within the social responsibility initiatives are currently being implemented the programs defined by the MoU signed in 2017. The agreement, which integrates the development activities of the Zohr project, defines two action programs, to be implemented in four years. The first included the renovation of the El Garabaa hospital, located nearby the Zohr onshore production facilities and the supply of necessary medical equipment. The planned activities were completed in May 2018. The second project, for an overall expense of $20 million, includes certain socio-economic and health programs to support local communities in the Zohr and Port Said areas. The program defined with the stakeholders and the the local Authorities three main areas: (i) aquaculture and fisheries, in particular the construction of a fish district. The activities started up during 2018; (ii) health care projects. A first project was defined in agreement with the Ministry of Health and includes the construction of a Primary Health Care Center which will provide health services to approximately 60,000 people in the Port Said area. The completion is expected in 2019. In addition, the project provides for the construction of the identified facilities and also further initiatives of health training and prevention; and (iii) programs to support youth, in particular the construction of a youth center with completion expected in 2019. SUB-SAHARAN AFRICA Angola Exploration activities yielded positive results with: (i) the Kalimba and Afoxé oil discoveries in the East Hub project area in the Block 15/06 (Eni operator with a 36.84% interest) with an estimated resources of 400-500 mmbbl of oil in place; and (ii) the Agogo oil discovery in the West Hub project area in the Block 15/06 with an estimated resources of 450-650 mmbbl of oil in place. The development of the discoveries will leverage on synergies with existing facilities. In November 2018, Eni signed an amendment of the Block 15/06 PSA contract that defines an additional exploration acreage in the western area of the block. The agreement confirms Eni’s near-field strategy for a fast-track development of exploration successes leveraging on existing production facilities. Development activities mainly concerned the two producing projects in the Block 15/06. In particular, activity of the West Hub project included: (i) production ramp-up of the Ochigufu field was achieved with a production plateau of 25 kbbl/d; and (ii) production start-up of the Vandumbu field. In the East Hub project development activities concerned: (i) production start-up of UM8 field with the linkage to existing FPSO in the area; (ii) upgrading of certain production facilities; and (iii) the Cabaça North & Cabaça South-East UM4/5 projects were sanctioned; the development plan provides for the drilling of three productive wells, two water injection wells and the connection to the existing production facilities in the area. Start-up is expected in 2021. Planned drilling activities were completed at the Mafumeira Sul producing field in the Block 0 (Eni’s interest 9.8%). Eni also continues its commitment to support socio-economic development in the southern region of the Country, in Huila and Namibe area. In particular, activities progressed with: (i) access to energy from renewable sources and to water; (ii) health initiatives through awareness projects of local communities, staff training programs, energy supplies for the Health Centers and Hospitals, also in the Luanda area; and (iii) scholarship programs. In 2018 activities concerned: (i) start-up of initiatives to support the agricultural development by means of the training centers; (ii) mine OPERATING REVIEW | EXPLORATION & PRODUCTION47 removal programs of certain areas to increase safety, to guarantee land for agricultural use and to improve resilience and stability of the local communities; and (iii) the “Luanda refinery reliability improvement and gasoline production” project. The activities include the development of specific solutions to improve the reliability of the Luanda refinery, to increase the fuel production through the installation of new production units, processes optimization and staff training. During the year a first unplanned maintenance was performed and the training program started. Congo Development activity carried out in 2018 was related to: (i) the Nené Marine Phase 2A producing project in the Marine XII block (Eni operator with a 65% interest) with the completion of drilling activities and the installation of a sealine for the connection to the Litchendjili field production platform in the Marine XII block; (ii) the completion of engineering activities of the Nené Marine Phase 2B project. The project was sanctioned in December 2018; (iii) activities to increase the power generation of the CEC plant (Eni’s interest 20%) up to 170 MW. Additional gas supply will be ensured by the production of the Marine XII block; and (iv) the water reinjection project of the Loango (Eni’s interest 42.5%) and Zatchi (Eni’s interest 55.25%) operated production fields. The activities of the second phase of the Project Integrated Hinda (PIH) progressed, aiming to improve life condition of local communities. The project includes several initiatives to support socio-economic development, access to water, access to energy, education and health service. In particular, in 2018, the programs concerned: (i) the completion of the CATREP agricultural development project with a training program of 14 agricultural cooperatives, that was supported also by the World Food Program; (ii) renovation and construction of multicultural centers; (iii) scholarship programs, in particular in the Pointe Noire area through the supply of educational material and renovation initiatives; and (iv) programs to strengthen the Primary Health Care services at the Health Centers and others operating in the area, in particular in the maternal and child sphere. In addition, the construction of a training and research center on renewable energy progressed in Oyo, in the north of the Country. Ghana In 2018, the non-associated gas production started up at the operated Offshore Cape Three Points (OCTP) project (Eni’s interest 44.44%). The gas production is sent to an onshore treatment plant to feed the national grid. The OCTP project is the only non-associated gas development project in deep water entirely dedicated to the domestic market in Sub-Saharan Africa. This project will ensure at least 15 years of reliable gas supply with an affordable price, significantly supporting the access to energy and economic development of the Country. The project has been developed in compliance with the highest environmental requirements, zero gas flaring and produced water reinjection. Eni progressed its commitment to improve the living condition of local communities, with training, economic diversification, acces to water and health services initiatives. In 2018, primary education, waste management and access to water projects started up in the western area of the Country. In particular, a well was drilled and a treatment and purification water-system was completed to supply water for approximately 5,000 people located in the Bakanta, Krisan and Sanzule communities. Within the partnership with United Nations Development Programme, certain activities are being designed to reduce the CO2 emissions in the medium-term by means of combating deforestation, access to energy and energy efficiency programs. Mozambique In October 2018, Eni signed the contract for the exploration and development rights of the offshore block A5-A, in the deep offshore of Zambesi. Eni was awarded the operatorship of the block with a 59.5% interest. In March 2019, Eni signed a farm out agreement with Qatar Petroleum to divest a 25.5% interest in the block A5-A. The transaction is subjected by approval of the relevant Authority. The development activities of the Area 4 (Eni’s interest 25%) in the offshore Mozambique concerned the Coral field, operated by Eni, and the Mamba Complex discoveries where Eni operates upstream development phase and Exxon Mobil lead the construction and operation of natural gas liquefaction facilities onshore. Development activities of the Coral South project provide for the installation of a floating unit for the treatment, liquefaction and storage of natural gas (FLNG) with a capacity of approximately 3.4 mmtonnes/y fed by 6 subsea wells and start-up expected in 2022. The LNG produced will be sold by Eni and its partners in Area 4 (CNPC and Exxon Mobil via the Mozambique Rovuma Venture SpA operating company and others) to BP under a long-term contract for a period of twenty years with an additional ten years’ option. Within the Mamba Complex discoveries, the Rovuma LNG project provides for the development of the straddling reserves of Area 1 according to its independent industrial plan, coordinated with the operator of Area 1 (Andarko). The development project will include also a part of non-straddling reserves. The project provides the construction of two onshore LNG trains with capacity of approximately 7.6 mmtonnes/y each, feed by 24 subsea wells, the gas treatment, the liquefaction, the storage and the export of LNG. In July 2018, the plan of development (PoD) was submitted to the relevant Authorities for their initial review. The activities progressed with the finalization of the PoD, of preliminary long-term agreements for the purchase of LNG volumes and the project financing. The Final Investment Decision (FID) is expected in 2019 with start-up in 2024. In 2018 , Eni’s programs to support the local communities of the Country progressed with, in partcicular: (i) the scholarship programs in Pemba, also by means of ordinary and extraordinary schools maintenance activities and training initiatives also with an oil & gas training programs; and (ii) health care initiatives, coordinated with the Country’s health Authorities, in the Maputo, Pemba and Palma area, by means of specific initiatives on prevention, facilities constructions and medical equipment supplies, particularly in the Cabo Delgado area. Nigeria Exploration activities yielded positive results with the EPU-05 deep offshore gas discovery in the Gbaran-Kolo Creek-Epu (Eni’s interest 5%) area. Development activities mainly included: (i) workover and rigless activities to support current production as well as maintenance and restoration of damaged facilities due to sabotage and bunkering in the operated OML 60, 61, 62 and 63 blocks (Eni’s interest 20%); (ii) the completion of the water injection project of the Ebocha field in the OML 61 block, achieving a produced water reinjection capacity of approximately 30 kbbl/day; (iii) the phase 2 activities of Okpai Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION48 plant to double the installed power capacity in the OML 60 block; (iv) drilling activities to increase production and workover activities to mitigate mature field decline in the OML 118 block (Eni’s interest 12.5%) and in the operated OML 125 block in the Abo field (Eni’s interest 100%); and (v) associated gas program of Forkados Yokri Integrated Project in the OML 43 block (Eni’s interest 5%) as well as Gbaran phase 2A/2B and SSAGS project in the OML 28 block (Eni’s interest 5%). Gas production will be sold to the local market. In February 2018, Eni signed with the Food and Agriculture Organization (FAO) a collaboration agreement to foster access to safe and clean water in Nigeria, mainly in the north-east areas, by drilling boreholes powered with photovoltaic systems, both for domestic use and irrigation purposes. Eni’s programs to support local communities progressed with: (i) acces to energy and to water initiatives; (ii) economic programs for diversification purposes, in particular with the Green River Project; (iii) professional training and scholarship programs; and (iv) renovation and construction of health centers and supply of medical equipment. Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny gas liquefaction plant located in the Eastern Niger Delta. The plant is operational, with a treatment capacity of approximately 1,236 bcf/y of feed gas and a production capacity of 22 mmtonnes/y of LNG. Natural gas supplies to the plant are currently provided under a gas supply agreements from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV (Eni’s interest 20%). In 2018, the Bonny liquefaction plant processed approximately 1,130 bcf. LNG production is sold under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG. KAZAKHSTAN Kashagan In 2019, Experimental Program development of the Kashagan field (Eni’s interest 16.81%) is expected to lead to plateau oil production capacity of about 370 kbbl/d, on a 100% basis. Additional phases of development are being studied, which contemplate increasing gas injection capacity, the conversion of production wells into injection wells and the upgrading of the existing facilities. Within the agreements with local Authorities, training program progressed for Kazakh resources in the Oil & Gas sector, in addition to the realization of infrastructures with social purpose. As of December 31, 2018, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.9 billion (€8.6 billion at the EUR/USD exchange rate of December 31, 2018). This capitalized amount included: (i) $7.3 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.6 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years. As of December 31, 2018, Eni’s proved reserves booked for the Kashagan field amounted to 614 mmboe, slightly decreased from 2017. Karachaganak Within the gas treatment expansion projects of the Karachaganak field (Eni’s interest 29.25%), the Karachaganak Process Center Debottlenecking project was sanctioned. Activities progressed with completion expected in 2020. Additional reinjection capacity will be ensured by installing a new reinjection facility in addition to the existing ones. Eni continues its commitment to support local communities in the nearby area of the Karachaganak field. In particular, activities focused on: (i) professional training; and (ii) realization of kindergartens and schools, maintenance of bridges and roads, construction of sport centers. As of December 31, 2018, Eni’s proved reserves booked for the Karachaganak field amounted to 452 mmboe, reporting a decrease of 78 mmboe from 2017 mainly due to an increased marker Brent price used in the reserves estimation process. REST OF ASIA Indonesia Exploration activities yielded positive results with the Merakes East discovery in the operated East Sepinggan block (Eni’s interest 85%). In May 2018, Eni was awarded a 100% interest in the East Ganal exploration block in the deep offshore Kutei area nearby to the operated Muara Bakau block (Eni’s interest 55%). In 2018, within the portfolio rationalization, Eni divested entire interest in the Sanga Sanga permit. Development activities concerned the offshore Merakes gas project in the operated East Sepinggan block. In December 2018, the development plan was sanctioned by the relevant Authorities. The project provides for the drilling of five subsea wells, which will be linked to the Floating Production Unit (FPU) of the Jangkrik producing field (Eni operator with a 55% interest). Natural gas production is processed by the FPU and then delivered by pipeline to the onshore plant, which is linked to the East Kalimantan transport system to feed Bontang liquefaction plant or will be sold on a spot basis in the domestic market. Start-up is expected in 2020. Ongoing initiatives and projects progressed in the field of environmental protection, health care and educational system to support local communities located in the operated areas of the Eastern Kalimantan, Papua and North Sumatra. In 2018, the following programs were launched: (i) to promote access to energy and to water for the local communities; and (ii) training agricultural activities. In addition, health initiatives were defined. United Arab Emirates In 2018, assets acquisition campaign was launched by Eni targeting to expand footprint in the Country. In particular, the following acquisitions of exploration and production assets in Abu Dhabi were finalized: (i) in March 2018, Eni signed two Concession Agreements related to the acquisition of a 5% participating interest in the Lower Zakum oil field and a 10% participating interest in the Umm Shaif and Nasr oil, condensates and natural gas fields, in the offshore of Abu Dhabi, for a consideration of $875 million with duration of 40 years; (ii) in November 2018, Eni was awarded a 25% interest of the Ghasha offshore concession with duration of 40 years. The concession includes Hail, Ghasha, Dalma gas fields and certain offshore fields in the Al Dhafra area. Production start-up is expected in 2022; and (iii) in January 2019, Eni was awarded the operatorship of the Block 1 and 2 with a 70% interest, located offshore Abu Dhabi. The exploration commitment for the first phase consists in exploration studies for the Block 1 and the drilling of two exploration wells and two appraisal wells in the Block 2. In January 2019 Eni was awarded three onshore exploration concessions in the Emirate of Sharjah: (i) the operatorship with a 75% interest in the concession Area A and C; and (ii) a 50% interest in the concession Area B. The exploration commitment of the first phase OPERATING REVIEW | EXPLORATION & PRODUCTION49 includes the drilling of one exploration well and exploration studies in concessions Area A and B as well as exploration studies in Area C. AMERICAS Mexico In 2018, Eni signed the following agreements: (i) with the Lukoil company to swap interest in three exploration licenses. In particular, the agreement provides for Eni divests its 20% interest in Area 10 (Eni’s interest 100%) and Area 14 (Eni’s interest 60%) licenses and purchases a 40% interest in Area 12 license operated by Lukoil; and (ii) to divest its 35% interest of the Area 1 (Eni’s interest 100%) to Qatar Petroleum Company. The agreements are subject to approval by the relevant Authorities. Furthermore, in 2018, Eni was awarded the operatorship with a 65% interest of the Area 24 license and with 75% of the Area 28 license. In July 2018, the plan of development for the Amoca, Mitzón and Tecoalli discoveries, located in the Area 1, was approved by the Mexican Authorithies. The phased approach for the development plan includes an early production start-up in 2019 through the installation of a production platform and the realization of facilities to connect the platform to an onshore existing treatment plant, with a production of 8 kbbl/d. The full field development envisages a phased installation of three additional platforms and a FPSO, which will increase the production capacity up to 90 kbbl/d in 2021. In 2018, certain initiatives to support local communities were implemented and held events with local stakeholders nearby to the license areas in development of Area 1. In addition, the first Local Development Plan was finalized, in agreement with the local Authorities, concerning the future programs to support the communities. United States In August 2018, Eni was awarded a 100% interest of 124 licenses in Alaska. The licenses are located in the the Eastern North Slope of Alaska, a high mineral potential area, nearby to the existing production facilities. In December 2018, Eni signed an agreement to purchase of a 70% interest and the operatorship of the Oooguruk field, where Eni already holds 30% stake. The agreement has been finalized in 2019. Development activities concerned the Lucius Subsequent Development project (Eni’s interest 8.5%) with the drilling and completion of three submarine productive wells, which will be linked to the production platform of the Lucius field and upgrading of existing facilities. CAPITAL EXPENDITURE Capital expenditure of the Exploration & Production segment (€7,901 million) concerned mainly development of oil and gas reserves (€6,506 million) directed mainly outside Italy, in particular in Egypt, Ghana, Norway, Libya, Nigeria, Congo and Iraq. Development expenditure in Italy in particular concerned sidetrack and workover activities in mature fields. Acquisition of proved and unproved properties of €869 million concerned the entry bonuses in the Concession Agreement of the Lower Zakum and Umm Shaif and Nasr producing fields as well as in the Ghasha offshore concession, in the United Arab Emirates. Exploration expenditure (€463 million) concerned mainly the United States, Egypt, Mexico, the United Arab Emirates and Indonesia. In 2018 overall expenditure in R&D amounted to €96 million (€83 million in 2017). A total of 10 new patents applications were filed. Capital expenditure Acquisition of proved and unproved properties Egypt Sub-Saharan Africa Rest of Asia Exploration Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Development Italy Rest of Europe North Africa Egypt Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Other expenditure TOTAL (€ million) 2018 869 869 463 1 52 20 80 22 140 146 2 6,506 380 600 525 2,205 1,635 193 550 381 37 63 7,901 2017 5 5 442 5 186 55 70 25 3 20 76 2 7,236 260 399 626 3,030 1,852 197 666 195 11 56 7,739 2016 2 2 417 11 42 270 30 57 7 7,770 407 590 747 1,700 2,176 707 1,213 220 10 65 8,254 Change 864 % Ch. .. (5) 869 21 (4) (134) (35) 10 (3) (3) 120 70 (730) 120 201 (101) (825) (217) (4) (116) 186 26 7 162 .. .. 4.8 (80.0) (72.0) (63.6) 14.3 (12.0) (100.0) .. 92.1 (10.1) 46.2 50.4 (16.1) (27.2) (11.7) (2.0) (17.4) 95.4 .. 12.5 2.1 Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 50 GAS & POWER ADJUSTED OPERATING PROFIT € million 2016 201 7 20 18 (390) 214 543 POWER PLANTS GHG EMISSIONS GHG emissions/kWheq (gCO2eq/KWheq) Electricity produced (TWh) 398 395 2 2 6 1 0 2 2 2 7 1 0 2 402 2 2 8 1 0 2 LNG SALES bcm 2016 2017 2018 8.1 8.3 10.3 Performance of the year ● In 2018, the total recordable injury rate (TRIR) amounted to 0.56, increasing by 51.4% compared to 2017, as result of the higher number of accidents (+2 events) registered among the contractors, partly offset by the better performance in the employees. operating profit of €543 million, more than doubled compared to 2017 following the restructuring of all business lines, in particular the growth in LNG sales, power optimizations and reduction of gas logistic costs, supported by a scenario which allowed to enhance the flexibility of the portfolio assets. ● The greenhouse gas emissions (GHG) reported an improved performance, approximately 2%, due to lower power generation (down by 3.6% vs. 2017). ● Eni worldwide gas sales amounted to 76.71 bcm, down by 4.12 bcm or 5.1% compared to 2017. Eni’s sales in Italy (39.03 bcm) increased by 4% compared to 2017. ● GHG emissions/kWheq relating to electricity production slightly increased by 1.8% compared to the previous year due to the higher consumption of refinery gas in place of natural gas at the Ferrera Erbognone site. ● Electricity sales recorded an increase of 5% (up by 1.74 TWh) compared to 2017, due to higher volumes sold to the Italian power exchange. ● In 2018, the Gas & Power segment reported an adjusted gas marketing activities and the power business. ● Capital expenditure amounting to €215 million mainly related the Agreements for the purchase of LNG volumes In order to strengthen the integration with upstream business Eni, obtained from the partners of Area 4 joint venture, long-term agreements for the purchase of LNG volumes. For more details see the “Mozambique” section in the Exploration & Production segment. LNG CONTRACTED VOLUMES ELECTRICITY SOLD GAS SALES IN ITALY RETAIL CUSTOMERS IN ITALY AND EUROPE 8.8 MTPA +70% vs. 2017 37.07 TWh +4.9% vs. 2017 39.03 bcm +4.3% vs. 2017 9.2 million 51 Energy efficiency services In January 2019, Eni through the subsidiary Eni gas e luce SpA, completed the acquisition of the controlling interest of SEA SpA, an energy service company operating in the field of services and solutions for energy efficiency. This transaction confirmed the strategy aiming to strengthen Eni’s presence in the energy efficiency services market, through the growth of commercial offer with integrated and innovative solutions, mainly focused on the industrial segment and apartment buildings. Portfolio optimization in Europe Completed the sale of gas distribution activities in Hungary with a distribution network of about 33,700 kilometers and 1.2 million of delivery points. In July 2018, in line with the planned portfolio rationalization, Eni acquired the further 51% interest, reaching to 100% of the company “Gas Supply Company Thessaloniki-Thessalia SA”, gas and electricity supplier in the retail market in Greece, with approximately 300,000 customers. In March 2018, the subsidiary Adriaplin finalized the acquisition of 100% of the company Mestni Plinovodi, which managed gas distribution and commercialization in 11 municipalities located in the central-north and north-eastern part of Slovenia. In May, Mestni Plinovodi was incorporated into Adriaplin to make fully operational the synergies between the two companies. Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers. Overall Eni supplies 9.2 million retail customers in Italy and Europe. In particular, clients located all over Italy are 7.7 million. In a trading environment characterized by a still decreasing demand (down by 3% in the Italian market compared to the previous year and down by 2% in the European Union) and characterized by a raised competitive pressure, Eni carried out a number of initiatives, – such as renegotiation of supply contracts, efficiency and optimization actions – in order to consolidate the business profitability in a weak demand scenario (for further information on the European scenario, see chapter on “Risk factors” below). NATURAL GAS SUPPLY OF NATURAL GAS In 2018, Eni’s consolidated subsidiaries supplied 74.15 bcm of natural gas, down by 4.13 bcm or by 5.3% from the full year 2017. Gas volumes supplied outside Italy from consolidated subsidiaries (68.82 bcm), imported in Italy or sold outside Italy, represented approximately 93% of total supplies, decreased by 4.41 bcm or by 6% from the full year 2017. This mainly reflected lower volumes purchased in Russia (down by 1.85 bcm), in the Netherlands (down by 1.25 bcm), in Algeria (down by 1.16 bcm) and in Norway (down by 0.73 bcm), partly offset by higher purchases in Indonesia (up by 2.32 bcm) driven by higher availabilty of gas volumes from upstream productions and in Qatar (up by 0.20 bcm). Supplies in Italy (5.33 bcm) increased by 5.5% from the full year 2017 due to higher supplied gas volumes from equity production. SUPPLIES OF ENI'S CONSOLIDATED SUBSIDIARIES Italy The Netherlands Russia Algeria Norway Libya Other 7% 21% 9% 74.15 bcm 36% 5% 6% 16% OPERATING REVIEW | GAS & POWEREni Annual Report 201852 Supply of natural gas Italy Russia Algeria (including LNG) Libya Netherlands Norway United Kingdom Indonesia (LNG) Qatar (LNG) Other supplies of natural gas Other supplies of LNG OUTSIDE ITALY TOTAL SUPPLIES OF ENI’S CONSOLIDATED SUBSIDIARIES Offtake from (input to) storage Network losses, measurement differences and other changes AVAILABLE FOR SALE BY ENI’S CONSOLIDATED SUBSIDIARIES Available for sale by Eni’s affiliates TOTAL AVAILABLE FOR SALE (bcm) 2018 5.33 26.24 12.02 4.55 3.95 6.75 2.21 3.06 2.56 5.52 1.96 68.82 74.15 0.08 (0.18) 74.05 2.66 76.71 2017 5.05 28.09 13.18 4.76 5.20 7.48 2.36 0.74 2.36 6.75 2.31 73.23 78.28 0.31 (0.45) 78.14 2.69 80.83 2016 6.00 27.99 12.90 4.87 9.60 8.18 2.08 3.28 5.83 1.91 76.64 82.64 1.40 (0.21) 83.83 2.48 86.31 Change 0.28 (1.85) (1.16) (0.21) (1.25) (0.73) (0.15) 2.32 0.20 (1.23) (0.35) (4.41) (4.13) (0.23) 0.27 (4.09) (0.03) (4.12) % Ch. 5.5 (6.6) (8.8) (4.4) (24.0) (9.8) (6.4) .. 8.5 (18.2) (15.2) (6.0) (5.3) (74.2) 60.0 (5.2) (1.1) (5.1) In 2018, main gas volumes from equity production derived from: (i) Italian gas fields (3.9 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.6 bcm); (iii) Indonesia (1.6 bcm); (iv) Libyan fields (1.4 bcm); and (v) the United States (0.3 bcm). Supplied gas volumes from equity production were approximately 9.9 bcm representing 13% of total volumes available for sale. SALES OF NATURAL GAS In a 2018 scenario characterized by a raised competitive pressure and a decrease in demand, natural gas sales amounted to 76.71 bcm (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities), down by 4.12 bcm or 5.1% from the previous year. Gas sales by entity Total sales of subsidiaries Italy (including own consumption) Rest of Europe Outside Europe Total sales of affiliates (net to Eni) Rest of Europe Outside Europe WORLDWIDE GAS SALES Sales in Italy (39.03 bcm) increased by 4.3% from the full year 2017 mainly driven by higher sales to spot market and volumes sold to wholesalers and industrial segment, partly offset by lower sales to thermoelectrical and residential segment. Sales to importers in Italy (3.42 bcm) decreased by 12.1% from the full year 2017 due to the lower availability of Libyan gas. Sales in the European markets amounted to 26 bcm, a decrease of 24.3% or 8.34 bcm from the full year 2017. Sales in the Extra European markets increased by 3.09 bcm or 59.8% from the full year 2017, due to higher LNG sales in Japan, Pakistan, China and Taiwan, partly offset by lower volumes sold in South Korea and India. (bcm) 2018 73.70 39.03 27.58 7.09 3.01 1.84 1.17 76.71 2017 77.52 37.43 36.10 3.99 3.31 2.13 1.18 80.83 2016 83.34 38.43 40.52 4.39 2.97 1.91 1.06 86.31 Change (3.82) 1.60 (8.52) 3.10 (0.30) (0.29) (0.01) (4.12) % Ch. (4.9) 4.3 (23.6) 77.7 (9.1) (13.6) (0.8) (5.1) GAS SALES IN ITALY Wholesalers Small and medium-sized enterprises Own consumption Italian gas exchange and spot market Power generation Industries Residential 6.11 4.20 1.50 0.79 4.79 39.03 bcm 9.15 12.49 OPERATING REVIEW | GAS & POWER Gas sales by market ITALY Wholesalers Italian gas exchange and spot markets Industries Small and medium-sized enterprises and services Power generation Residential Own consumption INTERNATIONAL SALES Rest of Europe Importers in Italy European markets: Iberian Peninsula Germany/Austria Benelux Hungary UK Turkey France Other Extra European markets WORLDWIDE GAS SALES LNG Europe Outside Europe TOTAL LNG SALES 53 (bcm) 2018 39.03 9.15 12.49 4.79 0.79 1.50 4.20 6.11 37.68 29.42 3.42 26.00 4.65 1.83 5.29 2.22 6.53 4.95 0.53 8.26 76.71 2017 37.43 8.36 10.81 4.42 0.93 2.22 4.51 6.18 43.40 38.23 3.89 34.34 5.06 6.95 5.06 2.21 8.03 6.38 0.65 5.17 80.83 2016 38.43 7.93 12.98 4.54 1.72 0.77 4.39 6.10 47.88 42.43 4.37 38.06 5.28 7.81 7.03 0.93 2.01 6.55 7.42 1.03 5.45 86.31 Change 1.60 0.79 1.68 0.37 (0.14) (0.72) (0.31) (0.07) (5.72) (8.81) (0.47) (8.34) (0.41) (5.12) 0.23 0.01 (1.50) (1.43) (0.12) 3.09 (4.12) % Ch. 4.3 9.4 15.5 8.4 (15.1) (32.4) (6.9) (1.1) (13.2) (23.0) (12.1) (24.3) (8.1) (73.7) 4.5 0.5 (18.7) (22.4) (18.5) 59.8 (5.1) (bcm) 2018 4.7 5.6 10.3 2017 5.2 3.1 8.3 2016 5.2 2.9 8.1 Change (0.5) 2.5 2.0 % Ch. (9.6) 80.6 24.1 In 2018, LNG sales (10.3 bcm, included in the worldwide gas sales) increased from the full year 2017 (up by 24.1%) and mainly concerned LNG supplied from Indonesia, Qatar, Nigeria, Oman and Algeria and marketed in Europe, China, Japan, Pakistan and Taiwan. POWER Availability of electricity Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. As of December 31, 2018, installed operational capacity of EniPower’s power plants was 4.7 GW. In 2018, thermoelectric power generation was 21.62 TWh, down by 0.8 TWh or by 3.6% from 2017. Electricity trading (15.45 TWh) reported an increase of 19.7% thanks to the optimization of inflows and outflows of power. Power sales In 2018, power sales of 37.07 TWh increased by 4.9% from the full year 2017 and were directed to the free market (70%), the Italian power exchange (19%), industrial sites (10%) and other (1%). Compared to 2017, power sales marketed in the free market decreased by 0.62 TWh or by 2.3%, due to lower volumes sold to large customers (down by 2.38 TWh), middle market (down by 1.45 TWh) and small and medium- sized enterprises (down by 0.20 TWh) partly offset by higher volumes sold to wholesalers segment (up by 3.39 TWh). Purchases of natural gas Purchases of other fuels Power generation Steam (mmcm) (ktoe) (TWh) (ktonnes) 2018 4,300 356 21.62 7,919 2017 4,359 392 22.42 7,551 2016 4,334 360 21.78 7,974 Change (59) (36) (0.80) 368 % Ch. (1.4) (9.2) (3.6) 4.9 OPERATING REVIEW | GAS & POWEREni Annual Report 2018 54 AVAILABILITY OF ELECTRICITY Power generation Trading of electricity(a) Total availability Free market Italian Exchange for electricity Industrial plants Other(a) Power sales (TWh) 2018 21.62 15.45 37.07 25.91 7.17 3.49 0.50 37.07 2017 22.42 12.91 35.33 26.53 5.21 3.01 0.58 35.33 2016 21.78 15.27 37.05 27.49 5.64 3.11 0.81 37.05 Change (0.80) 2.54 1.74 (0.62) 1.96 0.48 (0.08) 1.74 % Ch. (3.6) 19.7 4.9 (2.3) 37.6 15.9 (13.8) 4.9 (a) Includes positive and negative imbalances (difference between the electricity effectively fed-in and as scheduled). CAPITAL EXPENDITURE In 2018, capital expenditure amounted to €215 million, mainly related to gas marketing initiatives (€161 million) and to the maintenance, flexibility and upgrading initiatives of combined cycle power plants (€46 million). Capital Expenditure Marketing Marketing Italy Outside Italy Power generation International transport Total of capital expenditure of which: Italy Outside Italy (€ million) 2018 207 161 93 68 46 8 215 139 76 2017 138 102 63 39 36 4 142 99 43 2016 110 69 32 37 41 10 120 73 47 Change 69 59 30 29 10 4 73 40 33 % Ch. 50.0 57.8 47.6 74.4 27.8 100.0 51.4 40.4 76.7 OPERATING REVIEW | GAS & POWER REFINING & MARKETING AND CHEMICALS ADJUSTED OPERATING PROFIT € million REFINING BREAKEVEN MARGIN AND SERM $/barrel Adjusted operating proﬁt Reﬁning & Marketing Adjusted operating proﬁt Chemicals Reﬁning Breakeven Margin Standard Eni Reﬁning Margin (SERM) GHG EMISSIONS/ REFINING THROUGHPUTS tons CO2eq/kt 55 4.2 2 . 4 ~ 6 1 0 2 5.0 8 3 . 7 1 0 2 3.7 0 3 . 8 1 0 2 2016 278 2017 258 2018 253 8 7 2 5 0 3 1 3 5 0 6 4 0 9 3 ) 0 1 ( 6 1 0 2 7 1 0 2 8 1 0 2 Performance of the year ● In 2018, the total recordable injury rate (TRIR) confirms Eni’s ● In 2018, Eni’s refining throughputs amounted to 23.23 mmtonnes, commitment in the field of health and security with a decrease by 9.7% compared to 2017, with both employees and contractors contribution (down by 12.5% and 10.1%, respectively). ● Greenhouse gas emissions (GHG) reported an increase of 4.7% in absolute terms following higher volumes processed. ● Energy efficiency projects contributed to a 2.1% decrease in GHG emissions related to refining throughputs. ● In 2018, the Refining & Marketing and Chemicals segment reported an adjusted operating profit of €380 million, down by €611 million, or 62% from 2017. The Refining & Marketing business reported an adjusted operating profit of €390 million (down by 27%), consistent with an unfavorable refining trading environment (SERM down by 26%). This result was also affected by increased standstills, partly offset by the improved performance in marketing activities driven by the effective commercial initiatives. The Chemical business was negatively affected by rising costs of oil-based feedstock in the first ten months of the year and by a sharp decrease in polyethylene prices during the fourth quarter, thus reporting an adjusted operating loss of €10 million from the adjusted operating profit of €460 million reported in 2017. ● Breakeven refining margin at the budget scenario of exchange rates and oil spreads was 3 $/barrel, in line with the guidance. lower y-o-y (down by 3.3%) due to lower throughputs at the Taranto plant, reflecting higher crude oil volumes processed on behalf of third parties, at the Milazzo refinery due to maintenance standstills and at the Bayernoil refinery following an event occurred in September. These negatives were partially offset by higher volumes processed at the Sannazzaro and Livorno refineries, with the latter affected in 2017 by a shutdown due to a force majeure event. ● Production of biofuels from vegetable oil at the Venice green refinery amounted to 0.25 mmtonnes, up by 4.2% compared 2017. ● Retail sales in Italy were 5.91 mmtonnes, slightly decreased by 1.7% from 2017. ● Retail sales in the rest of Europe (2.48 mmtonnes) were down by 2% compared to the previous year, mainly due to lower volumes traded in Germany, due to the event occurred at Bayernoil refinery and in France. ● Sales of petrochemical products in Europe amounted to 4.94 mmtonnes, recording an increase of 6.3% y-o-y, due to higher intermediates sale volumes. ● Capital expenditure of €877 million mainly related to refining activities. GREEN REFINERY THROUGHPUTS AVERAGE REFINERY PLANT UTILIZATION RATE PRODUCTION OF PETROCHEMICAL PRODUCTS AVERAGE PETROCHEMICAL PLANT UTILIZATION RATE +4 % vs. 2017 at 0.25 mmtonnes 91 % 90% in 2017 9,483 ktonnes +6% vs. 2017 76 % 73% in 2017 56 Acquisition of new refining capacity in the Middle East In January 2019, Eni signed a Share Purchase Agreement with Abu Dhabi National Oil Company (ADNOC) for the acquisition of a 20% interest in the ADNOC Refining company, one of the top worldwide in terms of refining capacity (with an overall capacity of more than 900 kbbl/d). Additionally, the agreement includes the creation of a joint venture engaged in oil products trading activities, participated by Eni with a 20% interest, ADNOC with a 65% interest and Österreichische Mineralölverwaltung (OMV) with a 15% interest. The total consideration of the deal amounts to $3.3 billion, net of acquired debt and possible price adjustments at the closing date. The transaction is subject to the approval by the relevant authorities. The transaction is in line with Eni’s strategy finalized to geographical diversification and value chain integration. Eni, with its expertise, will provide support to the technological development of the three refineries operated by ADNOC Refining, located in Ruwais and Abu Dhabi areas. The agreement, one of the most remarkable transaction finalized in the refining sector, increased downstream capacity by 35% and is expected to halve the breakeven refining margin to 1.5 $/barrel in the long term. Agreements to support circular economy As part of its commitment in circular economy, Eni launched a number of partnerships with some Italian municipalities, Vatican City and multi-utility companies operating in waste treatment and local public transport (in Taranto, Turin, Venice, Rome and in some municipalities of Emilia Romagna) for the exploitation of civil waste and organic raw materials by using them as feedstock to produce energy resources like biofuels. These partnerships aim to Green chemicals development promote the use of Eni Diesel + in local public transport, in order to reduce GHG emissions, thanks to a 15% renewable component, and to establish a network for collecting non-edible feedstock, such as used cooking oil and other waste of biological origin, for the subsequent transformation into biofuel at the Eni biorefineries in Venice and in Gela, with the latter starting from 2019. Eni continues to be focused on its commitment in the development of green chemicals based on use of renewable resources through the acquisition of activities in the segment of green chemicals of the Mossi & Ghisolfi Group, finalized at the year-end. In particular, the new assets will allow the valorization of biomass. Development activities also include the re-launch of the international licensing of a proprietary technology to produce second generation bio-ethanol, to meet the growing demand and sustainability criteria required for bio-fuels. Partnerships Signed a partnership between Versalis and Italian producers to establish a supply chain aimed at recycling synthetic grass from sports fields. Versalis and SABIC, a company active in the reactors segment, signed an agreement to develop an innovative technology for natural gas conversion into synthesis gas to be further transformed into high value fuels and chemicals (such as methanol). New elastomers unit In September 2018, started up a new plant in Ferrara for the production of high value products which will mainly supply the automotive industry. The project, that consolidates the presence of Eni in the territory, will increase overall production capacity, to update elastomer products portfolio and to increase employment. Chemical international development As a part of Eni’s commitment in the chemical international development, was signed an agreement with Mazrui Energy Service, a leading service company in the Oil & Gas industry in the Middle East, to establish a joint venture for the marketing of innovative chemicals. The partnership with Mazrui will enable to enhance the Versalis know-how and proprietary technologies and to compete against major players in the market. OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS 57 REFINING & MARKETING SUPPLY AND TRADING In 2018, were purchased 22.62 mmtonnes of crude (24.28 mmtonnes in 2017), of which 4.14 mmtonnes by equity crude oil, 10.01 mmtonnes on the spot market and 8.47 mmtonnes by producer’s Countries with term contracts. The breakdown by geographic area was as follows: 36% of purchased crude came from the Middle East, 18% from Russia, 14% from Italy, 13% from Central Asia, 10% from North Africa, 3% from West Africa, 2% from North Sea and 4% from other areas. Purchases Equity crude oil Other crude oil Total crude oil purchases Purchases of intermediate products Purchases of products TOTAL PURCHASES Consumption for power generation Other changes(a) TOTAL AVAILABILITY (a) Include change in inventories, decrease due to transportation, consumption and losses. REFINING In 2018, Eni’s refining throughputs in Europe were 23.23 mmtonnes, decreased by 3.3% from 2017 due to the lower throughputs at the Taranto plant, reflecting higher crude oil volumes processed on behalf of third parties maintenance standstills at the Milazzo refinery, and at the Bayernoil refinery following an event occurred in September. These negatives were partially offset by the better performance at the Sannazzaro and Livorno refineries, with the latter affected in 2017 by a shutdown due to a force majeure event. In Italy, the decrease of refinery throughputs (down by 2.2%) was due to the above mentioned drivers. The volumes of biofuels produced from Availability of refined products ITALY At wholly-owned refineries Less input on account of third parties At affiliated refineries Refinery throughputs on own account Consumption and losses Products available for sale Purchases of refined products and change in inventories Products transferred to operations outside Italy Consumption for power generation Sales of products Green refinery throughputs OUTSIDE ITALY Refinery throughputs on own account Consumption and losses Products available for sale Purchases of refined products and change in inventories Products transferred from Italian operations Sales of products REFINERY THROUGHPUTS ON OWN ACCOUNT IN ITALY AND OUTSIDE ITALY of which: refinery throughputs of equity crude on own account TOTAL SALES OF REFINED PRODUCTS IN ITALY AND OUTSIDE ITALY Crude oil sales TOTAL SALES (mmtonnes) 2018 4.14 18.48 22.62 0.65 11.55 34.82 (0.35) (1.27) 33.20 2017 3.51 20.77 24.28 0.96 10.92 36.16 (0.34) (1.76) 34.06 2016 3.43 19.92 23.35 1.35 11.20 35.90 (0.37) (1.92) 33.61 Change 0.63 (2.29) (1.66) (0.31) 0.63 (1.34) (0.01) 0.49 (0.86) % Ch. 17.9 (11.0) (6.8) (32.3) 5.8 (3.7) (2.9) 27.8 (2.5) vegetable oil at the Venice green refinery increased by 4.2% from 2017. Outside Italy, Eni’s refining throughputs were 2.55 mmtonnes, down by approximately 320 ktonnes or 11.1% due to the downtime of the Bayernoil refinery in September. Total throughputs in wholly- owned refineries were 16.78 mmtonnes, up by 0.75 mmtonnes or 4.7% compared to 2017. The refinery utilization rate, ratio between throughputs and refinery capacity, is 91%. Approximately 18.3% of processed crude was supplied by Eni’s Exploration & Production segment, increased from 2017 (15.2%). (mmtonnes) 2018 2017 2016 Change % Ch. 16.78 (1.03) 4.93 20.68 (1.38) 19.30 7.50 (0.54) (0.35) 25.91 0.25 2.55 (0.20) 2.35 4.12 0.54 7.01 23.23 4.14 32.92 0.28 33.20 16.03 (0.34) 5.46 21.15 (1.36) 19.79 6.74 (0.46) (0.34) 25.73 0.24 2.87 (0.22) 2.65 4.36 0.46 7.47 24.02 3.51 33.20 0.86 34.06 17.37 (0.27) 4.51 21.61 (1.53) 20.08 6.28 (0.39) (0.37) 25.60 0.21 2.91 (0.22) 2.69 4.72 0.40 7.81 24.52 3.43 33.41 0.20 33.61 0.75 (0.69) (0.53) (0.47) (0.02) (0.49) 0.76 (0.08) (0.01) 0.18 0.01 (0.32) 0.02 (0.30) (0.24) 0.08 (0.46) (0.79) 0.63 (0.28) (0.58) (0.86) 4.7 .. (9.7) (2.2) (1.5) (2.5) 11.3 (17.4) (2.9) 0.7 4.2 (11.1) 9.1 (11.3) (5.5) 17.4 (6.2) (3.3) 17.9 (0.8) (67.4) (2.5) OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2018 58 MARKETING OF REFINED PRODUCTS In 2018, retail sales of refined products (32.92 mmtonnes) were down by 0.28 mmtonnes or by approximately 1% from 2017, mainly due to the decrease of retail and wholesale sales in Italy and lower volumes marketed in the wholesalers segment in the rest of Europe. Product sales in Italy and outside Italy (mmtonnes) Retail Wholesale Petrochemicals Other sales Sales in Italy Retail rest of Europe Wholesale rest of Europe Wholesale outside Europe Other sales Sales outside Italy TOTAL SALES OF REFINED PRODUCTS 2018 5.91 7.54 0.96 11.50 25.91 2.48 2.82 0.47 1.24 7.01 32.92 2017 6.01 7.64 0.86 11.22 25.73 2.53 3.03 0.45 1.46 7.47 33.20 2016 5.93 8.16 1.02 10.49 25.60 2.66 3.18 0.43 1.54 7.81 33.41 Change (0.10) (0.10) 0.10 0.28 0.18 (0.05) (0.21) 0.02 (0.22) (0.46) (0.28) % Ch. (1.7) (1.3) 11.6 2.5 0.7 (2.0) (6.9) 4.4 (15.1) (6.2) (0.8) Retail sales in Italy In 2018, retail sales in Italy were 5.91 mmtonnes, with a slight decrease compared to 2017 (about 100 ktonnes from 2017 or 1.7%). Average gasoline and gasoil throughput (1,589 kliters) was almost unchanged from 2017. Eni’s retail market share of 2018 was 24%, slightly decreased from 2017 (24.3%). As of December 31, 2018, Eni’s retail network in Italy consisted of 4,223 service stations, lower by 87 units from December 31, 2017 (4,310 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (74 units), closure of low throughput stations (10 units) and the reduction in motorway concessions netted by the new opening (3 units). Retail and wholesale sales of refined products (mmtonnes) Italy Retail sales Gasoline Gasoil LPG Others Wholesale sales Gasoil Fuel Oil LPG Gasoline Lubricants Bunker Jet fuel Other Outside Italy (retail+wholesale) Gasoline Gasoil Jet fuel Fuel Oil Lubricants LPG Other TOTAL RETAIL AND WHOLESALE SALES 2018 13.45 5.91 1.46 4.03 0.38 0.04 7.54 3.25 0.07 0.20 0.44 0.08 0.80 1.98 0.72 5.77 1.30 3.16 0.33 0.14 0.09 0.50 0.25 19.22 2017 13.65 6.01 1.51 4.08 0.38 0.04 7.64 3.36 0.08 0.21 0.44 0.08 0.85 1.96 0.66 6.01 1.21 3.29 0.50 0.13 0.10 0.51 0.27 19.66 2016 14.09 5.93 1.53 3.99 0.36 0.04 8.16 3.70 0.14 0.22 0.49 0.08 1.01 1.82 0.70 6.27 1.27 3.44 0.62 0.13 0.10 0.49 0.22 20.36 Change (0.20) (0.10) (0.05) (0.05) (0.10) (0.11) (0.01) (0.01) (0.05) 0.02 0.06 (0.24) 0.09 (0.13) (0.17) 0.01 (0.01) (0.01) (0.02) (0.44) % Ch. (1.5) (1.7) (3.3) (1.2) (1.3) (3.3) (12.5) (4.8) (5.9) 1.0 9.1 (4.0) 7.4 (4.0) (34.0) 7.7 (10.0) (2.0) (7.4) (2.2) OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS 59 CONSUMPTION AND MARKET SHARE IN ITALY Retail market share (%) Domestic consumption Average throughput (kliters) 24.3 24.3 24.0 1 5 5 , 1 6 1 0 2 8 8 5 , 1 7 1 0 2 9 8 5 , 1 8 1 0 2 Retail sales in the rest of Europe Retail sales in the rest of Europe were 2.48 mmtonnes, reducing from 2017 (down by 2%) due to lower volumes traded in Germany due to the event occurred at Bayernoil refinery and France. At December 31, 2018, Eni’s retail network in the rest of Europe consisted of 1,225 units, decreasing by 9 units from December 31, 2017, mainly in Germany. Average throughput (2,391 kliters) decreased by 49 kliters compared to 2017 (2,440 kliters). Wholesale and other sales Wholesale sales in Italy amounted to 7.54 mmtonnes, unchanged from 2017, mainly due to lower volumes marketed of gasoil offset by higher sales of other products. Wholesale sales in the rest of Europe were 2.82 mmtonnes, down by 6.9% from 2017 due to lower volumes sold in Germany and France, partly offset by higher volumes in Spain. Supplies of feedstock to the petrochemical industry (0.96 mmtonnes) increased by 11.6%. Other sales in Italy and outside Italy (12.74 mmtonnes) slightly increased by 0.06 mmtonnes, due to higher volumes sold to oil companies. CHEMICALS Product availability Intermediates Polymers Production Consumption and losses Purchases and change in inventories TOTAL AVAILABILITY Intermediates Polymers TOTAL SALES (ktonnes) 2018 7,130 2,353 9,483 2017 6,595 2,360 8,955 2016 Change 6,580 2,229 8,809 535 (7) 528 % Ch. 8.1 (0.3) 5.9 (5,085) (4,566) (4,917) (519) (11.4) 540 4,938 3,087 1,851 4,938 257 4,646 2,748 1,898 4,646 853 4,745 2,956 1,789 4,745 283 292 339 (47) 292 110.1 6.3 12.3 (2.5) 6.3 Petrochemical sales of 4,938 ktonnes increased from 2017 (up by 292 ktonnes, or 6.3%). The main increases were registered in olefins (up by 14.8%) and derivatives (up by 20.4%), partly offset by lower sales volumes of polyethylene (down by 6.3%) and elastomers (down by 3.2%). Average unit sales prices of the intermediates business increased by 7.1% from 2017, with olefins and aromatics up by 10.9% and 4.2%, respectively. The polymers reported a decrease of 2.4% from 2017. Petrochemical production of 9,483 ktonnes increased by 528 ktonnes (up by 5.9%) mainly due to higher production of intermediates business (up by 8.1%), in particular derivatives up by 17.6%; the polymers productions were substantially in line despite the improvement of styrenics (up by 8.3%). The main increases in production were registered at the Porto Marghera site (up by 22.9%), due to a recovery of production capacity for a shutdown in 2017, as well as Szàzhalombatta, Mantova and Priolo sites. Decreasing production at the Ferrara, Brindisi and Oberhausen sites due to unplanned shutdowns of the plants in 2018. Nominal capacity of plants is in line with 2017. The average plant utilization rate calculated on nominal capacity was 76.2%, increasing from 2017 (72.8%). BUSINESS TRENDS Intermediates Intermediates revenues (€2,401 million) increased by €413 million from 2017 (up by 20.8%) reflecting the higher commodity prices scenario that influences average intermediates prices of the main product of the business unit. Sales increased by 12.3%, in particular ethylene (up by 30.3%) and derivatives (up by 20.4%) driven by higher availability of product following the shutdowns in 2017. Average unit prices increased by 7.1%, in particular olefins (up by 10.9%) and aromatics (up by 4.1%); decreasing of derivatives (down by 9.3%). Intermediates production (7,130 ktonnes) registered an increase of 8.1% from the last year. Increasing production of derivatives (up by 17.6%), aromatics (up by 8.3%) and olefins (up by 7%). OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2018 60 Polymers Polymers revenues (€2,589 million) decreased by €141 million or 5.2% from 2017 due to lower volumes sold (down by 2.5%), as well as to the decrease of the average unit prices (down by 2.4%). The styrenics business benefitted from higher sold volumes (up by 5.8%) reflecting higher product availability; slightly decrease in prices of sold volumes(down by 1.4%). Polyethylene volumes decreased (down by 6.4%) due to oversupply and competitive pressure from cheaper products streams from the Middle-East and the USA; decreasing of average prices (down by 3.9%). In the elastomers business, a decrease of sold volumes was attributable to SBR rubbers (down by 3.6%), special rubbers EPDM (down by 5.7%) and lattices (down by 16.9%); increasing of thermoplastic rubbers (up by 2.5%) and BR (up by 1.2%). Higher styrenics volumes sold (up by 5.8%) was mainly driven by higher sales of styrene (up by 21.1%), compact polystyrene (up by 8.2%) and expandable polystyrene (up by 5.3%); lower sales of ABS/SAN (down by 16%). Overall, the sold volumes of polyethylene business reported a decrease (down by 6.4%) with lower sales of EVA, LDPE and LLDPE (down by 16.1%, 8.6% and 5.1%, respectively), while volumes of HDPE increased (up by 2.2%). Polymers productions are in line with 2017 (2,353 ktonnes) despite the lower productions of polyethylene (down by 7.3%) and elastomers (down by 2.7%). The styrenics business reported higher production of styrene (up by 12.1%) and HIPS (up by 11.7%). CAPITAL EXPENDITURE In 2018, capital expenditure in the Refining & Marketing and Chemicals segment amounted to €877 million and mainly regarded: (i) refining activity in Italy and outside Italy (€587 million) aiming fundamentally at reconstruction works of the EST conversion plant at the Sannazzaro refinery, reconversion of Gela refinery into a biorefinery, maintain plants’ integrity, as well as initiatives in the field of health, security and environment; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the rest of Europe (€139 million); (iii) in the Chemical business, upgrading activities (€52 million), maintenance (€32 million), environmental protection, safety and environmental regulation (€26 million), as well as upkeeping of plants (€21 million). Research and Development (R&D) expenditure in the Refining & Marketing and Chemicals segment amounted to approximately €44 million. During the year, 20 patent applications were filed. Capital expenditure Refining Marketing Chemicals TOTAL (€ million) 2018 2017 2016 Change 587 139 726 151 877 395 131 526 203 729 298 123 421 243 664 192 8 200 (52) 148 % Ch. 48.6 6.1 38.0 (25.6) 20.3 OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS CORPORATE AND OTHER ACTIVITIES 61 TREATED GROUNDWATER REUSED/REINJECTED mmcm 2016 2018 2017 4.2 12.2 mmcm 2016–2018 4.8 3.2 TECHNOLOGY INNOVATION First patent ﬁling applications (number) R&D expenditure (€ million) 11 1 4 6 1 0 2 7 4 4 7 1 0 2 13 7 5 8 1 0 2 NET SALES FROM OPERATIONS € million 2016 2017 2018 1,343 1,462 1,589 The “Corporate and Other activities” includes the following businesses: (i) the “Corporate and financial companies” segment includes results of operations of Eni’s headquarters (Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions) and Eni’s subsidiaries (Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc, Eni Insurance DAC, EniServizi, Eni Corporate Uninersity, AGI and other minor subsidiaries) which carries out cash management activities, finance, general purposes services and support to Group businesses; (ii) the “Other activities” segment comprises results of operations of Eni’s subsidiary Syndial which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years, as well as Energy Solutions business which engages in developing the business of renewable energy. Performance of the year ● In 2018, the treated groundwater (TAF) and reused in production increased by 12%. This result confirms Eni’s commitment in the growth of groundwater share reclaimed and reused for civil or industrial purposes, in the start-up of initiatives and assessments for the use of low-quality water in place of freshwater and the decrease of water intensity in the operations. logistical services, as well as remediation initiatives carried out for Eni’s Group. ● The capital expenditure reported in 2018 (€143 million) were mainly focused on the development of renewable projects, circular economy and digitalization. ● In 2018,the photovoltaic installed capacity amounted to 39.8 MW. ● In 2018, research and development expenditure amounted to €57 million (€44 million in 2017). 13 patent applications were filed. ● In 2018, the Corporate and Other activities segment reported an increase of revenues of approximately 9% mainly as result of the growth of global client activities, the environmental ● In 2018, the share of recovered/recycled waste increased compared to 2017, reaching approximately 40% of total waste disposed of. GROUNDWATER USED IN PRODUCTION/REINJECTED VS. TOTAL TREATED GROUNDWATER PHOTOVOLTAIC INSTALLED CAPACITY R&D EXPENDITURE 21 % in 2018 39.8 MW in 2018 +30 % vs. 2017 RECOVERED WASTE VS. RECOVERABLE WASTE 58 % in 2018 +10% vs. 2017 62 Main activities of the year Italy Eni’s commitment to renewables projects is going on, through the implementation of the Project Italy. In particular were launched the following photovoltaic plants: (i) in March 2018, the 1MW plant of the Green Data Center in Ferrera Erbognone; (ii) in July 2018, the 1MW plant of Gela in the area called “Isola 10”; and (iii) in September 2018, the 26 MW plant of Assemini. The administrative procedure was launched for the realization of two photovoltaic plants in the production area of Porto Marghera in a context of territorial requalification. In February 2019, was launched the construction of a 31 MW photovoltaic plant in the industrial area of Porto Torres. The project has been authorized by the Relevant Authority with the “Unique Authorization” allowing the construction and operation of the project. The annual production will be addressed, for a 50% share, to the internal consumption of the company located in the industrial site and will allow to avoid the emission of approximately 22,000 tons of CO2eq per year. In December 2018, was launched at Gela refinery the pilot plant Waste to Fuel, a proprietary technology created by Eni which transforms the Organic Fraction of Municipal Solid Waste (OFMSW) into bio-oil, which can be used as bunker fuel or for bio-diesel production. The first production was obtained in January 2019. The success of the pilot project will be a functional reference for the development of further future industrial-scale initiatives. The development of Ponticelle NOI (New Innovation Opportunities) is ongoing at the industrial site of Ravenna, with an overall investment of €60 million. The program includes the permanent safety activities and the innovative, sustainable and productive requalification of the area, according to the pillars of circular economy. The area involved covers approximately 26 hectares where it is foreseen: (i) the realization of a multipurpose environmental platform addressed to the processing of materials coming from the site and other Eni’s activities with the goal of maximize their recovery; (ii) a technology centre for reclamations, to test innovative remediation technologies; (iii) a photovoltaic system to provide energy to support productive activities; and (iv) a Waste to Fuel plant. In March 2019, a Memorandum of Understanding was signed with Veritas, a multi-utility company operating in collection, enhancement and treatment of waste in the Venetian territory. The agreement foresees the realization, in a decommissioned and reclaimed area of Porto Marghera, of a plant that will apply the Waste to Fuel technology to convert organic solid waste into bio-oil or bio-methane. Australia In February 2019, was completed the acquisition of a project for the construction of the 33.7 MW photovoltaic power plant in the site of Katherine, located in the north of the Country. The plant will enter into production at the end of 2019, be equipped with an energy accumulation system and allow to avoid the emission of about 63,000 tonnes of CO2eq per year. Algeria In November 2018, was completed the construction of the 10 MW photovoltaic plant located at the Bir production site Rebaa North (BRN) in Block 403 (Eni’s interest 50%). The plant will provide electricity to the productive facilities of the field and, at the same time, contribute to reduce greenhouse gas emissions, as part of a decarbonization process for the Country’s energy system. Additionally, in order to strengthen the partnership in renewable energy business, Eni signed the following agreements with Sonatrach: (i) for the implementation of a research laboratory at the BRN production site to test solar technologies in a desert environment; (ii) for the creation of a joint venture that will implement and manage solar power plants at the production sites operated by Sonatrach in the Country. Kazakhstan In December 2018, started the building, in partnership with General Electric (GE) of the first Eni’s wind farm energy with a total capacity of 50 MW, located at Badamsha site. The project, which is part of the agreement between Eni, GE and the Minister of Energy of the Republic of Kazakhstan, will enter into operation at the end of 2019. Pakistan In 2018, preliminary activities were launched to build the 10 MW solar system to support the production facilities at the Bhit field (Eni operator with a 40% interest). The start-up is expected in 2019. Tunisia In 2018, two photovoltaic projects were sanctioned: (i) the 5 MW plant for energy supply to the production facilities at the Adam field (Eni operator with a 50% interest); (ii) the 10 MW Tataouine plant (Eni operator with a 50% interest) which provides for the supply of the energy produced to the national company STEG on the basis of a 20-year Power Purchase Agreement. 11_Corporate_ING.indd 62 10/05/19 09:23 OPERATING REVIEW | CORPORATE AND OTHER ACTIVITIES63 FINANCIAL REVIEW PROFIT AND LOSS ACCOUNT Net sales from operations Other income and revenues Operating expenses Other operating income (expense) Depreciation, depletion, amortization Impairment reversals (impairment losses), net Write-off of tangible and intangible assets Operating profit (loss) Finance income (expense) Income (expense) from investments Profit (loss) before income taxes Income taxes Tax rate (%) Net profit (loss) - continuing operations Net profit (loss) - discontinued operations Net profit (loss) attributable to: Eni’s shareholders - continuing operations - discontinued operations Non-controlling interest - continuing operations - discontinued operations (€ million) 2018 75,822 1,116 (59,130) 129 (6,988) (866) (100) 9,983 (971) 1,095 10,107 (5,970) 59.1 4,137 2017 66,919 4,058 (55,412) (32) (7,483) 225 (263) 8,012 (1,236) 68 6,844 (3,467) 50.7 3,377 4,137 3,377 4,126 4,126 3,374 3,374 11 11 3 3 2016 55,762 931 (47,118) 16 (7,559) 475 (350) 2,157 (885) (380) 892 (1,936) 217.0 (1,044) (413) (1,457) (1,464) (1,051) (413) 7 7 Change 8,903 (2,942) (3,718) 161 495 (1,091) 163 1,971 265 1,027 3,263 (2,503) 8.4 760 % Ch. 13.3 (72.5) (6.7) .. 6.6 .. 62.0 24.6 21.4 .. 47.7 (72.2) 22.5 760 22.5 752 752 8 8 22.3 22.3 .. .. .. In the full year of 2018, Eni reported an operating profit of €9,983 million and a net profit attributable to Eni’s shareholders of €4,126 million, increased approximately by 25% and 22% from 2017, respectively. Eni’s results benefitted from a better trading environment and an improved performance. In 2018, Brent prices increased by 31% on average from 2017 to 71 $/barrel, in a highly volatile scenario. In the first ten months of the year, oil prices built on gains peaking at 85 $/barrel in October, the highest level in the last four years, due to a global economic recovery and a balanced demand/supply backdrop. Starting from November, alongside a sharp correction in the global financial markets, oil prices entered a downturn losing about 40% from its peak, falling to approximately 50 $/barrel at the end of the year, due to signs of weakening global growth, oversupply, uncertainty tied to the commercial dispute between USA and China, the Brexit, as well as geopolitical factors. In December, OPEC and Russia announced a production cut of 1.2 million barrel/day effective from 2019. In this scenario, Eni’s E&P segment reported an increase in operating profit of €2.6 billion, leveraging on better prices and production increases, with the latter boosted by a shift in the production mix towards barrels with higher profitability. The G&P segment improved its operating profit by approximately €0.6 billion, driven by the overall restructuring of all the business lines, effective management of flexibilities associated with the portfolio of long-term gas contracts, optimization in the power business and in logistics, as well as growth in the LNG business leveraging its integration with the E&P segment. The downstream oil and chemical businesses (approximately down by €1.4 billion) were negatively affected by a squeeze in margins (the SERM benchmark refining margin was down by 26% to 3.7 $/barrel; the cracker margin down by 11% and the polyethylene margin was down by 69%) because of rapidly-escalating oil-based feedstock costs which were not fully recovered in the final prices of products due to shrinking demand for commodities and competitive pressure from more efficient producers. Declining oil and product prices at year end resulted in a loss on inventory evaluation compared to a gain in the previous year (approximately down €225 million). Extraordinary/non-recurring items reported a loss of €388 million (compared to non-recurring gains of €839 million in the full year of 2017) reflecting the substantial netting between the gain of the business combination of Eni Norge and Point Resources to create Vår Energi (as difference between the fair value of the investment and the book value of disposed net asset) and the effect of suspending the amortization of assets since the beginning of the second half of the year, following the classification as asset held for sale, which offset impairment losses and risk provisions. 64 Average price of Brent dated crude oil in US dollars(a) Average EUR/USD exchange rate(b) Average price of Brent dated crude oil in euro Standard Eni Refining Margin (SERM)(c) PSV(d) TTF(d) 2018 71.04 1.181 60.15 3.7 260 243 2017 54.27 1.130 48.03 5.0 211 183 2016 43.69 1.107 39.47 4.2 168 148 % Ch. 30.9 4.5 25.2 (26.0) 23.2 32.8 (a) Price per barrel. Source: Platt’s Oilgram. (b) Source: ECB. (c) In $/bbl FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields. (d) €/kcm. Cash flow from operating activities amounted to €13,647 million for the full year of 2018 and was up by 35% from the full year of 2017 driven by an improved underlying performance and scenario effects. Adjusted net cash flow from operating activities before changes in working capital at replacement cost was €12,662 million, up by 37% from 2017. This adjusted measure is derived by excluding certain non-recurring charges: an expense recognized in connection with the final outcome of an arbitration proceeding (€313 million), an extraordinary allowance for doubtful accounts in the E&P segment (€158 million) and an expense related to the sale of a 10% interest in the Zohr project due to the fact that they related to the asset disposals. At a Brent price of 71 $/barrel in 2018, adjusted cash flow from operations amounted to approximately €13.45 billion and positive changes in receivables and payables associated with investing activities (mainly including the cash-in of the deferred price of the Zohr disposals made in 2017) amounted to €0.9 billion. Those inflows funded capex of €7.94 billion and the dividend of €2.95 billion, leaving a surplus of around €3.5 billion. Consequently, on the basis of the Group’s cash flow sensitivity to the Brent scenario which assumes a change of approximately €0.19 billion in cash flow for each one-US dollar change in the Brent price (and vice versa), the cash neutrality for funding full year capex and the floor dividend would have been achieved at 52 $/barrel. This is re-determined in 55 $/barrel when excluding from cash inflows the deferred tranches of the consideration on the disposal of Eni’s interests in Zohr made in 2017 (€450 million), being these the unique non-organic components of the cash flow. Net borrowings at December 31, 2018 was €8,289 million, down by €2,627 million as of December 31, 2017. Gearing was 0.14, the lower end of the European peer group and leverage reduced to 0.16, down from 0.23 as of December 31, 2017. Adjusted results and breakdown of special items Operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted operating profit (loss) Net profit (loss) attributable to Eni’s shareholders Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted net profit (loss) attributable to Eni’s shareholders Tax rate (%) (€ million) 2018 9,983 96 1,161 11,240 4,126 69 388 4,583 56.2 2017 8,012 (219) (1,990) 5,803 2016 2,157 (175) 333 2,315 3,374 (156) (839) 2,379 56.8 (1,051) (120) 831 (340) 120.6 Change 1,971 % Ch. 24.6 5,437 93.7 752 22.3 2,204 92.6 Net profit includes special items consist of net charges of €388 million, relating to the following: (i) net impairment losses of certain E&P assets resulting an overall effect of €726 million driven by a lower-than-expected performance at certain fields as well as in order to align them with the fair-value of selling price; (ii) an impairment reversal at certain transportation activities outside Italy due to the reduction of the country risk premium factored in the discount rate (€66 million); (iii) the reinstatement of correlation amounting €375 million between hydrocarbon production and reserve depletion by accruing the underlying UOP-based amortization charges of Eni Norge subsidiary classified as held for sale in accordance to IFRS 5 due to the pending business combination with Point Resources; impairment losses (€193 million) mainly regarding the (iv) write-down of capital expenditure relating to certain Cash Generating Units in the R&M business, which were impaired in previous reporting periods and continued to lack any profitability prospects; (v) a charge taken in connection with the outcome of an arbitration proceeding relating a long-term contract to purchase regasification services, which resulted in the termination of the contract and of the related annual fees charged to Eni. It also awarded the counterparty equitable compensation of €289 million (plus financial interests of €24 million); (vi) valuation allowance for doubtful accounts in connection with cost recovery in E&P segment to align the recoverable amount (€158 million); (vii) a gain recorded on the disposal of a 10% interest in the Shorouk and Nour concessions, offshore Egypt (€339 million net of assignment bonus and other charges); FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 65 (viii) provision for redundancy incentives (€155 million); (ix) environmental provisions (€325 million) mainly relating to R&M (x) and Chemicals and E&P segments; the effects of fair-valued commodity derivatives that lacked the formal criteria to be accounted as hedges under IFRS (net gains of €133 million); (xi) exchange rate differences and derivatives reclassified to operating profit (net gain of €107 million) mainly refferred to G&P segment, related to derivative financial instruments used to manage margin exposure to foreign currency exchange rate movements and exchange translation differences of commercial payables and receivables; (xii) the gain on the business combination involving Eni Norge and Point Resources, fully-owned by Eni and HitecVision respectively, which led to the creation of the equity-accounted joint venture Vår Energi, jointly controlled by Eni (69.6%) and HitecVision, with a gain of approximately €890 million as difference between the fair value of Eni’s interest in the venture and the book value of disposed net assets; (xiii) an impairment reversal (€262 million) at the Angola LNG equity-accounted entity due to improved project economics; (xiv) the impairment of an equity accounted upstream investment (approximately €200 million) due to the de-booking of undeveloped reserves at a certain project driven by a deteriorating operational local environment; (xv) Eni’s interest of extraordinary charges/impairment losses recognized by the Saipem joint venture (€154 million); (xvi) tax effects relating to operating special items, as well as the write-down of deferred taxes relating to Italian subsidiaries due to a deteriorated profitability outlook (€99 million). Breakdown of special items Special items of operating profit (loss) - environmental charges - impairment losses (impairments reversal), net - impairment of exploration projects - net gains on disposal of assets - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - reinstatement of Eni Norge amortization charges - other Net finance (income) expense of which: - exchange rate differences and derivatives reclassified to operating profit (loss) Net (income) expense from investments of which: - gains on disposal of assets - impairments / revaluation of equity investments Income taxes of which: - net impairment of deferred tax assets of Italian subsidiaries - net impairment of deferred tax assets of upstream business outside Italy - USA tax reform - taxes on special items of operating profit and other special items Total special items of net profit (loss) (€ million) 2018 1,161 325 866 (452) 380 155 (133) 107 (375) 288 (85) (107) (798) (909) 67 110 99 11 388 2017 (1,990) 208 (221) (3,283) 448 49 146 (248) 911 502 248 372 (163) 537 277 115 162 (839) 2016 333 193 (459) 7 (10) 151 47 (427) (19) 850 166 19 817 (57) 896 (72) 170 6 (248) 1,244 The breakdown by segment of the adjusted net profit is provided in the table below: Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Impact of unrealized intragroup profit elimination and other consolidation adjustments(a) Adjusted net profit (loss) attributable to: - Non-controlling interest - Eni’s shareholders (€ million) 2018 4,955 310 238 (965) 56 4,594 11 4,583 2017 2,724 52 663 (1,041) (16) 2,382 3 2,379 2016 508 (330) 419 (991) 61 (333) 7 (340) Change 2,231 258 (425) 76 72 2,212 8 2,204 % Ch. 81.9 .. (64.1) 7.3 92.9 .. 92.6 (a) This item concerned mainly intragroup sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 66 Profit and loss analysis Net sales from operations Exploration & Production Gas & Power Refining & Marketing and Chemicals - Refining & Marketing - Chemicals - Consolidation adjustments Corporate and other activities Consolidation adjustments Net sales from operations Other income and revenues Total revenues (€ million) 2018 25,744 55,690 25,216 20,646 5,123 (553) 1,589 (32,417) 75,822 1,116 76,938 2017 19,525 50,623 22,107 17,688 4,851 (432) 1,462 (26,798) 66,919 4,058 70,977 2016 16,089 40,961 18,733 14,932 4,196 (395) 1,343 (21,364) 55,762 931 56,693 Change 6,219 5,067 3,109 2,958 272 127 (5,619) 8,903 (2,942) 5,961 % Ch. 31.9 10.0 14.1 16.7 5.6 8.7 13.3 (72.5) 8.4 Net sales from operations in the full year of 2018 (€75,822 million) increased by €8,903 million or 13.3% from 2017, driven by the recovery of commodity prices. Revenues generated by the Exploration & Production segment (€25,744 million) increased by €6,219 million or up by 31.9%. This was due to higher average realizations on equity hydrocarbons (oil realizations up by 30.8%; gas realizations up by 41% on average in dollar terms) driven by increasing prices for the marker Brent and better gas prices due to the ramp-up of production with higher-than-average gas realizations. Revenues generated by the Gas & Power segment (€55,690 million) increased by €5,067 million or up by 10%. The increase reflected higher natural gas and power prices, as well as increased revenues from trading activity due to higher oil and products selling prices. Revenues generated by the Refining & Marketing and Chemicals segment (€25,216 million) increased by €3,109 million (or up by 14.1%) mainly in the Refining & Marketing business with an increase of €2,958 million due to higher commodity prices. The average selling prices of gasoline and gasoil reported an increase of 14% and 30%, respectively. Revenues generated in the Chemical business slightly increased (up by €272 million) boosted by the increase in average selling prices as well as by higher volumes sold (up by 6%). Eni’s other income and revenues recorded gains on the disposal of non-strategic assets and other revenues. The positive balance of €1,116 million mainly related to the gain on the divestment of a 10% interest in the Zohr project. The reduction from the full year 2017 is due to the gains on disposals recorded in 2017 on the sale of a 40% interest in the Zohr gas field in Egypt (€1,281 million) and of a 25% interest in Area 4 offshore Mozambique (€1,985 million) where development activity is underway. Operating expenses Purchases, services and other Impairment losses (impairment reversals) of trade and other receivables, net Payroll and related costs of which: provision for redundancy incentives and other (€ million) 2018 55,622 415 3,093 155 59,130 2017 51,548 913 2,951 49 55,412 2016 43,278 846 2,994 47 47,118 Change 4,074 (498) 142 % Ch. 7.9 (54.5) 4.8 3,718 6.7 Operating expenses for 2018 (€59,130 million) increased by €3,718 million from 2017, up by 6.7%. Purchases, services and other (€55,622 million) increased by €4,074 million or 7.9% primarily reflecting higher supply cost of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Payroll and related costs (€3,093 million) increased by €142 million from 2017, up by 4.8%, mainly due to the increase in average wages and higher provisions for redundancy incentives. These increases were partly offset by a reduction in the average number of employees outside Italy and the appreciation of the euro against the US dollar. Payroll and related costs include special item of €155 million mainly referring to an early retirement program in the Eni gas e luce SpA subsidiary in accordance with Art. 4 of Italian Law No. 92/2012. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW67 DD&A, impairments, reversals and write-off Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Impact of unrealized intragroup profit elimination Total depreciation, depletion and amortization Impairment losses (impairment reversals), net Depreciation, depletion, amortization, impairments and reversals, net Write-off of tangible and intangible assets (€ million) 2018 6,152 408 399 59 (30) 6,988 866 7,854 100 7,954 2017 6,747 345 360 60 (29) 7,483 (225) 7,258 263 7,521 2016 6,772 354 389 72 (28) 7,559 (475) 7,084 350 7,434 Change (595) 63 39 (1) (1) (495) 1,091 596 (163) 433 % Ch. (8.8) 18.3 10.8 (1.7) (6.6) .. 8.2 (62.0) 5.8 Depreciation, depletion and amortization (€6,988 million) decreased by approximately 7% from 2017, mainly in the Exploration & Production segment due to the interruption of the UOP-based amortization charges of Eni Norge subsidiary (€375 million), classified as held for sale in accordance to IFRS 5 from the second half of the year as a result of the pending business combination with Point Resources, as well as the appreciation of the euro against the US dollar, partly offset by new project start-ups and ramp-ups. The breakdown of impairment charges (€866 million) is shown in the table below: Impairment losses Impairment reversals Impairment losses (impairment reversals), net Impairment losses on receivables related to non-recurring activities Total Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Impairment losses (impairment reversals), net (€ million) (€ million) 2018 1,292 (426) 866 866 2018 726 (71) 193 18 866 2017 862 (1,087) (225) 4 (221) 2016 1,067 (1,542) (475) 16 (459) 2017 (158) (146) 54 25 (225) 2016 (700) 81 104 40 (475) Change 430 661 1,091 (4) 1,087 Change 884 75 139 (7) 1,091 Further information on impairment charges are described in the paragraph “special items”. Write-off of tangible and intangible assets (€100 million) mainly related to the costs of exploratory wells lacking the requisites for continuing capitalization because they did not encounter commercial quantities of hydrocarbons in particular in Vietnam and Morocco. Operating profit The breakdown by segment of the operating profit is provided below: Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Impact of unrealized intragroup profit elimination Operating profit (loss) (€ million) 2018 10,214 629 (380) (691) 211 9,983 2017 7,651 75 981 (668) (27) 8,012 2016 2,567 (391) 723 (681) (61) 2,157 Change 2,563 554 (1,361) (23) 238 1,971 % Ch. 33.5 .. .. (3.4) 24.6 FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 68 Adjusted operating profit The breakdown by segment of the adjusted operating profit is provided below: Operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted operating profit (loss) Breakdown by segment: Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Impact of unrealized intragroup profit elimination and other consolidation adjustments (€ million) 2018 9,983 96 1,161 11,240 10,850 543 380 (606) 73 11,240 2017 8,012 (219) (1,990) 5,803 5,173 214 991 (542) (33) 5,803 2016 2,157 (175) 333 2,315 2,494 (390) 583 (452) 80 2,315 Change 1,971 % Ch. 24.6 5,437 93.7 5,677 329 (611) (64) 106 5,437 109.7 153.7 (61.7) (11.8) 93.7 The increase in adjusted operating profit of €5.4 billion was due to a favourable hydrocarbon prices scenario (€4 billion) and the growth in the underlying performance (€1.4 billion) driven by the production growth and the improved performance of upstream projects with higher profit per boe. The disclosure of adjusted operating profit by segment is provided under the paragraph “Results by business segments”. Finance income (expense) Finance income (expense) related to net borrowings - Finance expense on short and long-term debt - Net interest due to banks - Net income from financial activities held for trading - Net income from receivables and securities for non-financing operating activities Income (expense) on derivative financial instruments - Derivatives on exchange rate - Derivatives on interest rate - Derivates on securities Exchange differences, net Other finance income (expense) - Net income from receivables and securities for financing operating activities - Finance expense due to the passage of time (accretion discount) - Other finance income (expense) Finance expense capitalized (€ million) 2018 (627) (685) 18 32 8 (307) (329) 22 341 (430) 132 (249) (313) (1,023) 52 (971) 2017 (834) (751) 12 (111) 16 837 809 28 (905) (407) 128 (264) (271) (1,309) 73 (1,236) 2016 (726) (757) 15 (21) 37 (482) (494) (12) 24 676 (459) 143 (312) (290) (991) 106 (885) Change 207 66 6 143 (8) (1,144) (1,138) (6) 1,246 (23) 4 15 (42) 286 (21) 265 Net finance expense of €971 million decreased by €265 million from 2017 mainly due to lower finance expenses related to debt which reflected the €2,627 million decrease in net borrowings. This improvement was due to the surplus generated by cash flow from operations after funding capex and dividend. Other finance income (expense) included finance charges due to the write-off of a financing receivables related to an unsuccessful exploration initiative executed by a joint venture in the Black Sea (approximately €270 million). These negatives were partly offset y-o-y by the write-off of 2017 financial receivables due by an equity accounted entities. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 69 Net income from investments The breakdown of the net income from investment of 2018 is provided in the table below: 2018 Share of gains (losses) from equity-accounted investments Dividends Net gains (losses) on disposals Other income (expense), net (€ million) Exploration & Production 158 193 19 885 1,255 Gas & Power 9 (6) 25 28 Refining & Marketing and Chemicals (67) 38 9 Corporate and other activities (168) (20) (168) Group (68) 231 22 910 1,095 Net income from investments amounted to €1,095 million related to: (i) dividends of €231 million paid by minor investments in certain entities which were designated at fair value and mainly related to Nigeria LNG Ltd (€187 million) and Saudi European Petrochemical Co. (€35 million); (ii) other net gains (€910 million) including the net gain on the Vår Energi business combination (approximately €890 million); (iii) the impairment reversal (€262 million) at the Angola LNG equity- accounted entity due to improved project economics partly offset by impairment loss of a joint venture due to deteriorated operating environment (approximately €200 million). These gains were partly offset by Eni’s share of losses recorded by the Saipem joint venture (Eni’s interest 31%) due mainly to the incurrence of impairment losses and certain extraordinary charges by the investee. The table below sets forth a breakdown of net income/loss from investments: Share of gains (losses) from equity-accounted investments Dividends Net gains (losses) on disposals Other income (expense), net (€ million) 2018 (68) 231 22 910 1,095 2017 (267) 205 163 (33) 68 2016 (326) 143 (14) (183) (380) Change 199 26 (141) 943 1,027 Income taxes Income taxes increased by €2,503 million to €5,970 million mainly due to the increase of profit before income taxes (up by €3,263 million from 2017). The reported tax rate was 59% compared to 51% reported in 2017, reflecting lower gains free of taxes or subject to a lower tax rate compared to the Group average tax rate. Adjusted tax rate was 56.2%, slightly lower from 2017, despite a higher tax rate in the E&P segment (approximately 3 percentage point) due to the recognition of lower deferred tax asset relating to certain projects. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 201870 Results by business segments1 Exploration & Production Operating profit (loss) Exclusion of special items: - environmental charges - impairment losses (impairment reversals), net - impairment of exploration projects - net gains on disposal of assets - provision for redundancy incentives - risk provisions - commodity derivatives - exchange rate differences and derivatives - other Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) Results also include: Exploration expenses: - prospecting, geological and geophysical expenses - write-off of unsuccessful wells(b) Average realizations Liquids(c) Natural gas Hydrocarbons (€ million) 2018 10,214 636 110 726 2017 7,651 (2,478) 46 (154) (442) 26 360 (3,269) 19 366 (6) (138) 10,850 (366) 285 (5,814) 54.0 4,955 380 287 93 ($/barrel) ($/kcf) ($/boe) 65.47 5.20 47.48 (68) 582 5,173 (50) 408 (2,807) 50.8 2,724 525 273 252 50.06 3.69 35.06 2016 2,567 (73) (684) 7 (2) 24 105 19 (3) 461 2,494 (55) 68 (1,999) 79.7 508 374 204 170 39.18 3.27 29.14 Change 2,563 % Ch. 33.5 5,677 (316) (123) (3,007) 3.2 2,231 (145) 14 (159) 15.41 1.51 12.42 109.7 81.9 (27.6) 5.1 (63.1) 30.8 41.0 35.4 (a) Excluding special items. (b) Also includes write-off of unproved exploration rights, if any, related to projects with negative outcome. (c) Includes condensates. In 2018, the Exploration & Production segment reported an adjusted operating profit of €10,850 million more than doubled y-o-y and the best result of the last four years. The better performance was driven by higher realized prices on equity hydrocarbons driven by the strong trend in crude oil prices in the first ten months (which drove a 31% rise in price of the Brent market benchmark, in dollar term) as well as production growth. These positives were partly offset by the euro appreciation over the US dollar (up by 4.5%). When excluding scenario effect, the underlying performance reported a significant increase, leveraging on a favorable volume/mix effects, boosted by the increased contribution of barrels with higher unitary profitability. Adjusted operating profit excluded special items of €636 million. Adjusted net profit was €4,955 million, an 82% increase y-o-y due to improved operating performance, partially offset by the write-off of financing receivables granted to a participated joint venture to execute an exploration projects that was written-off in the Black Sea (approximately €270 million), with an additional effect on the adjusted tax rate due to the fact that these expenses were non-deductible. The adjusted tax rate for 2018 increased by approximately 3 percentage points due to the recognition of lower deferred tax asset relating to certain projects. Excluding these effects, tax rate decreased by approximately 2 percentage points. For the full year 2018, taxes paid represented approximately 30% of the cash flow from operating activities of the E&P segment before changes in working capital and income taxes paid. (1) Other alternative performance indicators disclosed are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information, see the section “Alternative performance measures” of this Annual Report at subsequent pages. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW Gas & Power Operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items: - impairment losses (impairment reversals), net - environmental charges - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - other Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) (a) Excluding special items. 71 (€ million) 2018 629 (86) (71) (1) 122 (156) 112 (92) 543 (4) 9 (238) 43.4 310 2017 75 139 (146) 38 157 (171) 261 214 10 (9) (163) 75.8 52 2016 (391) 90 (89) 81 1 17 4 (443) (19) 270 (390) 6 (20) 74 .. (330) Change 554 % Ch. .. 329 (14) 18 (75) (32.4) 258 153.7 .. In 2018, the Gas & Power segment reported an adjusted operating profit of €543 million, the best result of the last eight years, more than doubled the full year 2017. This improvement reflected the overall restructuring of all the business lines mainly driven by growth in the LNG sales, optimizations in the power business and logistics and favorable trends in the first nine months in the natural gas wholesale market which enabled the Company to extract value from the flexibilities associated with the portfolio of long-term supply contracts. Adjusted operating profit excluded special items of €86 million. Adjusted net profit was €310 million, improving by €258 million compared to 2017 when the segment reported an adjusted net profit of €52 million, due to the better operating performance. Adjusted tax rate reflected a normalization at 43.4%, decreasing compared to 75.8% in 2017 which was penalized by a higher impact of certain non-Italian subsidiaries tax rate. Refining & Marketing and Chemicals Operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items: - environmental charges - impairment losses (impairment reversals), net - net gains on disposal of assets - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - other Adjusted operating profit (loss) - Refining & Marketing - Chemicals Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) (a) Excluding special items. (€ million) 2018 (380) 234 526 193 193 (9) 21 8 23 1 96 380 390 (10) 11 (2) (151) 38.8 238 2017 981 (213) 223 136 54 (13) (6) (11) (9) 72 991 531 460 5 19 (352) 34.7 663 2016 723 (406) 266 104 104 (8) 28 12 (3) 3 26 583 278 305 1 32 (197) 32.0 419 Change (1,361) % Ch. .. (611) (141) (470) 6 (21) 201 4.1 (425) (61.7) (26.6) .. (64.1) In 2018, the Refining & Marketing segment reported an adjusted operating profit of €390 million, down by 27% y-o-y driven by lower refining margins (down by 26%) due to higher petroleum feedstock cost not recovered in product prices and higher impact from plant standstills. The oxygenated business was penalized by downtime at certain assets due to prolonged maintenance activities. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 72 These negative trends were offset by plant and supply optimizations, as well as by higher margins on green throughputs. Marketing activities reported an improved performance both in the retail and wholesale segments also leveraging on effective commercial initiatives to support margins and on efficiency actions. The Chemical business was affected by the worsening trading environment characterized by sharply higher supply cost of oil-based feedstock in the first ten months that were not recovered in sale prices, by competitive pressure and by a demand slowdown in the last part of the year, mainly in the polyethylene segment, which resulted in a strong contraction of the benchmark margin of cracker (down by 11%) and polyethylene margins (down by 69%), as well as, by the fact that the first half of 2017 benefitted from particularly high prices of intermediates (butadiene and benzene) due to contingent factors. In this scenario, the Chemical business reported breakeven result and absorbed market fluctuations leveraging on plant optimization and a shift in its product portfolio towards specialties, which are less exposed to the scenario volatility. A large-scale change in scenario affected the petrochemical industry compared to the full year 2017. Adjusted operating profit of the R&M and Chemicals segment excluded special items of €526 million and an inventory holding loss of €234 million. Adjusted net profit was €238 million decreased by €425 million due to lower operating performance. Corporate and other activities Operating profit (loss) Exclusion of special items: - environmental charges - impairment losses (impairment reversals), net - net gains on disposal of assets - risk provisions - provision for redundancy incentives - other Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Adjusted net profit (loss) (a) Excluding special items. (€ million) 2018 (691) 85 23 18 (1) (1) (1) 47 (606) (697) 5 333 (965) 2017 (668) 126 26 25 (1) 82 (2) (4) (542) (699) 22 178 (1,041) 2016 (681) 229 88 40 1 7 93 (452) (721) (6) 188 (991) Change (23) % Ch. (3.4) (64) 2 (17) 155 76 (11.8) 0.3 (77.3) 87.1 7.3 The Corporate and other activities segment mainly includes results of operations of Eni’s headquarters principally on an intercompany basis. Eni’s headquarters and certain Eni subsidiaries performs human resources management, finance, administration, information technology, legal affairs and other general and business support services. In addition, this business segment comprises operating expenses of reclamation and decommissioning activities pertaining to certain businesses, which Eni exited, divested or shut down in past years, net of the captive subsidiaries margins related to specialist business services (insurance, financial and recruitment activities). FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 73 SUMMARIZED GROUP BALANCE SHEET The summarized Group balance sheet aggregates the amount of assets and liabilities derived from the statutory balance sheet in accordance with functional criteria which considers the enterprise conventionally divided into the three fundamental areas focusing on resource investments, operations and financing. Management believes that this summarized group balance sheet is useful information in assisting investors to assess Eni’s capital structure and to analyse its sources of funds and investments in fixed assets and working capital. Management uses the summarized group balance sheet to calculate key ratios such as the return on invested capital (adjusted ROACE) and the financial soundness/ equilibrium (gearing and leverage). Summarized Group Balance Sheet(a) Fixed assets Property, plant and equipment Inventories - Compulsory stock Intangible assets Equity-accounted investments and other investments Receivables and securities held for operating purposes Net payables related to capital expenditure Net working capital Inventories Trade receivables Trade payables Tax payables and provisions for net deferred tax liabilities Provisions Other current assets and liabilities Provisions for employee post-retirement benefits Assets held for sale including related liabilities CAPITAL EMPLOYED, NET Eni shareholders’ equity Non-controlling interest Shareholders’ equity Net borrowings TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY (€ million) December 31, 2018 December 31, 2017 60,302 1,217 3,170 7,963 1,314 (2,399) 71,567 4,651 9,520 (11,645) (1,104) (11,886) (860) (11,324) (1,117) 236 59,362 51,016 57 51,073 8,289 59,362 63,158 1,283 2,925 3,730 1,698 (1,379) 71,415 4,621 10,182 (10,890) (2,387) (13,447) 287 (11,634) (1,022) 236 58,995 48,030 49 48,079 10,916 58,995 Change (2,856) (66) 245 4,233 (384) (1,020) 152 30 (662) (755) 1,283 1,561 (1,147) 310 (95) 367 2,986 8 2,994 (2,627) 367 (a) For a reconciliation to the statutory statement of cash flow see the paragraph “Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes”. The Summarized Group Balance Sheet was affected by the movement in the EUR/USD exchange rate, which determined an increase in net capital employed, total equity and net borrowings by €2,107 million, €1,787 million, and €320 million respectively. This was due to translation into euros of the financial statements of US-denominated subsidiaries reflecting a 4.5% appreciation of the US dollar against the euro (1 EUR= 1.146 USD at December 31, 2018 compared to 1.200 at December 31, 2017). Fixed assets (€71,567 million) increased by €152 million from December 31, 2017. The item “Property, plant and equipment” was down by €2,856 million mainly due to the derecognition of Eni Norge’s assets following loss of control over the subsidiary as a result of the business combination with Point Resources which had an offsetting impact in the line-item “Equity-accounted investments and other investments” mainly due to the recognition of Vår Energi interest; while DD&A and impairment losses (€7,854 million) and the disposals were substantially offset by capital expenditure for the year (€9,119 million). The increase in the item “Equity-accounted investments and other investments” of €4,233 million was due to the above mentioned Vår Energi operation, the new accounting of equity instruments required by IFRS 9 and the net equity investments. Net payables related to capital expenditure increased by €1,020 billion due to the cash-in of the receivables arising from the disposal of the Zohr interests made in 2017. Net working capital was in negative territory at minus €11,324 million and increased by €310 million y-o-y driven by the decrease in risk provisions due to the change of the estimate revision to the decommissioning provision following higher discount rates and to tax payables and provision for deferred taxes due to the derecognition of Eni Norge, offset by a reduction in trade receivables and an increase in trade payables. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 74 COMPREHENSIVE INCOME Net profit (loss) Items that are not reclassified to profit or loss in later periods Remeasurements of defined benefit plans Change in the fair value of minor investments with effects to other comprehensive income Taxation Items that may be reclassified to profit or loss in later periods Currency translation differences Change in the fair value of available-for-sale financial instruments Change in the fair value of cash flow hedging derivatives Share of “Other comprehensive income” on equity-accounted entities Taxation Total other items of comprehensive income (loss) Total comprehensive income (loss) attributable to: - Eni’s shareholders - Non-controlling interest CHANGES IN SHAREHOLDERS' EQUITY (€ million) Shareholders’ equity at January 1, 2017 Total comprehensive income (loss) Dividends distributed to Eni’s shareholders Dividends distributed by consolidated subsidiaries Other changes Total changes Shareholders’ equity at December 31, 2017 attributable to: - Eni’s shareholders - Non-controlling interest Shareholders’ equity at December 31, 2017 Impact of adoption IFRS 9 and IFRS 15 Shareholders’ equity at January 1, 2018 Total comprehensive income (loss) Dividends distributed to Eni’s shareholders Dividends distributed by consolidated subsidiaries Other changes Total changes Shareholders’ equity at December 31, 2018 attributable to: - Eni’s shareholders - Non-controlling interest (€ million) 2018 4,137 (2) (15) 15 (2) 1,578 1,787 (243) (24) 58 1,576 5,713 2017 3,377 (4) (33) 29 (5,514) (5,573) (5) (6) 69 1 (5,518) (2,141) 5,702 11 (2,144) 3 (2,141) (2,881) (3) 18 5,713 (2,953) (3) (8) 53,086 (5,007) 48,079 48,030 49 48,079 245 48,324 2,749 51,073 51,016 57 Shareholders’ equity including non-controlling interest was €51,073 million, up by €2,994 million. This was due to net profit for the period and positive foreign currency translation differences (€1,787 million) reflecting the appreciation of dollar compared to the euro (up by 4.5%; EUR/USD exchange rate of 1.146 at December 31, 2018 compared to 1.200 at December 31, 2017), partly offset by a negative change in the fair value of the cash flow hedge reserve (€243 million) and the distribution of dividend (€2,953 million): 2017 balance dividend of €1,440 million and 2018 interim dividend for €1,513 million. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 75 LEVERAGE AND NET BORROWINGS Leverage is a measure used by management to assess the Company’s level of indebtedness. It is calculated as a ratio of net borrowings which is calculated by excluding cash and cash equivalents and certain very liquid assets from financial debt to shareholders’ equity, including non-controlling interest. Gearing measures how much of capital employed net is financed recurring to third-party funding and is calculated as the ratio between net borrowings and capital employed net. Management monitors leverage in order to assess the soundness and efficiency of the Group balance sheet in terms of optimal mix between net borrowings and net equity, and to carry out benchmark analysis with industry standards. (€ million) Total debt: Short-term debt Long-term debt Cash and cash equivalents Securities held for trading and other securities held for non-operating purposes Financing receivables for non-operating purposes Net borrowings Shareholders’ equity including non-controlling interest Leverage Gearing December 31, 2018 December 31, 2017 24,707 4,528 20,179 (7,363) (6,219) (209) 10,916 48,079 0.23 0.18 25,865 5,783 20,082 (10,836) (6,552) (188) 8,289 51,073 0.16 0.14 Change 1,158 1,255 (97) (3,473) (333) 21 (2,627) 2,994 0.07 (0.05) Net borrowings at December 31, 2018 was €8,289 million, lower by €2,627 million from 2017. Total debt of €25,865 million consisted of €5,783 million of short-term debt (including the portion of long-term debt due within twelve months of €3,601 million) and €20,082 million of long-term debt. This reduction was driven by net cash flow from operations and the finalization of portfolio transactions as part of the Dual Exploration Model and other minor assets. As of December 31, 2018, the ratio of net borrowings to shareholders’ equity including non controlling interest – leverage – was 0.16, reporting a decrease from 0.23 as of the end of 2017. This decline was driven by lower net borrowing and by the increase in the Group total equity of €2,994 million from December 31, 2017. This was due to the positive foreign currency translation differences (€1,787 million) and profit for the year, partly offset by dividend distribution to Eni’s shareholders (2017 balance dividend and 2018 interim dividend of €2,953 million). As of December 31, 2018, gearing – the ratio of net borrowings to net capital employed – was 0.14, lower than 0.18 at December 31, 2017. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 201876 SUMMARIZED GROUP CASH FLOW STATEMENT Eni’s Summarized Group Cash Flow Statement derives from the statutory statement of cash flows. It enables investors to understand the connection existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred in the reporting period. The measure which links the two statements is represented by the “free cash flow” which is calculated as difference between the cash flow generated from operations and the net cash used in investing activities. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/receivables (issuance/repayment of debt and receivables related to financing activities), shareholders’ equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; and (ii) change in net borrowings for the period by adding/deducting cash flows relating to shareholders’ equity and the effect of changes in consolidation and of exchange rate differences. Summarized Group Cash Flow Statement(a) Net profit (loss) Adjustments to reconcile net profit (loss) to net cash provided by operating activities: - depreciation, depletion and amortization and other non monetary items - net gains on disposal of assets - dividends, interests, taxes and other changes Changes in working capital related to operations Dividends received, taxes paid, interests (paid) received during the period Net cash provided by operating activities Capital expenditure Investments and purchase of consolidated subsidiaries and businesses Disposals Other cash flow related to capital expenditure, investments and disposals Free cash flow Borrowings (repayment) of debt related to financing activities(b) Changes in short and long-term financial debt Dividends paid and changes in non-controlling interests and reserves Effect of changes in consolidation, exchange differences and cash NET CASH FLOW Change in net borrowings Free cash flow Net borrowings of acquired companies Net borrowings of divested companies Exchange differences on net borrowings and other changes Dividends paid and changes in non-controlling interest and reserves CHANGE IN NET BORROWINGS (€ million) 2018 4,137 2017 3,377 2016 (1,044) Change 760 7,657 (474) 6,168 1,632 (5,473) 13,647 (9,119) (244) 1,242 942 6,468 (357) 320 (2,957) 18 3,492 2018 6,468 (18) (499) (367) (2,957) 2,627 8,720 (3,446) 3,650 1,440 (3,624) 10,117 (8,681) (510) 5,455 (373) 6,008 341 (1,712) (2,883) (65) 1,689 7,773 (48) 2,229 2,112 (3,349) 7,673 (9,180) (1,164) 1,054 465 (1,152) 5,271 (766) (2,885) (3) 465 2017 6,008 2016 (1,152) 261 474 (2,883) 3,860 5,848 284 (2,885) 2,095 (1,063) 2,972 2,518 192 (1,849) 3,530 (438) 266 (4,213) 1,315 460 (698) 2,032 (74) 83 1,803 Change 460 (18) (760) (841) (74) (1,233) (€ million) (a) For a reconciliation to the statutory statement of cash flow see the paragraph “Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes”. (b) The item included investments and divestments (on net basis) in held-for-trading financial assets and other investments/divestments in certain short-term financial assets. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determing net borrowings. Cash flows of such investments were as follows: Financing investments: - securities - financing receivables Disposal of financing investments: - securities - financing receivables Borrowings (repayment) of debt related to financing activities 2018 2017 2016 Change (424) (196) (620) 46 217 263 (357) (316) (72) (388) (1,317) (272) (1,589) 223 506 729 341 6,860 6,860 5,271 (108) (124) (232) (177) (289) (466) (698) FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 77 Cash flow from operating activities amounted to €13,647 million for the full year of 2018 was up by 35% driven by an improved underlying performance and scenario effects. Cash flow from operating activities for the full year of 2018 was influenced by a lower level of receivables due beyond the end of the reporting period being sold to financing institutions, compared to 2017 (approximately €280 million). Adjusted net cash flow from operating activities before changes in working capital at replacement cost was €12,662 million, up by 37% y-o-y. This adjusted measure is derived by excluding certain non-recurring charges: an expense recognized in connection with the final outcome of an arbitration proceeding (€313 million), an extraordinary allowance for doubtful accounts in the E&P segment (€158 million) and an expense related to the sale of a 10% interest in the Zohr project due to the fact that they related to the asset disposals (see the following reconciliation table). Full Year 2018 (€ million) k c o t s n o s s o L / t fi o r P n a f o d r a w a l a n i F n o i t a r t i b r a s t n u o c c a l u f t b u o d y r a n i d r o a r t x E r o f e c n a w o l l a % 0 1 n o e u d e s n e p x E l a s o p s i d r h o Z d n u f o t n i - d e h s a c t c e j o r p r h o Z e h t s e c n a v d a e d a r T s e r u s a e m P A A G Net cash before changes in working capital 12,015 96 313 158 80 12,662 Changes in working capital 1,632 (96) (313) (158) (280) 785 Net cash provided by operating activities 13,647 80 (280) 13,447 S E R U S A E M P A A G - N O N Adjusted net cash before changes in working capital Underlying net cash provided by operating activities Capital expenditure for the year, including investments, was €9,363 million. Net capex amounted to approximately €7.94 billion and excluded the following items: entry bonus paid mainly in connection with the two new producing Concession Agreements in the United Arab Emirates (€869 million); non- strategic acquisitions in the gas mid-downstream business (approximately €100 million); the capex pertaining to a 10% divested interest in the Zohr project (€170 million) incurred from January 1, 2018 to the closing of the transaction (end of June 2018), which were reimbursed to Eni by the buyer. Additionally, as part of the financing agreements with the Egyptian partners relating to the Zohr project, the Company cashed in €280 million as an advance on future gas supplies to Egyptian state-owned companies. In 2018, the self-financing ratio of net capex was 172%. Cash flow from disposals (€1,242 million) related to the sale of the above mentioned 10% interest in the Zohr project, the divestment of certain other non-strategic assets in the E&P segment and the gas distribution activity in Hungary. Proceeds from disposals were netted by Eni Norge’s cash deposited at third-party banks (approximately €250 million), which was divested as part of the business combination with Point Resources which determined the loss of Eni’s control on its former subsidiary. Other cash flow relating to capital expenditure, investments and disposals (€942 million) included the collection of the deferred tranches of the consideration on the sale of 10% and 30% interests in the Zohr project finalized in 2017 (€450 million) and increased payables relating to capital expenditure. In order to calculate cash neutrality, management have reclassified tha main cash flow metrics. Excluding from the cash flow, the trade advances cashed-in to fund the Zohr project and the expense due on 10% of Zohr disposal, at a Brent price of 71 $/barrel in 2018, adjusted cash flow from operations amounted to approximately €13.45 billion and positive changes in receivables and payables associated with investing activities (mainly including the cash-in of the deferred price of the Zohr disposals made in 2017) amounted to €0.9 billion. Those inflows funded capex of €7.94 billion and the dividend of €2.95 billion, leaving a surplus of around €3.5 billion. Consequently, on the basis of the Group’s cash flow sensitivity to the Brent scenario which assumes a change of approximately €0.19 billion in cash flow for each one-US dollar change in the Brent price (and vice versa), the cash neutrality for funding FY capex and the floor dividend would have been achieved at 52 $/barrel. This is re-determined in 55 $/barrel when excluding from cash inflows the deferred tranches of the consideration on the disposal of Eni’s interests in Zohr made in 2017 (€450 million), being these the unique non-organic components of the cash flow. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 78 Capital expenditure Exploration & Production - acquisition of proved and unproved properties - exploration - development - other expenditure Gas & Power Refining & Marketing and Chemicals - Refining & Marketing - Chemicals Corporate and other activities Impact of unrealized intragroup profit elimination Capital expenditure (€ million) 2018 7,901 869 463 6,506 63 215 877 726 151 143 (17) 9,119 2017 7,739 5 442 7,236 56 142 729 526 203 87 (16) 8,681 2016 8,254 2 417 7,770 65 120 664 421 243 55 87 9,180 Change 162 864 21 (730) 7 73 148 200 (52) 56 % Ch. 2.1 .. 4.8 (10.1) 12.5 51.4 20.3 38.0 (25.6) 64.4 438 5.0 In the full year of 2018, capital expenditure amounted to €9,119 million (€8,681 million in the FY 2017) and mainly related to: - development activities (€6,506 million) deployed mainly in Egypt, Ghana, Norway, Libya, Italy, Nigeria, Congo and Iraq. The acquisition of proved and unproved reserves of €869 million relates to the entry bonus in two producing Concession Agreements and the offshore concession of Ghasha in the United Arab Emirates; - refining activity in Italy and outside Italy (€587 million) mainly aimed at reconstruction works of the EST conversion plant at the Sannazzaro refinery, reconversion of Gela refinery into a biorefinery, maintain plants’ integrity as well as initiatives in the field of health, security and environment; marketing activity, mainly regulation compliance and stay in business initiatives in the retail network of refining product in Italy and in the rest of Europe (€139 million); initiatives relating to gas marketing (€161 million) and power business (€46 million). - FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 79 Alternative performance measures (Non-GAAP measure) Management evaluates underlying business performance on the basis of Non-GAAP financial measures, not determined in accordance with IFRS (“Alternative performance measures”), such as adjusted operating profit and adjusted net profit, which are arrived at by excluding from reported operating profit and net profit certain gains and losses, defined special items, which include, among others, asset impairments, gains on disposals, risk provisions, restructuring charges and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income (see below). In determining adjusted results, also inventory holding gains or losses are excluded from base business performance, which is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS, except in those business segments where inventories are utilized as a lever to optimize margins. Management is disclosing Non-GAAP measures of performance to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models. Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures. Follows the description of the main alternative performance measures adopted by Eni. The measures reported below refer to the performance of the reporting periods disclosed in this Annual Report. Adjusted operating and net profit Adjusted operating and net profit are determined by excluding inventory holding gains or losses, special items and, in determining the business segments’ adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates which impact industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments’ adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production segment). Inventory holding gain or loss This is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS. Special items These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write-ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones; or (iii) exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency. Those items are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally occurring opposite positions and then dealing with any residual risk exposure in the exchange rate market. As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (CONSOB), non-recurring material income or charges are to be clearly reported in the management’s discussion and financial tables. Also, special items allow to allocate to future reporting periods gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives and exchange rate derivatives relating to commercial exposures, lacking the criteria to be designed as hedges, including the ineffective portion of cash flow hedges and certain derivative financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production segment. Leverage Leverage is a Non-GAAP measure of the Company’s financial condition, calculated as the ratio between net borrowings and shareholders’ equity, including non-controlling interest. Leverage is the reference ratio to assess the solidity and efficiency of the Group balance sheet in terms of incidence of funding sources including third-party funding and equity as well as to carry out benchmark analysis with industry standards. Gearing Gearing is calculated as the ratio between net borrowings and net capital employed and measures how much of net capital employed is financed recurring to third-party funding. Net cash provided by operating activities before changes in working capital at replacement cost Net cash provided from operating activities before changes in working capital and excluding inventory holding gain or loss. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 201880 Free cash flow Free cash flow represents the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. Free cash flow is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/ receivables (issuance/repayment of debt and receivables related to financing activities), shareholders’ equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; (ii) changes in net borrowings for the period by adding/deducting cash flows relating to shareholders’ equity and the effect of changes in consolidation and of exchange rate differences. Net borrowings Net borrowings is calculated as total finance debt less cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Financial activities are qualified as “not related to operations” when these are not strictly related to the business operations. Debt coverage Rating companies use the debt coverage ratio to evaluate debt sustainability. It is calculated as the ratio between net cash provided by operating activities and net borrowings, less cash and cash-equivalents, securities held for non-operating purposes and financing receivables for non-operating purposes. Net Debt/EBITDA adjusted Net Debt/EBITDA adjusted is the ratio between the profit available to cover the debt before interest, taxes, amortizations and impairment. This index is a measure of the company’s ability to pay off its debt and gives an indication as to how long a company would need to operate at its current level to pay off all its debt. Profit per boe Measures the return per oil and natural gas barrel produced. It is calculated as the ratio between Results of operations from E&P activities (as defined by FASB Extractive Activities - Oil and Gas Topic 932) and production sold. Opex per boe Measures efficiency in the oil and gas development activities, calculated as the ratio between operating costs (as defined by FASB Extractive Activities - oil&gas Topic 932) and production sold. ROACE (Return On Average Capital Employed) adjusted Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed. Coverage Financial discipline ratio, calculated as the ratio between operating profit and net finance charges. Finding & Development cost per boe Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities - Oil and Gas Topic 932). Current ratio Measures the capability of the company to repay short-term debt, calculated as the ratio between current assets and current liabilities. The following tables report the group operating profit and Group adjusted net profit and their breakdown by segment, as well as is represented the reconciliation with net profit attributable to Eni’s shareholders of continuing operations. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWn o i t c u d o r P & n o i t a r o l p x E r e w o P & s a G 10,214 629 (€ million) 110 726 (442) 360 26 (6) (138) 636 10,850 (366) 285 (5,814) 54.0 4,955 (1) (71) 122 (156) 112 (92) (86) 543 (4) 9 (238) 43.4 310 d n a g n i t e k r a M & s l a c i m e h C g n i n fi e R (380) 234 193 193 (9) 21 8 23 1 96 526 380 11 (2) (151) 38.8 238 s e i t i v i t c a r e h t o d n a e t a r o p r o C (691) 23 18 (1) (1) (1) 47 85 (606) (697) 5 333 (965) d e z i l a e r n u f o t c a p m I t fi o r p p u o r g a r t n i n o i t a n m i i l e 211 (138) 73 (17) 56 2018 Reported operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items: - environmental charges - impairment losses (impairments reversal), net - net gains on disposal of assets - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - other Special items of operating profit (loss) Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) of which attributable to: - non-controlling interest - Eni’s shareholders Reported net profit (loss) attributable to Eni’s shareholders Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted net profit (loss) attributable to Eni’s shareholders (a) Excluding special items. 81 P U O R G 9,983 96 325 866 (452) 380 155 (133) 107 (87) 1,161 11,240 (1,056) 297 (5,887) 56.2 4,594 11 4,583 4,126 69 388 4,583 FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 82 (€ million) s e i t i v i t c a r e h t o d n a e t a r o p r o C (668) 26 25 (1) 82 (2) (4) 126 (542) (699) 22 178 d e z i l a e r n u f o t c a p m I t fi o r p p u o r g a r t n i n o i t a n m i i l e (27) (6) (33) 17 (1,041) (16) d n a g n i t e k r a M & s l a c i m e h C g n i n fi e R 981 (213) 136 54 (13) (6) (11) (9) 72 223 991 5 19 (352) 34.7 663 r e w o P & s a G 75 (146) 38 157 (171) 261 139 214 10 (9) (163) 75.8 52 n o i t c u d o r P & n o i t a r o l p x E 7,651 46 (154) (3,269) 366 19 (68) 582 (2,478) 5,173 (50) 408 (2,807) 50.8 2,724 P U O R G 8,012 (219) 208 (221) (3,283) 448 49 146 (248) 911 (1,990) 5,803 (734) 440 (3,127) 56.8 2,382 3 2,379 3,374 (156) (839) 2,379 2017 Reported operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items: - environmental charges - impairment losses (impairments reversal), net - net gains on disposal of assets - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - other Special items of operating profit (loss) Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) of which attributable to: - non-controlling interest - Eni’s shareholders Reported net profit (loss) attributable to Eni’s shareholders Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted net profit (loss) attributable to Eni’s shareholders (a) Excluding special items. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 83 n o i t c u d o r P & n o i t a r o l p x E 2,567 (684) 7 (2) 105 24 19 (3) 461 (73) 2,494 (55) 68 (1,999) 79.7 508 d n a g n i t e k r a M & s l a c i m e h C g n i n fi e R 723 (406) 104 104 (8) 28 12 (3) 3 26 266 583 1 32 (197) 32.0 419 r e w o P & s a G (391) 90 1 81 17 4 (443) (19) 270 (89) (390) 6 (20) 74 18.3 (330) r e h t o d n a e t a r o p r o C s e i t i v i t c a (681) 88 40 1 7 93 229 (452) (721) (6) 188 d e z i l a e r n u f o t c a p m I t fi o r p p u o r g a r t n i n o i t a n m i i l e (61) 141 80 (19) (991) 61 D E U N I T N O C S I D S N O I T A R E P O 413 (413) I G N U N I T N O C S N O I T A R E P O 2,157 (175) 193 (459) 7 (10) 151 47 (427) (19) 850 333 2,315 (769) 74 (1,953) 120.6 (333) 7 (340) (1,051) (120) 831 (340) P U O R G 2,157 (175) 193 (459) 7 (10) 151 47 (427) (19) 850 333 2,315 (769) 74 (1,953) 120.6 (333) 7 (340) (1,464) (120) 1,244 (340) (€ million) 2016 Reported operating profit (loss) Exclusion of inventory holding (gains) losses Exclusion of special items: - environmental charges - impairment losses (impairments reversal), net - write off - net gains on disposal of assets - risk provisions - provision for redundancy incentives - commodity derivatives - exchange rate differences and derivatives - other Special items of operating profit (loss) Adjusted operating profit (loss) Net finance (expense) income(a) Net income (expense) from investments(a) Income taxes(a) Tax rate (%) Adjusted net profit (loss) of which attributable to: - non-controlling interest - Eni’s shareholders Reported net profit (loss) attributable to Eni’s shareholders Exclusion of inventory holding (gains) losses Exclusion of special items Adjusted net profit (loss) attributable to Eni’s shareholders (a) Excluding special items. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 84 Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes Summarized Group Cash Flow Statement Items of Summarized Group Balance Sheet (where not expressly indicated the item derives directly from the statutory scheme) December 31, 2018 December 31, 2017 Notes to the Consolidated Financial Statement Partial amounts from statutory scheme Amounts of the summarized Group scheme Partial amounts from statutory scheme Amounts of the summarized Group scheme (€ million) Fixed assets Property, plant and equipment Inventories - Compulsory stock Intangible assets Equity-accounted investments and other investments Receivables and securities held for operating activities Net payables related to capital expenditure, made up of: - receivables related to disposals - receivables related to capital expenditure/disposals non-current - payables related to capital expenditure Total fixed assets Net working capital Inventories Trade receivables Trade payables Tax payables and provisions for net deferred tax liabilities, made up of: - income tax payables - other tax payables - deferred tax liabilities - other non-current tax liabilities - current tax assets - other current tax assets - deferred tax assets - other non-current tax assets - payables/receivables for Italian consolidated accounts Provisions Other current assets and liabilities, made up of: - short-term financial receivables for operating purposes - receivables vs. partners for exploration and production activities and other - other current assets - other receivables and other assets non-current - advances, other payables, payables vs. partners for exploration and production activities and other - other current liabilities - other payables and other liabilities non-current Total net working capital Provisions for employee post-retirements benefits Assets held for sale including related liabilities made up of: - assets held for sale - liabilities related to assets held for sale CAPITAL EMPLOYED, NET Shareholders’ equity including non-controlling interest Net borrowings Total debt, made up of: - long-term debt - current portion of long-term debt - short-term financial liabilities less: Cash and cash equivalents Securities held for trading and other securities held for non-operating purposes Financing receivables for non-operating purposes Total net borrowings(a) TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY (see note 15) (see note 7) (see note 10) (see note 16) 122 9 (2,530) (see note 7) (see note 16) (see note 17) (see note 10) (see note 16) (see note 15) (see note 7) (see note 10) (440) (1,432) (4,272) (61) 191 561 3,931 422 (4) 51 4,459 2,258 361 (see note16) (2,568) (see note 17) (3,980) (1,441) 295 (59) 20,082 3,601 2,182 (see note 6) (see note 15) 60,302 1,217 3,170 7,963 1,314 (2,399) 71,567 4,651 9,520 (11,645) (1,104) (11,886) (860) (11,324) (1,117) 236 59,362 51,073 25,865 (10,836) (6,552) (188) 8,289 59,362 597 118 (2,094) (472) (1,472) (5,900) (45) 191 729 4,078 507 (3) 84 4,641 1,573 698 (3,760) (1,515) (1,434) 323 (87) 20,179 2,286 2,242 63,158 1,283 2,925 3,730 1,698 (1,379) 71,415 4,621 10,182 (10,890) (2,387) (13,447) 287 (11,634) (1,022) 236 58,995 48,079 24,707 (7,363) (6,219) (209) 10,916 58,995 (a) For details on net borrowings see also note 19 to the condensed consolidated interim financial statements. FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW85 Summarized Group Cash Flow Statement Items of Summarized Cash Flow Statement and confluence/reclassification of items in the statutory scheme 2018 2017 Partial amounts from statutory scheme Amounts of the summarized Group scheme Partial amounts from statutory scheme Amounts of the summarized Group scheme (€ million) Net profit (loss) Adjustments to reconcile net profit (loss) to cash provided by operating activities: Depreciation, depletion and amortization and other non monetary items - depreciation, depletion and amortization - impairment losses (impairment reversals), net - write-off of tangible and intangible assets - share of profit (loss) of equity-accounted investments - other changes - net change in the provisions for employee benefits Net gains on disposal of assets Dividends, interests, income taxes and other changes - dividend income - interest income - interest expense - income taxes Changes in working capital related to operations - inventories - trade receivables - trade payables - provisions for contingencies - other assets and liabilities 4,137 7,657 (474) 6,168 1,632 3,377 8,720 (3,446) 3,650 1,440 7,483 (225) 263 267 894 38 (205) (283) 671 3,467 (346) 657 284 96 749 6,988 866 100 68 (474) 109 (231) (185) 614 5,970 15 334 642 (238) 879 Dividends received, taxes paid, interest (paid) received during the period (5,473) (3,624) - dividends received - interest received - interest paid - income taxes paid, net of tax receivables received Net cash provided by operating activities Investing activities: - tangible assets - intangible assets Investments and purchase of consolidated subsidiaries and businesses - investments - consolidated subsidiaries and businesses net of cash and cash equivalent acquired Disposals - tangible assets - intangible assets - changes in consolidated subsidiaries and businesses net of cash and cash equivalent disposed of - income taxes paid on disposals - investments Other cash flow related to capital expenditure, investments and disposals - securities - financing receivables - change in payables in relation to investing activities and capitalized depreciation reclassification: purchase of securities and financing receivables held for non-operating purposes - disposal of securities - disposal of financing receivables - change in receivables in relation to disposals reclassification: disposal of securities and financing receivables held for non-operating purposes Free cash flow 10,117 (8,681) (510) 5,455 (373) 275 87 (609) (5,226) (8,778) (341) (125) (119) 1,089 5 (47) 195 (432) (554) 408 620 61 496 606 (263) 13,647 (9,119) (244) 1,242 942 291 104 (582) (3,437) (8,490) (191) (510) 2,745 2 2,662 (436) 482 (316) (657) 152 388 224 999 (434) (729) 6,468 6,008 FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 201886 continued Summarized Group Cash Flow Statement Items of Summarized Cash Flow Statement and confluence/reclassification of items in the statutory scheme 2018 2017 Partial amounts from statutory scheme Amounts of the summarized Group scheme Partial amounts from statutory scheme Amounts of the summarized Group scheme (€ million) Free cash flow Borrowings (repayment) of debt related to financing activities reclassification: purchase of securities and financing receivables held for non-operating purposes reclassification: disposal of securities and financing receivables held for non-operating purposes Changes in short and long-term finance debt - increase in long-term finance debt - repayments of long-term finance debt - increase (decrease) in short-term finance debt Dividends paid and changes in non-controlling interest and reserves - dividends paid by Eni to shareholders - dividends paid to non-controlling interest Effect of exchange rate changes and other changes on cash and cash equivalents Effect of change in consolidation (inclusion/exclusion of significant/ insignificant subsidiaries) Net cash flow (620) 263 3,790 (2,757) (713) (2,954) (3) 18 6,468 (357) 320 (2,957) 18 3,492 (388) 729 1.842 (2,973) (581) (2,880) (3) (72) 7 6,008 341 (1,712) (2,883) (65) 1,689 FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 87 RISK FACTORS AND UNCERTAINTIES 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, cash flow and rates of growth are affected by volatile prices of crude oil, natural gas, oil products and chemicals Prices of oil and natural gas have a history of volatility due to many factors that are beyond Eni’s control. These factors include among other things: - global and regional dynamics of oil and gas supply and demand and global level of inventories. In 2018, the oil market environment was a volatile one. Until October 2018, crude oil prices continued the upward trend commenced in the second half of 2017 driven by economic growth, effectiveness of the production cuts implemented by OPEC Countries and other producers agreed at the end of November 2016 and normalizing inventory level. Geopolitical risks also played a role including production disruption in Venezuela, renewed internal tensions in Libya and worsening relations between USA and Iran. Oil prices peaked in October 2018, touching a four-year high around 85 $/bbl for the Brent crude oil benchmark. Then in November 2018, a sharp downturn, one of the steepest on record, followed driving crude oil prices as low as 60 $/bbl, a correction of about 30%. This downturn was driven by emerging trends pointing to an economic slowdown, uncertainties relating to the developments of the USA-China trade dispute and of the Brexit, and building oversupplies due to rising production levels in USA, OPEC and Russia also in anticipation of the enactment of US sanctions against Iran, which would happen to be less severe than expected. In December 2018, OPEC and Russia agreed to cut again production quotas by 1.2 million bbl/d, effective from January 2019, in an effort to curb a supply glut. In spite of this development, crude oil prices continued to slide throughout December 2018 to the year’s lows of 50 $/bbl, extending the correction from the highs to 40%. On average, in 2018 the price for the Brent crude oil benchmark increased by 31% y-o-y at about 71 $/bbl. In early 2019, oil prices regained the sixty-dollar mark thanks to better-than-expected gauges of economic activity and implementation of the production cuts. In the first quarter of 2019, the Brent crude oil price averaged approximately 63 $/bbl pointing to renewed strength; - global political developments, including sanctions imposed on certain producing Countries and conflict situations; - global economic and financial market conditions; - the ability of the OPEC cartel to control world supply and therefore oil prices; - prices and availability of alternative sources of energy (e.g., nuclear, coal and renewables); - weather conditions; - operational issues; - governmental regulations and actions; - success in the development and deployment of new technologies for the recovery of crude oil and natural gas reserves and technological advances affecting energy consumption; - competition from alternative energy sources like solar energy, photovoltaic and other renewables; - rising commitment of the world nations and the civil society to addressing the issue of global warming and climate change by reducing the release in the atmosphere of greenhouse gases (“GHG”) produced by the consumption of hydrocarbons in human activities. All these factors can affect the global balance between demand and supply for hydrocarbons and hence prices of crude oil, natural gas, and other energy commodities. Management expects global oil demand to grow by approximately 1.4 mmbbl/d in 2019, more or less in line with 2018, and global oil demand and supplies to be balanced overall. Considering the risks of an economic slowdown, geopolitical factors, uncertainties associated with possible developments in the USA-China trade dispute and with the Brexit, management is assuming a Brent price of 62 $/bbl in 2019, gradually increasing over the following three year period to reach 70$/bbl in 2022. After 2022, management is assuming a price growing in line with inflation (e.g. 71.4 $/bbl in 2023 assuming a long-term inflationary rate of 2%) based on its view of market fundamentals and oil price projections made by specialized agencies and financial analysts, substantially in line with the previous planning assumptions. Management’s oil price forecast was utilized to elaborate the Group financial projections and the level of Group’s capital expenditures for the 2019-2022 industrial plan and to estimate recoverability of the carrying amounts of the Group’s oil and gas assets as of December 31, 2018. Fluctuations in oil and natural gas prices materially affect the Group’s results of operations and business prospects. Lower prices from one year to another negatively affect the Group’s consolidated results of operations and cash flow. This is because lower prices translate into lower revenues recognized in the Company’s 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. Based on the current portfolio of oil and gas assets, Eni’s management estimates that the Company’s consolidated net cash provided by operating activities would vary by approximately €190 million for each one-dollar change in the price of the Brent crude oil benchmark with respect to the price case assumed in Eni’s financial projections for 2019 at 62 $/bbl. Furthermore, a structural decline in commodity prices may have material effects on Eni’s business outlook and may limit the Group’s funds available to finance expansion projects and certain contractual commitments. This because lower oil and gas prices over prolonged periods may adversely affect the 88 funds available to finance expansion projects, further reducing the Company’s ability to grow future production and revenues. In addition, in a weak scenario the Company may also need to review investment decisions and the viability of development projects and capex plans and as a result of this review the Company could reschedule, postpone or curtail development projects. In case of a structural decline in hydrocarbons prices, the Company may review the carrying amounts of oil and gas properties and this could result in recording material asset impairments. Finally, lower oil and gas prices could result in the de-booking of proved reserves, if they become uneconomic in this type of environment. These risks may adversely impact the Group’s results of operations, cash flow, liquidity, business prospects and shareholder returns, including dividends and the share prices. In response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions, lower commodity prices may also reduce the Group’s access to capital and lead to a downgrade or other negative rating action with respect to the Group’s credit rating by rating agencies, including Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investor Services Inc (“Moody’s”). These downgrades may negatively affect the Group’s cost of capital, increase the Group’s financial expenses, and may limit the Group’s ability to access capital markets and execute aspects of the Group’s business plans. Eni is estimating that approximately 50% of its current production is exposed to fluctuations in hydrocarbons prices. Exposure to this strategic risk is not subject to economic hedging, except for some specific market conditions or transactions. The remaining portion of Eni’s current production is largely unaffected by crude oil price movements considering that the Company’s property portfolio is characterized by a sizeable presence of production sharing contracts, whereby, due to the cost recovery mechanism, the Company is entitled to a larger number of barrels in the event of a fall in crude oil prices. (See the specific risks of the Exploration & Production segment in “Risks associated with the exploration and production of oil and natural gas” below). - The Group’s results from its Refining & Marketing and Chemicals businesses are primarily dependent upon the supply and demand for refined and chemical products and the associated margins on refined products and chemical products 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. Because of the above mentioned risks, a prolonged decline in commodity prices would materially and adversely affect the Group’s business prospects, financial condition, results of operations, cash flows, ability to finance planned capital expenditures and commitments and may impact shareholder returns, including dividends and the share price. Competition There is strong competition worldwide, both within the oil industry and with other industries, to supply energy and petroleum products to the industrial, commercial and residential energy markets Eni faces strong competition in each of its business segments. The current competitive environment in which Eni operates is characterized by volatile prices and margins of energy commodities, limited product differentiation and complex relationships with state-owned companies and national agencies of the Countries where hydrocarbons reserves are located to obtain mineral rights. As commodity prices are beyond the Company’s control, Eni’s ability to remain competitive and profitable in this environment requires continuous focus on technological innovation, the achievement of efficiencies in operating cost, efficient management of capital resources and the ability to provide valuable services to the energy buyers. It also depends on Eni’s ability to gain access to new investment opportunities, both in Europe and worldwide. - In the Exploration & Production segment, Eni faces competition from both international and state-owned oil companies for obtaining exploration and development rights, and developing and applying new technologies to maximize hydrocarbon recovery. Furthermore, Eni may face a competitive disadvantage because of its smaller size relative to other international oil companies, particularly when bidding for large scale or capital intensive projects, and it may be exposed to the risk of obtaining lower cost savings in a deflationary environment compared to its larger competitors given its potentially smaller market power with respect to suppliers. If, because of those competitive pressures, Eni fails to obtain new exploration and development acreage, to apply and develop new technologies, and to control costs, its growth prospects and future results of operations and cash flow in this business may be adversely affected. In the Gas & Power segment, Eni is facing strong competition in the European wholesale gas markets to sell gas to industrial customers, the thermoelectric sector and retailer companies from other gas wholesalers, upstream companies, traders and other players both in the Italian market and in markets across Europe. In recent years, competition has been fueled by muted demand growth, oversupplies and the development of very liquid European spot markets where large volumes of gas are traded daily. Players are competing mainly in terms of pricing and to a lesser extent on the ability to offer additional services to the buyers of the commodity, like volume flexibilities, different pricing options, the possibility to change the delivery point and other optionality. Management believes that competition in the European wholesale gas market will continue to negatively affect the results of operations and cash flow of Eni’s Gas & Power segment in future reporting periods. Eni’s Gas & Power segment also engages in the supply of gas and electricity to customers in the retail markets mainly in Italy, France and other areas in Europe. Customers include households, large residential accounts (hospitals, schools, public administration buildings, offices) and small and medium-sized businesses located in urban areas. The retail FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES market is characterized by strong competition among local selling companies which mainly compete in term of pricing and the ability to bundle valuable services with the supply of the energy commodity. In this segment competition has intensified in recent years due to the progressive liberalization of the market and the option on part of residential customers to switch smoothly from one supplier to another. Management believes that competition will represent a risk factor to the Company’s results of operations and cash flow in this business unit. - Eni is facing strong competitive pressure in its business of gas-fired electricity generation which is largely sold at wholesale markets in Italy. Margins on the sale of electricity have declined in recent years due to oversupplies, weak economic growth and inter-fuel competition. This latter was due to the fact that power produced from renewable sources and coal-fired power generation are cheaper than gas-fired electricity, although coal-fired plants are expected to be progressively phased-out due to environmental issues. Management believes that these negative factors will continue to negatively affect crack-spread margins on electricity at Italian wholesale markets and the profitability of this business unit in the foreseeable future. - In the Refining & Marketing segment, Eni faces strong - competition both in the wholesale markets and in the retail marketing activity. Margins of European refiners are facing structural headwinds due to muted trends in the European demand for fuels and continued competitive pressures from players in the Middle East, the USA and Asia, who can leverage on larger plant scale and cost economies, availability of cheaper feedstock, lower energy expenses and fewer environmental obligations. Eni believes that the competitive environment will remain challenging in the foreseeable future, also considering refining overcapacity in the European area and expectations of a new investment cycle driven by capacity expansion plans announced in Asia and the Middle East, potentially leading to a situation of global oversupplies of refinery products. In 2018 Eni’s gauge of profitability in the refining business fell by approximately 26% to 3.7 $/bbl driven by rising costs of oil-based feedstock that the Company was unable to transfer to final products prices pressured by the weak market fundamentals described above. This decline negatively affected the performance of the Company’s refining activity. Management believes that in the long-term the trading environment will not recover meaningfully with refining margins seen in a 4-5 $/bbl range. Furthermore, Eni’s refining margins are exposed to the volatility in the spreads between crudes with high sulfur content or sour crudes vs. the Brent crude benchmark, which is a low-content sulfur crude. Eni complex refineries are able to process sour crudes which typically trade at a discount over the Brent crude. However, in 2019 a shortfall in supplies of sour crudes is expected in the market due to the production cuts implemented by OPEC, lower exports from Venezuela and the USA sanctions against Iran. Those developments could result in an appreciation of the relative prices of sour crudes vs. the Brent, which would negatively affect the results of our refining business. Against this backdrop, management has designed an action plan 89 intended to reduce the Company’s breakeven margin in its refining business to about 3 $/bbl in 2019 by means of plant and feedstock optimization, energy savings and other cost efficiencies. Additionally, management expects to close by year-end the acquisition of a 20%-stake in a large refining asset in Abu Dhabi, which will de-risk Eni’s refining business due to the fact that the asset being acquired is more profitable than Eni’s legacy refineries due to larger scale, efficiency, geographic reach and proximity to raw materials sources. In case management fails to execute on this plan, the profitability of Eni’s refining business may be negatively affected considering management’s expectations for a weak trading environment. In marketing, Eni faces competition from other oil companies and newcomers such as low-scale operators and large retailers, who tend to adopt aggressive pricing policies. All these operators compete with each other primarily in terms of pricing and, to a lesser extent, service quality. In the Chemical business, Eni faces strong competition from well-established international players and state-owned petrochemical companies, particularly in the most commoditized market segments such as the production of basic petrochemical products (like ethylene and polyethylene), which demand is a function of macroeconomic growth. Many of those competitors based in the Far East and the Middle East are able to benefit from cost economies due to larger plant scale, wide geographic moat, availability of cheap feedstock and proximity to end-markets. Excess capacity across Europe has also fueled competition in this business. Furthermore, petrochemical producers based in the United States have regained market share, as their cost structure has become competitive due to the availability of cheap feedstock deriving from the production of domestic shale gas from which ethane is derived which is a cheaper raw material for the production of ethylene than the oil-based feedstock utilized by Eni’s petrochemicals subsidiaries. In 2018 the operating profit of our Chemicals business fell sharply due to increased expenses for oil- based feedstock, which the Company was not able to pass to final products prices pressured by competition. The Company does not expect any meaningful improvement in the trading environment in the short to the medium-term due to competitive headwinds described above. Management intends to execute an action plan designated to diversify the product portfolio away from the more commoditized products which are exposed to crude oil prices fluctuations and cyclical market dynamics and to focus on higher-value added products, particularly in the green chemicals business and in specialty niche markets, which we believe are less exposed to the economic cycle and to the volatility of crude oil prices. If the Company fails to reduce its exposure to commodity plastics and to gain critical mass in the green chemicals business and in the specialty markets, its future results of operations and cash flows may remain cyclical and exposed to any demand or cost downturn. 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, FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 201890 transport of natural gas, storage and distribution of petroleum products and the production of base chemicals, plastics and elastomers. By their nature, the Group’s operations expose Eni to a wide range of significant health, safety, security and environmental risks. Technical faults, malfunction of plants, equipment and facilities, control systems failure, human errors, acts of sabotage, loss of containment and adverse weather events can trigger damaging events such as explosions, fires, oil and gas spills from wells, pipeline and tankers, release of contaminants, toxic emissions and other negative events. The magnitude of these risks is influenced by the geographic range, operational diversity and technical complexity of Eni’s activities. Eni’s future results of 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, GHG emissions 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 its share price and dividends. Eni’s activities in the Refining & Marketing and Chemicals segment entail health, safety and environmental risks related to the handling, transformation and distribution of oil, oil products and certain petrochemical products. These risks can arise from the intrinsic characteristics and the overall life cycle of the products manufactured and the raw materials used in the manufacturing process, such as oil-based feedstock, catalysts, additives and monomer feedstock. These risks comprise flammability, toxicity, long-term environmental impact such as greenhouse gas emissions and risks of various forms of pollution and contamination of the soil and the groundwater, emissions and discharges resulting from their use and from recycling or disposing of materials and wastes at the end of their useful life. 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, shipping, river freight, rail, road and 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 has invested and will continue to invest significant resources in order to upgrade the methods and systems for safeguarding 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 unforeseen 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 other facilities, and managing its operations in a safe and reliable manner and in compliance with all applicable rules and regulations. These measures may not ultimately be completely successful in protecting against those risks. Failure to manage these risks could cause unforeseen 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 and to negatively affect results and cash flow and the Company’s business prospects. 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 the decommissioning of productive infrastructures and environmental sites remediation and clean-up. 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 retains worldwide third-party liability insurance coverage, which is designed to hedge part of the liabilities associated with damage to third parties, loss of value to the Group’s assets related to unfavorable events and in connection with environmental clean-up and remediation. Maximum compensation is $1.2 billion in case of offshore incident and $1.4 billion in case of incident at onshore facilities (refineries). Additionally, the Company may also activate further insurance coverage in case of specific capital projects and other industrial initiatives. Management believes that its insurance coverage is in line with industry practice and is 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 incident which occurred at the Macondo well in the Gulf of Mexico several years ago, 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. FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES91 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 a loss would not have a material adverse effect on the Company. The occurrence of the above mentioned events could have a material adverse impact on the Group’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects and shareholders’ returns and damage the Group’s reputation. Risks associated with the exploration and production of oil and natural gas The exploration and production of oil and natural gas require high levels of capital expenditures and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of oil and gas fields. The exploration and production activities are subject to the mining risk and the risks of cost overruns and delayed start-up at the projects to develop and produce hydrocarbons reserves. Those risks could have an adverse, significant impact on Eni’s future growth prospects, results of operations, cash flows, liquidity and shareholders’ returns. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production leases, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. A description of the main risks facing the Company’s business in the exploration and production of oil and gas is provided below. Eni’s oil and natural gas offshore operations are particularly exposed to health, safety, security and environmental risks Eni has material offshore operations relating to the exploration and production of hydrocarbons. In 2018, approximately 56% of Eni’s total oil and gas production for the year derived from offshore fields, mainly in, Libya, Norway, Angola, Egypt, the Gulf of Mexico, Italy, Congo, Indonesia, Venezuela, the United Arab Emirates, the United Kingdom and Nigeria. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. Offshore accidents and spills could cause damage of catastrophic proportions to the ecosystem and health and security of people due to objective difficulties in handling hydrocarbons containment, pollution, poisoning of water and organisms, length and complexity of cleaning operations and other factors. Furthermore, 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 or 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 future growth prospects, results of operations, cash flows, liquidity, reputation and shareholders’ returns. Exploratory drilling efforts may be unsuccessful Exploration drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling and completing wells have margins of uncertainty, and drilling operations may be unsuccessful because of a large variety of factors, including geological failure, unexpected drilling conditions, pressure or heterogeneities in formations, equipment failures, well control (blowouts) and other forms of accidents. A large part of the Company exploratory drilling operations is located offshore, including in deep and ultra-deep waters, in remote areas and in environmentally sensitive locations (such as the Barents Sea, the Gulf of Mexico and the Caspian Sea). In these locations, the Company generally experiences higher operational risks and more challenging conditions and incurs higher exploration costs than onshore. Furthermore, deep and ultra-deep water operations require significant time before commercial production of discovered reserves can commence, increasing both the financial risks associated with these activities. Because Eni plans to make significant investments in executing exploration projects, it is likely that the Company will incur significant amounts of dry hole expenses in future years. 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, and could have an adverse impact on Eni’s future growth prospects, results of operations, cash flows and liquidity. Development projects bear significant operational risks which may adversely affect actual returns Eni is executing or is planning to execute several development projects to produce and market hydrocarbon reserves. Certain projects target the development of reserves in high-risk areas, particularly deep offshore and in remote and hostile environments or in environmentally-sensitive locations. Eni’s future results of operations and business prospects depend heavily on its ability to implement, develop and operate major projects as planned. Key factors that may affect the economics of these projects include: - the outcome of negotiations with joint venture partners, governments and state-owned companies, suppliers, customers or others to define project terms and conditions, including, for example, Eni’s ability to negotiate favorable long-term contracts to market gas reserves; - commercial arrangements for pipelines and related equipment to transport and market hydrocarbons; - timely issuance of permits and licenses by government agencies; - the ability to make the front-end engineering design in order to prevent the occurrence of technical inconvenience during the execution phase; timely manufacturing and delivery of critical equipment by contractors, shortages in the availability of such equipment or lack of shipping yards where FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 201892 complex offshore units such as FPSO and platforms are built; these events may cause cost overruns and delays impacting the time-to-market of the reserves; - risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs; - performance in project execution on the part of contractors who are awarded project construction activities generally based on the EPC (Engineering, Procurement and Construction) contractual scheme; - changes in operating conditions and cost overruns; - the actual performance of the reservoir and natural field decline; and - the ability and time necessary to build suitable transport infrastructures to export production to final markets. As previously described, events such as poor project execution, inadequate front-end engineering design, delays in the achievement of critical phases 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. Lastly, the development and marketing of hydrocarbon 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 the technical and economic feasibility of the development project, project final investment decision and building and commissioning the related plants and facilities. As a consequence, rates of return for such long lead time projects are exposed to the volatility of oil and gas prices and costs which may be substantially different from those estimated when the investment decision was made, thereby leading to lower return rates. Moreover, projects executed with partners and joint venture partners 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 operational control of the joint ventures in which it participates and may have exposure to counterparty credit risk and disruption of operations and strategic objectives due to the nature of its relationships. Finally, if 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 capitalised costs associated with reduced future cash flows of those projects. Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition 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 production sharing agreements (“PSAs”), whereby the Company 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 expenditure, and vice versa. Based on the current portfolio of oil and gas assets, Eni’s management estimates that production entitlements vary on average by approximately 600 bbl/d for each $1 change in oil prices based on current Eni’s assumptions for oil prices. This led to negative reserves revisions of 38 mmBOE in 2018, due to the oil price increase previously described. In case oil prices differ significantly from Eni’s own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different. Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiations with national oil companies and other entities owners of known reserves and acquisitions. An inability to replace produced reserves by discovering, 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 The accuracy of proved reserve estimates and of projections of future rates of production and timing of development expenditures depends on a number of factors, assumptions and variables, including: - the quality of available geological, technical and economic data and their interpretation and judgement; - projections regarding future rates of production and costs and timing of development expenditures; - changes in the prevailing tax rules, other government regulations and contractual conditions; - results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and - changes in oil and natural gas prices which could affect the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions. Reserve estimates are subject to revisions as prices fluctuate due to the cost recovery mechanism under the Company’s FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 93 production sharing agreements and similar contractual schemes. Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves. The prices used in calculating Eni’s estimated proved reserves are, in accordance with the US Securities and Exchange Commission (the “US 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, 2018, average prices were based on 71.4 $/bbl for the Brent crude oil. Brent prices have declined significantly since they reached a peak at 85 $/bbl in October of 2018 and in the first quarter of 2019 have recovered only partially. If such prices do not increase significantly in the coming months, 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 could 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. Accordingly, the estimated reserves reported as of the end of 2018 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 business prospects, results of operations, cash flows and liquidity. The development of the Group’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates or the Group’s proved undeveloped reserves may not ultimately be developed or produced. At December 31, 2018, approximately 32% of the Group’s 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. The Group’s reserve estimates assume it can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. The Group’s reserve report at December 31, 2018 includes estimates of total future development and decomissioning costs associated with the Group’s proved total reserves of approximately €35.3 billion (undiscounted, including consolidated subsidiaries and equity-accounted entities). It cannot be certain that estimated costs of the development of these reserves will prove correct, development will occur as scheduled, or the results of such development will be as estimated. In case of change in the Company’s plans to develop those reserves, or if it is not otherwise able to successfully develop these reserves as a result of the Group’s inability to fund necessary capital expenditures or otherwise, it will be required to remove the associated volumes from the Group’s reported proved reserves. Oil and gas activity may be subject to increasingly high levels of income taxes and royalties Oil and gas operations are subject to the payment of royalties and income taxes, which tend to be higher than those payable in many other commercial activities. Furthermore, in recent years, Eni has experienced adverse changes in the tax regimes applicable to oil and gas operations in a number of Countries where the Company conducts its upstream operations. As a result of these trends, management estimates that the tax rate applicable to the Company’s oil and gas operations is materially higher than the Italian statutory tax rate for corporate profit, which currently stands at 24%. 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’s 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, governments are facing greater pressure on public finances, which may induce them to intervene in the fiscal framework for the oil and gas industry, including the risk of increased taxation, windfall taxes, and even nationalizations and expropriations. Eni’s results and cash flow depend on its ability to identify and mitigate the above mentioned risks and hazards which are inherent to its operations. 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 The present value of future net revenues from Eni’s proved reserves may differ from the current market value of Eni’s estimated crude oil and natural gas reserves. In accordance with US SEC rules, Eni bases the estimated discounted future net revenues from proved reserves on the 12-month un- weighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the US SEC pricing used in the calculations. Actual future net revenues from crude oil and natural gas properties will be affected by factors such as: - the actual prices Eni receives for sales of crude oil and natural gas; - the actual cost and timing of development and production expenditures; - the timing and amount of actual production; and - changes in governmental regulations or taxation. FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 201894 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. Additionally, 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, 2018, the net present value of Eni’s proved reserves totaled approximately €57.6 billion. The average prices used to estimate Eni’s proved reserves and the net present value at December 31, 2018, as calculated in accordance with US SEC rules, were 71.4 $/bbl for the Brent crude oil. Actual 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 2019, Eni’s PV-10 at December 31, 2019 could decrease significantly. Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves 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, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. These risks can limit the Group access to hydrocarbons reserves or may have the Group to redesign, curtail or cease its oil and gas operation with significant effects on the Group business prospects, results of operations and cash flow. In Italy, a new law has been enacted effective February 12, 2019, which requires certain Italian administrative bodies to adopt within eighteen months a plan intended to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, it is established a moratorium on exploration activities, including the award of new exploration leases. Following the plan approval, exploration permits resume their efficacy in areas that have been identified as suitable; on the contrary in unsuitable areas, exploration permits are repealed. As far as development and production concessions are concerned, pending the national plan approval, ongoing concessions retain their efficacy and administrative procedures underway to grant extension to expired concession remain unaffected; instead no applications to obtain new concession can be filed. Once the above mentioned national plan is adopted, development and production concessions that fall in suitable areas can be granted further extensions and applications for new concessions can be filed; on the contrary development and production concessions current at the approval of the national plan that fall in unsuitable areas are repealed at their expiration and no further extensions can be granted, nor new concession applications can be filed. In case Italian administrative bodies fail to adopt the national plan for suitable areas within two years from the law enactment, the general moratorium on exploration activities is revoked and application for new concession permits can be filed. According to the statute, areas that are suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline. Our largest development project in Italy is operated under a concession that will expire in 2019; the application for renewal is underway and the renewal process is unaffected by the new law; assuming it is renewed as expected, this concession will expire in 2029, unless renewed at that time. Production at those sites is currently scheduled to continue until 2045. Management believes the criteria laid out in the law for identified unsuitable areas to be high-level principles, which make it difficult identifying in a reliable and objective manner areas that might be suitable or unsuitable to hydrocarbons activities before the plan adoption by Italian authorities. Therefore, management is not currently in the position to make a reliable and fair estimation of future impacts of the new law provisions on the recoverability of the volumes of proved reserves booked in Italy and the associated future cash flows. However, based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expects any material impacts on the Group future results of operations and cash flow. Political considerations The large majority of Eni’s oil and gas reserves are located in Countries outside Europe and North America, mainly in Africa, Central Asia and Central-Southern America, where the socio-political framework, the financial system and the macroeconomic outlook are less stable than in the OECD Countries. In those non-OECD Countries, Eni is exposed to a wide range of additional risks and uncertainties in addition to the material risks described above, which could materially impact the ability of the Company to conduct its oil and gas operations in a safe, reliable and profitable manner. As of December 31, 2018, approximately 82% of Eni’s proved hydrocarbon reserves were located in such Countries. Adverse political, social and economic developments, such as internal conflicts, revolutions, establishment of non-democratic regimes, protests, strikes and other forms of civil disorder, contraction of economic activity and financial difficulties of the local governments with repercussions on the solvency of state institutions, inflation levels, exchange rates and similar events FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 95 in those non-OECD Countries may impair Eni’s ability to continue operating in an economically viable way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. In particular, Eni faces risks in connection with the following, possible issues: - lack of well-established and reliable legal systems and uncertainties surrounding the enforcement of contractual rights; - unfavorable enforcement of laws, regulations and contractual arrangements leading, for example, to expropriation, nationalization or forced divestiture of assets and unilateral cancellation or modification of contractual terms. Eni is facing increasing competition from state-owned oil companies that are partnering Eni in a number of oil and gas projects and properties in the host Countries where Eni conducts its upstream operations. These state-owned oil companies can unilaterally change contractual terms and other conditions of oil and gas projects in order to obtain a larger share of profit from a given project, thereby reducing Eni’s profit share. They can also enforce different interpretations of contractual clauses relating to the recovery of certain expenses incurred by the Company to produce hydrocarbons reserves in any given project; - sovereign default or financial instability due to the fact that those Countries rely heavily on petroleum revenues to sustain public finance and petroleum revenues have dramatically contracted during the recent, three-year long oil downturn which ended by mid of 2017. Financial difficulties at country level often translate into failure on part of state-owned companies and agencies to fulfill their financial obligations towards Eni relating to funding capital commitments in projects operated by Eni or to timely paying supplies of equity oil and gas volumes; - restrictions on exploration, production, imports and exports; - tax or royalty increases (including retroactive claims); - political and social instability which could result in civil and social unrest, internal conflicts and other forms of protest and disorder such as strikes, riots, sabotage, acts of violence and similar events. These risks could result in disruptions to economic activity, loss of output, plant closures and shutdowns, project delays, the loss of assets and threat to the security of personnel. They may disrupt financial and commercial markets, including the supply of and pricing for oil and natural gas, and generate greater political and economic instability in some of the geographical areas in which Eni operates; - difficulties in finding qualified suppliers in critical operating environments; and - complex processes of granting authorizations or licences affecting time-to-market of certain development projects. Areas where Eni operates and where the Company is particularly exposed to political risk include, but are not limited to: Libya, Egypt, Algeria, Nigeria, Angola, Kazakhstan, Venezuela and Iraq. Additionally, any possible reprisals because of military or other action, such as acts of terrorism in Europe, 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 operations in Libya were materially affected by the revolution of 2011 and a change of regime, which caused a prolonged period of political and social instability, still ongoing. In 2011 Eni’s operations in the Country experienced an almost one-year long shutdown due to security issues amidst a civil war, causing a material impact on the Group results of operation and cash flow of the year. In subsequent years Eni has experienced frequent disruptions at its operations albeit of a smaller scale than in 2011 due to security threats to its installations and personnel. In the second half of 2018 a resurgence of socio-political instability coupled with internal clashes reduced the Country economic activity and gas demand which negatively affected the Company’s levels of production for the year. Management is closely monitoring the situation and is evaluating any possible measure to safeguard safety of Eni’s local personnel and security of plants and production infrastructures. Going forward, management believes that Libya’s geopolitical situation will continue to represent a source of risk and uncertainty to Eni’s operations in the Country. Currently, Libya represents approximately 16% of the Group’s total production; this proportion is forecasted to decrease in the medium term. In the event of major adverse events such as the resumption of internal conflict, acts of war, sabotage, social unrest, clashes and other forms of civil disorder, Eni could be forced to interrupt or reduce its producing activities at the Libyan plants, negatively affecting Eni’s results of operations, cash flow and business prospects. Venezuela is currently experiencing a situation of financial stress amidst an economic downturn due to lack of resources to support the development of the Country’s hydrocarbons reserves, which have negatively affected the Country production levels and hence petroleum revenues. The situation has been made worse by certain international sanctions targeting the Country’s financial system and its ability to export crude oil to the USA market, which is the main outlet of Venezuelan production, which are described below. Eni expects the financial and political outlook of Venezuela to negatively affect its ability to recover the investments made in the Country to develop two petroleum projects and the overdue trade receivables owned to us by the Venezuelan national oil company – PDVSA – and its affiliates for the gas supplies of the Cardón IV gas project, a 50% – held joint venture. In 2018, this venture was able to collect a certain percentage of the sales of the equity gas produced in the year to PDVSA. The venture is systematically accounting a loss provision on the uncollected revenues based on management’s appreciation of the counterparty risk which was estimated based on the findings of a review of the past experience of sovereign defaults. Furthermore, due to a worsening operating environment, management decided to de- book the proved undeveloped reserves (down 106 million bbl) at one of the Company’s projects in the Country, recognizing an impairment loss of around €200 million. Nigeria is also undergoing a situation of financial stress, which has translated into continuing delays in collecting overdue trade receivables and credits for the carry of the expenditures of the Nigerian joint operators at projects operated by Eni and the FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 201896 incurrence of credit losses. Further, Eni’s activities in Nigeria have been impacted in recent years by continuing incidences 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. Eni expects that those risks will continue to affect Eni’s operations in Nigeria and other Countries. It is possible that the Group may incur further asset impairments or credit losses in future reporting periods depending on the evolution of the financial outlook of the Countries where the Group is conducting its Oil & Gas operations. In Egypt, Eni plans to invest significantly in the next four-year plan to sustain the production plateau at the Zohr offshore gas field and to develop existing gas reserves at other projects. Since our gas production is entirely sold to local state-owned oil companies, we expect a significant increase in the credit risk exposure in Egypt, where we experienced some issues at collecting overdue trade receivables during the downturn. Eni will continue monitoring the counterparty risk in future years considering the significant volumes of gas expected to be supplied to Egypt’s national oil companies. Eni closely monitors political, social and economic risks of the Countries in which it 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, the occurrence of any such events could adversely affect Eni’s results from operations, cash flow and business prospects, also including the counterparty risk arising from the financing exposure of Eni in case state-owned entities, which are party to Eni’s upstream projects for developing hydrocarbons, fail to reimburse due amounts. Sanction targets In response to the Russia-Ukraine crisis, the European Union and the United States have enacted sanctions targeting, inter alia, the financial and energy sectors in Russia by restricting the supply of certain oil and gas items and services to Russia and certain forms of financing. Eni has adapted its activities to the applicable sanctions and will adapt its business to any further restrictive measures that could be adopted by the relevant authorities. Recently, the US Government has tightened the sanction regime against Russia by enacting the “Countering America’s Adversaries Through Sanctions Act”. In response to these new measures, the Company could possibly refrain from pursuing business opportunities in Russia, while currently the Company is not engaged in any upstream projects in Russia. It is possible that wider sanctions targeting the Russian energy, banking and/or finance industries may be implemented. Further sanctions imposed on Russia, Russian citizens or Russian companies by the international community, such as restrictions on purchases of Russian gas by European companies or measures restricting dealings with Russian counterparties, could adversely impact Eni’s business, results of operations and cash flow. Furthermore, an escalation of the international crisis, resulting in a tightening of sanctions, could entail 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 prospects. In 2017, the US Administration enacted certain financing sanctions against Venezuela, which prohibit any US person to be involved in all transactions related to, provision of financing for, and other dealings in, among other things, any debt owed to the Government of Venezuela that is pledged as collateral after the effective date, including accounts receivable. Recently the US Administration has resolved to impose an embargo on the import of crude oil from Venezuela state-owned oil company, PDVSA and has restricted the ability of US dealers to trade bonds issued by the Government of Venezuela and its affiliates. These sanctions do not affect directly Eni’s activities, which however are affected by the worsening financial, political and operating outlook of the Country which could limit the ability of Eni to recover its investments. Risks in the Company’s Gas & Power business Risks associated with the trading environment and competition in the gas market Until 2018, our Gas & Power segment has recorded a history of weak profitability and losses due to the changed fundamentals of the wholesale gas markets in Europe following the gas downturn of 2013-2014. Competition escalated driven by muted demand growth, oversupplies and the increasing weigh in the European energy mix of governmental-subsided renewable energy sources (particularly the photovoltaic). The large-scale development of shale gas in the United States was another factor contributing to the oversupply situation in Europe, because many LNG projects worldwide that originally targeted the US market were redirected to an already saturated European market. Furthermore, a number of re-gasification terminals in the US have been upgraded to gas liquefaction facilities with the aim of exporting the US gas surplus. Large gas supplies to Europe led to the development of liquid spot markets where gas is traded daily. Prices at those hubs became the main indexation parameter of selling prices, replacing prices contractually agreed in bilateral negotiations between gas buyers and gas wholesalers. Increased competition, market liquidity and indexation mismatch between gas purchase prices and selling prices determined a squeeze of margins on gas sales. These trends were exacerbated by the contractual commitments taken by the Company to supply gas to end-markets in Europe. A few years ago, before the onset of the European gas downturn, the Company signed with the main Countries supplying gas to Europe (Russia, Algeria, the Netherlands, Libya and Norway) long-term gas supply contracts with take-or-pay clauses, which would expose us to a volume risk, as the Company was contractually required to purchase minimum annual amounts of gas or, in case of failure, to pay the corresponding price. Additionally, Eni booked the transportation rights along the main gas backbones across Europe to deliver its contracted gas volumes to end-markets. In a weak market, FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 97 the need to dispose of the minimum off-take of gas negatively affected Eni’s margins. Those market trends have negatively affected the operating performance of our Gas & Power segment from the beginning of the market crisis throughout 2017, when this segment closed at breakeven. However, in 2018 the segment posted a significant recovery in profitability due to the benefits of the renegotiations of its long-term gas supply contracts and other drivers. Furthermore, in 2018 gas demand and supplies in Europe were more balanced due to a certain recovery in demand supported by the phase out of a number of coal-fired power plants and lower production from nuclear plants, a slowdown in the final investment decisions in new liquefaction capacity due to the oil downturn and increasing gas demand from China. Looking forward, the Company expects that a muted demand environment in Europe driven by an ongoing economic slowdown will increase the risks of oversupplies and margin pressure. Against the backdrop of a challenging competitive environment, Eni anticipates a number of risk factors to the profitability outlook of the Company’s gas marketing business over the four- year planning period, considering the Company’s operational constraints dictated by its long-term supply contracts with take-or-pay clauses and its structure of fixed costs linked to the transportation rights at the main European backbones booked for multi-year periods. Such risk factors include continuing oversupplies, pricing pressures, volatile margins and the risk of deteriorating spreads of Italian spot prices versus continental benchmarks. The results of Eni’s wholesale business are particularly exposed to the volatility of the spreads between spot prices at European hubs and Italian spot prices because the Group’s supply costs are mainly linked to prices at European hubs, whereas a large part of the Group’s selling volumes are linked to Italian spot prices which, historically, have been higher due to the costs of logistics and other factors. This price differential enables the Company to recover its fixed operating expenses in the gas wholesale business. Risks are raising that spot prices in Italy could converge with prices at continental hubs due to the current slowdown of gas demand in Europe and in Italy and the return of LNG spot volumes at European markets and also at Italian regasification terminals. Longer-term there are risks of an oversupply build in the Italian market due to the expected entry into operations of a project to import gas from the Caspian region to Italy and other developments. A reduction of the spread between Italian spot prices and European spot prices for gas could negatively affect the profitability of our business by reducing the total addressable market and the related opportunities to monetize the flexibilities of our gas portfolio, as in the case of the possibility to lift additional gas volumes in addition to the annual minimum quantity at our take-or-pay contracts up the annual contractual quantity in case of favorable market conditions. Eni’s management is planning to continue its strategy of renegotiating the Company’s long-term gas supply contracts in order to constantly align pricing and volume terms to current market conditions as they evolve, considering the risk factors described above. The revision clauses provided by these contracts state 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 obtained and the timing of recognition of profit. Furthermore, in case Eni and the gas suppliers fail to agree on revised contractual terms, the claiming party has the ability to open an arbitration procedure to obtain revised contractual conditions. However, the suppliers might also file counterclaims with the arbitration panel seeking to dismiss Eni’s request for a price review and may also claim an increase in the price of the gas supplied to Eni based on their own view of markets dynamics. All these possible developments within the renegotiation process could increase the level of risks and uncertainties relating the outcome of those renegotiations. Current, negative trends in gas demands and supplies may impair the Company’s ability to fulfil its minimum off-take obligations in connection with its take-or-pay, long-term gas supply contracts In the years preceding the European gas downturn of 2013- 2014, Eni signed a number of long-term gas supply contracts with national operators of certain key producing Countries, from where most of the European gas supplies are sourced (Russia, Algeria, Libya, the Netherlands and Norway). These contracts were intended to secure Eni long-term access to gas supplies, particularly with a view to supplying the Italian gas market and in anticipation of certain pargets of gas demand growth, which however would fall short of industry’s projections. These contracts include take-or-pay clauses whereby the Company has an obligation to lift 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. Similar considerations apply to ship-or-pay contractual obligations. Long-term gas supply contracts with take-or-pay clauses expose the Company to a volume risk, as the Company is obligated to purchase an annual minimum volume of gas, or in case of failure, to pay the underlying price. Management believes that the current level of market liquidity, the outlook of the European gas sector which is featuring muted demand growth, strong competitive pressures and large supplies, as well as any possible change in sector-specific regulation represent risk factors to the Company’s ongoing ability to fulfil its minimum take obligations associated with its long-term supply contracts. Risks associated with sector-specific regulations in Italy Risks associated with the regulatory powers entrusted to the Italian Regulatory Authority for Energy, Networks and Environment in the matter of pricing to residential customers Eni’s Gas & Power segment is subject to regulatory risks mainly in its domestic market in Italy. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 201898 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 and commercial users until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of de-regulation, or intended to reduce operators’ ability to transfer to customers cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results and cash flow. Environmental, health and safety regulations Eni has incurred in the past, and 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 regarding the impact 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, including refinery and petrochemical plant operations, limit or prohibit drilling activities in certain protected areas, require to remove and dismantle drilling platforms and other equipment and well plug-in once oil and gas operations have terminated, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the Company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees’ or communities’ health and safety resulting from the Group’s operations. These laws and regulations set limits to the emission of scrap substances and pollutants and discipline the handling of hazardous materials and discharges of water contaminants nad nocive air emissions 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 or operated 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. Breaches of environmental, health and safety laws and regulations as in the case of negligent or willful release of pollutants into the atmosphere, the soil or groundwater or the overcome of concentration threshold of contaminants set by the law expose the Company to the incurrence of liabilities associated with compensation for environmental, health or safety damage and expenses for environmental remediation and clean-up. Furthermore, in the case of violation of certain rules regarding the safeguard of the environment and safety in the workplace and of communities, the Company may be liable for the negligent or willful conduct on part of its employees as per Italian Law Decree No. 231/2001, which assumes that any misconduct of employees in the field of environmental and health matters can be ascribed to the Company. Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures in the foreseeable future to comply with laws and regulations and to safeguard the environment, safety in the workplace, health of employees, contractors and communities involved by the Company operations, including: - costs to prevent, control, eliminate or reduce certain types of air and water emissions and handle waste and other hazardous materials, including the costs incurred in connection with government action to address climate change; - remedial and clean-up measures related to environmental contamination or accidents at various sites, including those owned by third parties (see discussion below); - damage compensation claimed by individuals and entities, including local, regional or state administrations, should Eni cause any kind of accident, oil spill, well blowouts, pollution, contamination, emission of GHG above permitted levels or of any other hazardous gases, water, ground or air contaminants or pollutants, as a result of its operations or if the Company is found guilty of violating environmental laws and regulations; and - costs in connection with the decommissioning and removal of drilling platforms and other facilities, and well plugging at the end of Oil & Gas field production. As a further result of any new laws and regulations or other factors, like the actual or alleged occurrence of environmental damage at Eni’s plants and facilities, the Company may be forced 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, cash flow and liquidity. 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 such 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’s business, competitive position, cash flow, results of operations, liquidity, future growth prospects, shareholders’ returns and damage to the Group’s reputation. FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 99 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. Furthermore, environmental requirements and regulations in Italy and elsewhere typically impose strict liability. Strict liability means that in some situations Eni could be exposed to liability for clean-up and remediation costs, environmental damage, and other damages as a result of Eni’s conduct of operations that was lawful at the time it occurred or of 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 found liable of violations of any environmental laws or regulations. In Italy, Eni is exposed to the risk of expenses and environmental liabilities in connection with the impact of its past activities at certain industrial hubs where the Group’s products were produced, processed, stored, distributed or sold, such as chemical plants, mineral-metallurgic plants, refineries and other facilities, which were subsequently disposed of, liquidated, closed or shut down. At these industrial hubs, Eni has undertaken a number of initiatives to remediate and to clean-up proprietary or concession areas that were allegedly contaminated and polluted by the Group’s industrial activities. State or local public administrations have 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. In some cases, Eni has been sued for alleged breach of criminal laws (for example for alleged environmental crimes such as failure to perform soil or groundwater reclamation, environmental disaster and contamination, discharge of toxic materials, amongst others). Although Eni believes that it may not be held liable for having exceeded in the past pollution thresholds that are unlawful according to current regulations but were allowed by laws then effective, nor because the Group took over operations from third parties, it cannot be excluded that Eni could potentially incur such environmental liabilities. Eni’s financial statements account for provisions relating to the costs to be incurred with respect to clean-ups and remediation of contaminated areas and groundwater for which a legal or constructive obligation exists and the associated costs can be reasonably estimated in a reliable manner, regardless of any previous liability attributable to other parties. The accrued amounts represent management’s best estimates of the Company’s existing liabilities. 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 Eni’s industrial sites as required by the applicable regulations on contaminated sites; (iii) unfavourable developments in ongoing litigation on the environmental status of certain of the Company’s sites where a number of public administrations and the Italian Ministry of the Environment act as plaintiffs; (iv) the possibility that new litigation might arise; (v) the probability that new and stricter environmental laws might be implemented; and (vi) the circumstance that the extent and cost of environmental restoration and remediation programs are often inherently difficult to estimate leading to underestimation of the future costs of remediation and restoration, as well as unforeseen adverse developments both in the final remediation costs and with respect to the final liability allocation among the various parties involved at the sites. As a result of those risks, environmental liabilities could be substantial and could have a material adverse effect on Eni’s results of operations, cash flow, financial condition, business prospects, reputation and shareholders’ value, including dividends and the share price. Rising public concern related to climate change has led and could continue to lead to the adoption of national and international laws and regulations which are expected to result in a decrease of demand for hydrocarbons and increased compliance costs for the Company. Eni is also exposed to risks of technological breakthrough in the energy field and risks of unpredictable extreme meteorological events linked to the climate change. All these developments may adversely affect the Group’s profitability, businesses outlook and reputation Growing worldwide public concern over greenhouse gas (GHG) emissions and climate change, as well as increasingly regulations in this area, could adversely affect the Group’s business and reputation, increase its operating costs and reduce its results of operations, cash flow, financial condition, business prospects and shareholders returns. Those risks may emerge in the short and medium-term, as well as over the long term. The scientific community has established a link between climate change and increasing GHG concentration in the atmosphere. International efforts to limit global warming have led, and Eni expects them to continue to lead, to new laws and regulations designed to reduce GHG emissions that are expected to bring about a gradual reduction in the use of fossil fuel over the medium to long-term, notably through the diversification of the energy mix. Governmental institutions have responded to the issue of climate change on two fronts: on one side, governments can both impose taxes on GHG emissions and incentivize a progressive shift in the energy mix away from fossil fuels, for example, by subsidizing the power generation from renewable sources. Some governments have already introduced carbon pricing schemes, which can be an effective measure to reduce GHG emissions at the lowest overall cost to society. Today, about FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018100 half of the GHG direct emissions coming from Eni operated assets are already included in national or supranational Carbon Pricing Mechanisms, such as the European Emission Trading Scheme. Eni expects that more governments will adopt similar schemes and that a growing share of the Group’s GHG emissions will be subject to carbon-pricing and other forms of climate regulation in the short to medium term. Eni expects that governments require companies to apply technical measures to reduce their GHG emissions. Eni is already incurring operating costs related to its participation in the European Emission Trading Scheme, whereby Eni is required to purchase on the open markets emission allowances in case its GHG emissions exceed freely-assigned emission allowances (see note No. 27 to the Financial Statements). In 2018 to comply with this carbon emissions scheme, Eni purchased on the open market allowances corresponding to 12.7 million tonnes of CO2 emissions. In certain jurisdictions, Eni is also subject to carbon pricing schemes in Norway. Due to the likelihood of new regulations in this area, Eni expects additional compliance obligations with respect to the release, capture, and use of carbon dioxide that could result in increased investments and higher project costs for Eni and could have a material adverse effect on Eni’s operating costs and results of operations, cash flow, financial condition, business prospects and shareholders’ returns. Eni also expects that governments will also require companies to apply technical measures to reduce their GHG emissions. Eni expects that the achievement of the Paris Agreement goal of holding the increase in global average temperature to less than 2 °C above pre-industrial levels, or the more stringent goal advocated by the Intergovernmental Panel on Climate Change (IPCC) to limit global warming to 1.5 °C, will strengthen the global response to the threat of climate change and spur governments to introduce further measures and policies targeting the reduction of GHG emissions, which will reduce local demand for fossil fuels, thus negatively affecting global demand for oil and natural gas. Eni’s business depends on the global demand for oil and natural gas. If existing or future laws, regulations, treaties, or international agreements related to GHG and climate change, including incentives to preserve energy or use alternative energy sources, technological breakthrough in the field of renewable energies or mass-adoption of electric vehicles reduce the worldwide demand for oil and natural gas by a large amount, Eni’s results of operations, cash flow, financial condition, business prospects and shareholders’ returns may be significantly and adversely affected. The scientific community has concluded that increasing global average temperatures produces significant physical effects, such as the increased frequency and severity of hurricanes, storms, droughts, floods or other extreme climatic events that could interfere with Eni’s operations and damage Eni’s facilities. Extreme and unpredictable weather phenomena can result in material disruption to Eni’s operations, and consequent loss of or damage to properties and facilities, as well as a loss of output, loss of revenues, increasing maintenance and repair expenses and cash flow shortfall. Finally, there is a reputational risk linked to the fact that oil companies are increasingly perceived by institutions and the general public as the entities responsible of the global warming due to GHG emissions across the value chain and in particular related with the use of energy products. This could possibly make Eni’s shares less attractive to investment funds and individual investors who have been more and more assessing the risk profile of companies against their carbon footprint when making investment decisions. This trend could have a material adverse effect on the price of our securities and our ability to access equity or other capital markets. Additionally, the World Bank has announced plans to stop financing upstream oil and gas projects in 2019. Similarly, according to press reports, other financial institutions also appear to be considering limiting their exposure to certain fossil fuel projects. Accordingly, our ability to use financing for future projects may be adversely impacted. This could also adversely impact our potential partners’ ability to finance their portion of costs, either through equity or debt. Further, in some Countries, governments and regulators have filed lawsuits seeking to hold fossil fuel companies, including Eni, liable for costs associated with climate change. Losing any of these lawsuits could have a material adverse effect on our results of operations, cash flows, liquidity and business prospects. For further information see pages 29-30 of the Annual Report on Form 20-F 2018 - Item 4 - Information on the Company. Risks related to legal proceedings and compliance with anti- corruption legislation Eni is the defendant in a number of civil and criminal actions and administrative proceedings. In addition to existing provisions accrued as of December 31, 2018 to account for ongoing proceedings, in future years Eni may incur significant losses in addition to the amounts already accrued in connection with pending or future 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 and investigations in which Eni or its subsidiaries or its officers and employees are defendant involve the alleged breach of anti-bribery and anti- corruption laws and regulations and other ethical misconduct. Such proceedings are described in note 27 to the 2018 consolidated financial statements, under the heading “Legal Proceedings”. Ethical misconduct and noncompliance with applicable laws and regulations, including noncompliance with anti-bribery and anti- corruption laws, by Eni, its officers and employees, its partners, agents or others that act on the Group’s behalf, could expose Eni and its employees to criminal and civil penalties and could be damaging to Eni’s reputation and shareholder value. Risks from acquisitions Eni is constantly monitoring the oil and gas market in search of opportunities to acquire individual assets or companies with a view of achieving its growth targets or complementing its FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES101 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 related to acquisitions materialize, expected synergies from acquisition may fall short of management’s targets and 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. Eni’s crisis management systems may be ineffective 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. Eni has crisis management plans and the 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 exposed to financial risk, which includes exposure to market risk, including commodity price risk, interest rate risk and foreign currency risk, as well as liquidity risk, and credit risk. Eni’s primary source of exposure to financial risk is the volatility in commodity prices. Generally, the Group does not hedge its strategic exposure to the commodity risk associated with its plans to find and develop oil and gas reserves, volume of gas purchased under its long-term gas purchase contracts, which are not covered by contracted sales, its refining margins and other activities. The Group’s risk management objectives in addressing commodity risk are to optimize the risk profile of its commercial activities by effectively managing economic margins and safeguarding the value of Eni assets. To achieve this, Eni engages in risk management activities seeking both to hedge Group’s exposures and to profit from short-term market opportunities and trading. Eni is engaged in substantial trading and commercial activities in the physical markets. Eni also uses financial instruments such as futures, options, Over-the-Counter 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 risk. 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 Officer is in charge of defining policies and tools to manage the Group’s exposure to financial risk, as well as monitoring and reporting activities. Various Group committees are in charge of defining internal criteria, guidelines and targets of risk management activities consistent with the strategy and limits defined at Eni’s top level, to be used by the Group’s business units, including monitoring and controlling activities. Although Eni believes it has established sound risk management procedures, trading activities involve elements of forecasting and Eni is exposed to the risks of market movements, of incurring significant losses if prices develop contrary to management expectations and of default of counterparties. Disruption to or breaches of Eni’s critical IT services or information security systems could adversely affect the Group’s activities The Group’s activities depend heavily on the reliability and security of its information technology (IT) systems. The Group’s IT systems, some of which are managed by third parties, are susceptible to being compromised, damaged, disrupted or shutdown due to failures during the process of upgrading or replacing software, databases or components, power or network outages, hardware failures, cyber-attacks (viruses, computer intrusions), user errors or natural disasters. The cyber threat is constantly evolving. Attacks are becoming more sophisticated with regularly renewed techniques while the digital transformation amplifies exposure to these cyber threats. The adoption of new technologies, such as the Internet of things (IoT) or the migration to the cloud, as well as the evolution of architectures for increasingly interconnected systems, are all areas where cyber security is a very important issue. The Group and its service providers may not be able to prevent third parties from breaking into the Group’s IT systems, disrupting business operations or communications infrastructure through denial-of-service attacks, or gaining access to confidential or sensitive information held in the system. The Group, like many companies, has been and expects to continue to be the target of attempted cybersecurity attacks. While the Group has not experienced any such attack that has had a material impact on its business, the Group cannot guarantee that its security measures will be sufficient to prevent a material disruption, breach or compromise in the future. FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018 102 As a result, the Group’s activities and assets could sustain serious damage, services to clients could be interrupted, material intellectual property could be divulged and, in some cases, personal injury, property damage, environmental harm and regulatory violations could occur, potentially having a material adverse effect on the Group’s financial condition, including its operating income and cash flow. The United Kingdom leaving the European Union may affect the Group’s results On June 23, 2016, the UK held a referendum to decide on the UK’s membership of the European Union. The UK vote was to leave the European Union. There are a number of uncertainties in connection with the future of the UK and its relationship with the European Union. The negotiation of the UK’s exit terms is likely to take a number of years. Until the terms and timing of the UK’s exit from the European Union are clearer, it is not possible to determine the impact that the referendum, the UK’s departure from the European Union and/or any related matters may have on the business of the Issuer. As such, no assurance can be given that such matters would not adversely affect the Company’s business prospects, results of operations, cash flows and liquidity. FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESOUTLOOK 103 For further information on Eni’s business outlook and financial and operational targets, please see the chapter “Scenario and Strategy”. 104 CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION In accordance with the Italian Legislative Decree 254/2016 Introduction Eni’s 2018 Consolidated Disclosure of Non-Financial Information (NFI) has been prepared by structuring the report on the three levers of Eni’s integrated business model (Path to Decarbonisation, Operational Excellence Model and Promotion of Local Development) whose objective is to create long-term value for stakeholders, combining financial stability with social and environmental sustainability. The NFI provides an integrated view on the topics set out in Italian Legislative Decree 254/2016, also by providing references to other sections of the Annual Report or to the Corporate Governance Report, if the information is already contained therein or to provide further explanation. In particular, the Annual Report illustrates: - Eni’s business and Governance Model; - risk management in the sections (i) “Integrated Risk Management”, including Eni’s Integrated Risk Management (IRM) model, the control levels, the process – including the sustainability aspects – and its governance, and the main activities for 2018; (ii) “Targets, risks and treatment measures”, showing the Top Risks for Eni and the main actions taken by the Company to mitigate them; (iii) “Risk factors and uncertainties”, where the main non-financial risks, their potential impacts and treatment actions are described in greater detail. The NFI illustrates in detail: - Company policies in the section “Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics”. Eni has a regulatory system composed of direction, coordination and control instruments (Policies and Management System Guidelines - MSGs) and instruments which define the operating procedures (procedures and operating instructions). The Policies, approved by the BoD, define the principles and general rules of conduct on which Eni’s activities must, without exception, be based. The MSGs, instead, are common guidelines for all Eni units for the management of operating and business support processes and cross-cutting compliance and governance processes, including sustainability aspects; - the main features of the “Eni Organizational and Management Models” for the following issues: environment, climate, people, health and safety, human rights, suppliers, transparency and anti- corruption, local communities, innovation and digitalization; - the strategy on the issues dealt with, the most significant initiatives of the year and the main performance results with related comments. The contents of the “Path to Decarbonization” are drafted according to the voluntary recommendations of the Task Force on Climate-related Financial Disclosures (TCFD) defined by the Financial Stability Board. Finally, reference to the main United Nations Sustainable Development Goals (SDGs) has been included in the various chapters. The UN’s 2030 Agenda for Sustainable Development, presented in September 2015, identifies 17 Sustainable Development Goals, which represent common goals for the current complex social challenges. These goals are a valuable source of guidance for the international community and for Eni in conducting its activities in the Countries in which it operates. As in previous years, Eni will also publish, on the occasion of the Shareholders’ Meeting, the Sustainability Report (Eni For), which will continue to be a voluntary disclosure document, certified according to the GRI Standards and with its own limited assurance. Below is a table showing the correspondence between the information content required by the Decree and its position within the NFI, the Annual Report or Corporate Governance Report. AREAS OF THE ITALIAN LEGISLATIVE DECREE 254/2016 PARAGRAPHS INCLUDED IN THE NFI THEMES AND FOCUSES IN THE ANNUAL REPORT (AR) AND IN THE CORPORATE GOVERNANCE AND SHAREHOLDING STRUCTURE REPORT (CGR) COMPANY MANAGEMENT MODEL AND GOVERNANCE Art. 3.1, paragraph a) • Eni’s organizational and management models, p. 107 • Path to decarbonization, pp. 108-111 • Operational excellence model, pp. 112-122 • Promotion of local development: cooperation model, pp. 122-123 • Key sustainability topics, p. 124 AR  Business Model, p. 4  Responsible and sustainable approach, p. 5  Governance, pp. 24-29  Stakeholders engagement, pp. 14-15 CGR  Responsible and sustainable approach, pp. 8-10  Corporate Governance Model, pp. 11-13  Board of Directors: composition, pp. 35-40 and Board POLICIES Art. 3.1, paragraph b) RISK MANAGEMENT MODEL Art. 3.1, paragraph c) CGR AR • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Path to decarbonization, pp. 108-111 • People, pp. 112-114 • Safety, p. 115 • Respect for the environment, pp. 116-118 • Human Rights, pp. 118-120 • Suppliers, p. 120 • Transparency and anti-corruption, pp. 121-122 induction, p. 55  Board committees, pp. 55-64  Board of Statutory Auditors, pp. 64-73  Model 231, pp. 101-102  Eni Regulatory System, pp. 87-100  Integrated Risk Management Model, p. 20; Integrated Risk Management Process, p. 21; Targets, risks and treatment measures pp. 22-23; Risk factors and uncertainties, pp. 87-102 105 AREAS OF THE ITALIAN LEGISLATIVE DECREE 254/2016 PARAGRAPHS INCLUDED IN THE NFI THEMES AND FOCUSES IN THE ANNUAL REPORT (AR) AND IN THE CORPORATE GOVERNANCE AND SHAREHOLDING STRUCTURE REPORT (CGR) CLIMATE CHANGE Art. 3.2, paragraph a) Art. 3.2, paragraph b) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • Path to decarbonization (governance, risk management, strategy and objectives), pp. 108-111 AR  Integrated Risk Management, pp. 20-23; Safety, security, environmental and other operational risks, pp. 89-91; Risks related to climate change, pp. 99-100  Scenario and strategy, pp. 16-19 CGR  Responsible and sustainable approach, pp. 8-10 O T H T A P I I N O T A Z N O B R A C E D I L A N O T A R E P O L E D O M E C N E L L E C X E PEOPLE Art. 3.2, paragraph d) Art. 3.2, paragraph c) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • People (employment, diversity and inclusion, training, industrial relations, welfare, health), pp. 112-114 • Safety, p. 115 AR  Integrated Risk Management, pp. 20-23; Risks associated with the exploration and production of oil and natural gas, pp. 90-94; Safety, security, environmental and other operational risks, pp. 89-91  Governance, pp. 24-29 (Remuneration Policy, p. 28) RESPECT FOR THE ENVIRONMENT Art. 3.2, paragraph a) Art. 3.2, paragraph b) Art. 3.2, paragraph c) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • Respect for the environment (circular economy, water, spills, waste, biodiversity), pp. 116-118 AR  Integrated Risk Management, pp. 20-23; Risks associated with the exploration and production of oil and natural gas, pp. 91-94; Safety, security, environmental and other operational risks, pp. 89-91 HUMAN RIGHTS Art. 3.2, paragraph e) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • Human rights (risk management, security, training, whistleblowing), pp. 118-120 SUPPLIERS Art. 3.1, paragraph c) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • Suppliers (risk management), p. 120 CGR  Responsible and sustainable approach, pp. 8-10 TRANSPARENCY AND ANTI- CORRUPTION Art. 3.2, paragraph f) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, AR  Integrated Risk Management, pp. 20-23; Risks related to legal proceedings and compliance with anti-corruption legislation, p. 100 p. 107  The internal control and risk management • Transparency and anti-corruption, pp. 121-122 system, p. 29 CGR  Principles and values. Code of Ethics, p. 7; Anti-Corruption Compliance Program, pp. 102-104 I L E D O M N O T A R E P O O C LOCAL COMMUNITIES Art. 3.2, paragraph d) • Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics, p. 106 • Eni’s organizational and management models, p. 107 • Promotion of local development: cooperation model, pp. 122-123 AR  Integrated Risk Management, pp. 20-23; Political considerations, pp. 94-96; Risks associated with the exploration and production of oil and natural gas, pp. 91-94 : T N E M P O L E V E D L A C O L F O N O T O M O R P I Annual Report 2018. AR CGR Corporate Governance Report 2018.  Sections/paragraphs providing the disclosures required by the Decree.  Sections/paragraphs to which reference should be made for further details. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 106 Main regulatory and guiding instruments related to Legislative Decree 254/2016 topics PATH TO DECARBONIZATION CLIMATE CHANGE OBJECTIVE Promote the energy transition PUBLIC DOCUMENTS “Sustainability” policy; Eni’s Position on Biomass PRINCIPLES: • reduce greenhouse gas emissions, improving plant efficiency and increasing the use of low carbon content fuel • develop and implement new technologies for the reduction of Greenhouse gas emissions and more efficient energy production • use the opportunities offered by the development of international carbon markets, including tools to reduce deforestation • promote sustainable management of water resources • assure a sustainable management of biomass throughout the supply chain • acquire palm oil produced only in a sustainable way, in compliance with social, environmental and safety requirements OPERATIONAL EXCELLENCE MODEL PEOPLE, HEALTH AND SAFETY OPERATIONAL EXCELLENCE MODEL RESPECT FOR THE ENVIRONMENT OBJECTIVE Valorize Eni’s people and protect their health and safety OBJECTIVE Use resources efficiently and protect biodiversity and ecosystem services PUBLIC DOCUMENTS “Our people”, “Integrity in our operations” policies PRINCIPLES: • respect the dignity of each person, valuing diversity, whether related to culture, ethnicity, gender, age, sexual orientation or disability • provide managers with tools and support for the management and development of the people working for them • identify the essential knowledge and skills for Company growth and promote their enhancement, development and sharing • adopt equitable remuneration systems that motivate and support the retention of the best people to meet the needs of the business • conduct activities in accordance with agreements and regulations on workers’ health and safety and based on the principles of precaution, prevention, protection and continuous improvement PUBLIC DOCUMENTS “Sustainability”, “Integrity in our operations” policies; “Eni biodiversity and ecosystem services policy”; “Eni’s positioning with regards to Green Sourcing” PRINCIPLES: • consider, when evaluating projects and in operational practices, the presence of protected areas and of areas of biodiversity value, identifying potential impacts and mitigation actions • ensure connections with environmental aspects (climate, BES(a) and management of water resources) and social issues such as the sustainable development of local communities • promote circular economy and the commitment to the efficient use of resources • promote Green Sourcing principles • optimize control and reduction of emissions in air, water and soil • implement sustainable remediation to return areas to the community or not use virgin areas for new industrial initiatives • carry out “risk based” environmental studies to increase the quality of the response in the event of accident PROMOTION OF LOCAL DEVELOPMENT: COOPERATION MODEL OPERATIONAL EXCELLENCE MODEL OPERATIONAL EXCELLENCE MODEL HUMAN RIGHTS OBJECTIVE Protect human rights PUBLIC DOCUMENTS “Sustainability”, “Our people”, “Our Partners in the Value Chain”, “Integrity in our operations” policies; Code of Ethics; Eni Statement on Respect for Human Rights PRINCIPLES: • respect human rights and promote their respect among employees, partners and stakeholders, also through training and awareness-raising activities • ensure a safe and healthy working environment and working conditions in line with international standards • take into account Human Rights issues, from the very first feasibility evaluation phases of projects and respect the distinctive rights of indigenous peoples and vulnerable groups • select partners who comply with the Code of Ethics and who are committed to preventing or mitigating impacts on human rights • minimize the necessity for intervention by state and/or private security forces to protect employees and assets (a) Biodiversity and Ecosystem Services. TRANSPARENCY AND ANTI-CORRUPTION LOCAL COMMUNITIES OBJECTIVE Combat active and passive corruption PUBLIC DOCUMENTS “Anti-Corruption” Management System Guideline; “Our partners in the value chain” policy; Tax Strategy Guideline PRINCIPLES: • carry out business activities with fairness, correctness, transparency, honesty and integrity in compliance with the law • prohibit bribery without exception • prohibit offering, promising, giving, paying, directly or indirectly, benefits of any nature to a Public Official or a private person (active corruption) • prohibit accepting, directly or indirectly, benefits of any nature from a Public Official or a private person (passive corruption) • ensure that all Eni employees and partners comply with the internal anti-corruption regulations OBJECTIVE Promote relations with local communities and contribute to their development PUBLIC DOCUMENTS “Sustainability” policy PRINCIPLES: • create growth opportunities and enhance the skills of people and local companies in the territories where Eni operates • involve local communities in order to consider their concerns on new projects, impact assessments and development initiatives • identify and assess the environmental, social, economic and cultural impacts generated by Eni activities, including those on indigenous peoples • promote free, prior and informed consultation with local communities • cooperate in initiatives to guarantee independent, long-lasting and sustainable local development CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION107 DIMENSION ORGANIZATIONAL AND MANAGEMENT MODELS CLIMATE CHANGE • Organizational centralized function dedicated to Climate Change, Energy Efficiency & New Issues • Long-term Positioning Initiatives Coordination Unit for Circular Economy and Carbon Neutrality initiatives in this area • Climate Change Program cross-functional working group whose Steering Committee is chaired by the CEO: it aims to gradually reduce GHG emissions in line with the 2 °C target • Energy Transition Research and Development Program: it aims to develop technologies to promote the rapid spread of natural gas usage, decarbonizing the supply chain •Energy Solutions Department: business development for energy production from renewable sources and management of relevant assets by dedicated companies • Unit of the Legal Affairs Department dedicated to the topics of Climate Change, Sustainability and Circular Economy • Energy management systems according to the ISO 50001 standard O T H T A P I I N O T A Z N O B R A C E D I L A N O T A R E P O L E D O M E C N E L L E C X E PEOPLE SAFETY • Employment management and planning process to align skills to the technical and professional needs of the Company • Human resources management and development tools, aimed at professional growth and involvement, inter-generational exchange of experiences, building of cross-cutting managerial development courses in line with the Company’s strategic opportunities, professional development in core technical areas and valuing diversity • Quality management system for training, up-to-date and complying with the ISO 9001:2015 standard • Knowledge management system for integrating and sharing know-how and professional experiences • National and international industrial relations management system: participative model and platform of operating tools to motivate and engage employees in compliance with International Labour Organization conventions and the guidelines of the Institute for Human Rights and Business • Integrated environmental, health and safety management system based on an operating platform of qualified healthcare providers and partnerships with national and international university and governmental research centers and institutions • Security management system aimed at ensuring protection for Eni people in all the Countries in which Eni operates and particularly in high-risk Countries • Welfare system for the achievement of work-life balance and the enhancement of services for employees and their families • Integrated environmental, health and safety management system for workers with the aim of eliminating or mitigating the risks to which workers are exposed during their work activities • Process safety management system aimed at preventing major accidents by applying high technical and management standards (application of best practices for asset design, operating management, maintenance and decommissioning) • Emergency preparation and response with plans that put the protection of people and the environment first • Product safety management system for the assessment of risks related to the production, import, sale, purchase and use of substances/mixtures to ensure human health and environmental protection throughout their life cycle • Integrated environmental, health and safety management system: adopted in all plants and production units in accordance with the ISO 14001:2015 environmental management standard RESPECT FOR THE ENVIRONMENT • Application of the Environmental, Social & Health Impact Assessment (ESHIA) process to all projects • Technical meetings for the analysis and sharing of experiences on specific environmental issues • Green Sourcing: model to identify analysis methods and technical requirements to be adopted for the selection of products and suppliers that are able to ensure better environmental performances • Biomasses Working Group: implementation of the commitments set out in Eni’s Position on biomass and palm oil • Human rights management process regulated in a Management System Guideline • Working Group on Business and Human Rights: to further align business processes with the main international standards and best practices HUMAN RIGHTS • Application of the ESHIA process to all projects, integrated with the analysis of human rights impacts • Specific analyses of human rights impacts known as HRIA (Human Rights Impact Assessment) • 231 Model: sets out responsibilities, sensitive activities and control protocols for crimes of corruption under Italian Legislative Decree 231/01 (including environmental crimes and crimes relating to workers’ health and safety) • Anti-Corruption Compliance Program: system of rules and controls to prevent corruption crimes • Recognition for the Anti-Corruption Compliance Program: certified pursuant to the ISO 37001:2016 standard • “Anti-Corruption Compliance” organizational structure under the “Integrated Compliance” department and reporting directly to the Chief Executive Officer • Procurement Process designed to check compliance with Eni’s requirements for ethical conduct and trustworthiness, health, safety, and environmental protection and human rights, through the qualification, selection, management and monitoring of suppliers, as well as through assessment using parameters set out by the Social Accountability Standard (SA8000) • Sustainability focal point at the local level, who interfaces with the Company headquarters to define local community development programs in line with national development plans integrating business processes • Application of the ESHIA process to all projects • Stakeholder Management System Platform for the management and monitoring of the relations with local and other stakeholders and of grievances • Risk identification, mitigation and monitoring system linked to relations with local stakeholders TRANSPARENCY AND ANTI- CORRUPTION SUPPLIERS LOCAL COMMUNITIES L A C O L F O N O T O M O R P I : T N E M P O L E V E D I L E D O M N O T A R E P O O C I N O T A Z I L A T G D I I I D N A N O T A V O N N I • Centralized Research & Development Function for optimal sharing and best use of know-how • Management of Technological Innovation projects in line with R&D best practices (planning and control for the steps following the development of the technology) • Continuous updating of procedures relating to the protection of intellectual property and the identification of professional R&D service providers INNOVATION CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 108 PATH TO DECARBONIZATION Taking into account the scientific evidence on climate change of the Intergovernmental Panel on Climate Change (IPCC), Eni intends to play a leading role in the energy transition process, supporting the objectives of the Paris Agreement. Eni has long been committed to promoting comprehensive and effective climate change disclosure and in this respect confirms its commitment to implementing the recommendations of the Task Force on Climate Related Financial Disclosure (TCFD) published in 2017. Disclosure on the path to decarbonization is structured around the four topic areas covered by TCFD recommendations: governance, risk management, strategy and metrics and objectives. The key elements of each topic are presented below and feature cross-references to the Eni for 2018 Report - Path to Decarbonization1 for a complete analysis. GOVERNANCE Eni’s decarbonization strategy is part of a structured system of Corporate Governance; within this, the Board of Directors (BoD) and the Chief Executive Officer (CEO) play a central role in managing the main aspects linked to climate change. The BoD examines and approves, based on the CEO’s proposal, the Strategic Plan, which sets out strategies and includes objectives also on climate change and energy transition. Eni’s economic and financial exposure to the risk that may derive from new carbon pricing mechanisms is examined by the BoD both in the phase leading up the authorisation of every investment and in the following half-year monitoring of the entire project portfolio. The BoD is also informed annually on the result of the impairment test carried out on the main Cash Generating Units in the E&P sector and elaborated with the introduction of a carbon tax valued according to the IEA SDS scenario (see pages 99-100). Finally, the BoD is informed on a quarterly basis of the results of the risk assessment and monitoring activities of Eni’s top risks, including climate change. Since 2014, the BOD has been supported in conducting its duties by the Sustainability and Scenarios Committee (CSS), with whom examines, on a periodic basis, the integration between strategy, future scenarios and the medium/long-term sustainability of the business. During 2018, the CSS discussed in detail climate change issues at all meetings, including the decarbonisation strategy, energy scenarios, renewable energies, research and development to support the energy transition, climate partnerships and water resources and biodiversity issues2. Since the second half of 2017, the BoD and the CEO are also supported by an Advisory Board, composed of international experts, called to analyze the main geopolitical, technological and economic trends, including issues related to the decarbonization process3. In 2018, Eni also contributed to the “Climate Governance”4 initiative of the World Economic Forum (WEF), with the involvement of the Eni BoD. From 2015, the CEO also chairs the Steering Committee of the Climate Change Program, a cross-functional working group composed of members of Eni’s top management that assists the CEO in developing and monitoring an appropriate short/medium/long-term decarbonization strategy. The strategic commitment to reduce greenhouse gas emissions is part of the Company’s key goals. Therefore, the CEO’s short-term incentive plan includes the objective of reducing the intensity of GHG direct emissions from upstream operated activities by 12.5%. This objective is consistent with the target of reducing greenhouse gases by 2025 announced to the market and is applied to the incentives for Company managers who have a strategic role on this matter. Among the many international climate initiatives that Eni participates in, Eni’s CEO sits on the Steering Committee of the Oil and Gas Climate Initiative (OGCI) as one of the founding companies. Established in 2014 by five European O&G companies, the OGCI now counts thirteen companies, representing about one third of global hydrocarbon production. In 2018, OGCI launched the first collective industry target, undertaking to reduce the intensity of methane emissions in upstream Oil & Gas operations. Through the Climate Investment scheme, the OGCI is currently engaged in the joint investment of $1 billion over 10 years in the development of technologies to reduce GHG emissions along the energy value chain at global level. As regards partnerships, Eni is the only O&G company to be actively involved, since the start of its work, in the Task Force on Climate Related Financial Disclosure (TCFD), set-up by the Financial Stability Board, which has drawn up voluntary recommendations for corporate climate change disclosure. In keeping with its commitment to climate disclosure, Eni has worked with its peers at the TCFD Oil & Gas Preparer Forum to harmonize the needs of reporting companies with those of users. In this context, the first status report on the implementation of the recommendations in 2017 highlighted the challenges of TCFD reporting and underscored the best practices: Eni was brought forth as an example of how a company should publish the risks and opportunities related to climate change in illustrating its strategy. Transparency in climate change reporting and the strategy implemented by the Company have allowed Eni to be, once again in 2018, a leading company with an A- rating in the Climate Change program of the CDP (formerly Carbon Disclosure Project), the main independent rating that evaluates the actions and strategies of listed international companies to combat climate change. RISK MANAGEMENT Eni has developed and adopted an Integrated Risk Management (IRM) model to ensure that management takes risk-informed decisions, taking fully into consideration current and potential future risks, including medium and long-term ones, as part of an organic and comprehensive vision. The process is implemented using a “top-down, risk-based” approach, starting from the contribution to the definition of Eni’s Strategic Plan, by means of analyses that support the understanding and (1) This report will be published on the occasion of the Shareholders’ Meeting scheduled in May. (2) For more information, please refer to the section “Sustainability and Scenarios Committee” in the 2018 Corporate Governance Report. (3) For more information, please refer to the chapter “Governance” of the Management report included in the Annual Report 2018. (4) The initiative aims to raise the Boards’ level of awareness of climate-related issues, also following the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD). CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION109 evaluation of the likelihood of underlying risk (e.g. definition of specific de-risking objectives) and continue with the support for its implementation through periodic risk assessment & treatment cycles and monitoring. Risk prioritization is carried out on the basis of multi-dimensional matrices that measure the level of risk by combining clusters of probability of occurrence and impact in both quantitative and qualitative terms. The risk of Climate Change is identified as one of Eni’s top strategic risks and is analysed, assessed and monitored by the CEO as part of the IRM process. Main risks and opportunities Climate change is analysed, evaluated and managed by considering energy transition aspects (market scenario, regulatory and technological evolution, reputational issues) and physical phenomena. The analysis is carried out using an integrated and cross-cutting approach which involves specialist departments and business lines and considers the related risks and opportunities. The main findings are shown below. Market scenario. In the IEA Sustainable Development Scenario5 (WEO 2018), taken as a reference to assess the risks of the energy transition, fossil fuels are expected to continue to play a central role in the energy mix (Oil & Gas equal to 48% of the mix in 2040), although in this scenario the global energy demand by 2040 is expected to fall slightly. Natural gas, which grows also in the SDS scenario, represents an opportunity for strategic repositioning for energy companies, due to its lower carbon intensity, the possibility of integration with renewable sources in electricity production and the prospects of growing hydrogen production. Oil demand is expected to grow in the other IEA scenarios (Current Policies Scenario and New Policies Scenario), while in the IEA SDS scenario a peak is expected in almost all Countries before 2030 (except India and sub-Saharan Africa). Nonetheless, also considering the SDS scenario, there is a need for significant investments in the upstream sector to compensate for the drop in production from existing fields. There is residual uncertainty linked to the effect that regulatory developments and breakthrough technologies could have on the scenario, with a consequent impact on the Company business model. Eni carries out an assessment of the potential costs associated with GHG emissions, estimating them on the basis of the Sustainable Development Scenario (SDS) of the International Energy Agency (IEA), as illustrated more in detail in the section Risk Factors and Uncertainty (see pages 99-100). Regulatory developments. The adoption of policies designed to support energy transition to low carbon sources could have significant impacts on the business. The differentiated approach by Country could provide an advantage for the development of new business opportunities. With particular reference to the European scenario, 2018 saw the entry into force of the amended EU-ETS Directive (covering the 2021-2030 period), of the “Circular Economy Package” and the approval of the Renewable Energy Directive (REDII, in force from 2021). At the international level, in 2018 an agreement was reached within the IMO (International Maritime Organization) on the adoption of an initial strategy to reduce greenhouse gas emissions from the shipping sector. Also in the light of this regulatory development, Eni has strengthened its commitment to the development of green business and renewable sources, as illustrated more in detail in the section Strategy and Objectives. Technological developments. The need to build a final energy consumption model with low carbon footprint will favour technologies aimed at capturing and reducing GHG emissions, the production of hydrogen from gas as well as technologies that support the control of methane emissions along the Oil & Gas production chain. These elements will help to support the role of hydrocarbons in the global energy mix. On the other hand, technological development in the field of renewable energy production and storage and in the efficiency of electric vehicles could have impacts on the demand for hydrocarbons and therefore on the business. Scientific and technological research is therefore one of the levers on which Eni’s decarbonization strategy is based and the areas of action are described in the section Strategy and Objectives. Reputation. The increasing attention being given to climate change has an impact on the reputation of the entire Oil & Gas industry, seen as one of the main parties responsible for GHG emissions, with effects on the management of relations with the key stakeholders. The ability to develop and implement strategies to adapt the business model to a low carbon scenario, as well as the capacity to communicate these in a transparent manner provides an opportunity to improve stakeholder perceptions. As already mentioned, Eni’s commitment to comprehensive and transparent reporting on climate change issues is confirmed by its participation in the TCFD proceedings and its recognition as a leading company in the CDP Climate Change. Physical risks. Increasingly intense extreme/chronic climate phenomena in the medium to long term could cause damage to plants and infrastructure, resulting in an interruption of industrial activities and increased recovery and maintenance costs. With regard to extreme phenomena, such as hurricanes or typhoons, Eni’s current portfolio of assets, designed in accordance with current regulations to withstand extreme environmental conditions, has a geographical distribution that does not result in concentrations of risk. The vulnerability of Eni assets to more gradual phenomena, such as rising sea levels or coastal erosion, is limited and it is therefore possible to envision and implement preventive mitigation measures to counter them. STRATEGY AND OBJECTIVES In relation to the risks and opportunities described above, Eni has defined a clear decarbonization strategy, integrated in its business model, that is developed in short/medium/long-term actions. Eni is committed in the implementation of its scientific and technological research activities (R&D) to achieve maximum efficiency in the decarbonization process and find innovative solutions to facilitate the energy transition. In the short-term, Eni’s strategy is based on the following drivers: - Efficiency increase and direct GHG emissions reduction of operated activities: the objective for 2025 is to reduce upstream emission intensity by 43% compared to 2014 by eliminating process flaring, cutting fugitive methane emissions and implementing energy efficiency measures. This objective will contribute to the target of improving the operating efficiency index by 2% a year by 2021 compared to 2014; it will be pursued by all Eni business units through energy efficiency initiatives; (5) International Energy Agency - Sustainable Development Scenario in the World Energy Outlook 2018. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018110 - low carbon and resilient Oil & Gas portfolio: Eni’s hydrocarbon portfolio has a high incidence of natural gas (>50%)6, a bridge to a low-emission future. It is also characterized by conventional projects developed in stages. The main upstream projects being executed, which account for about 45% of the total development investments in the sector in the 2019-2022 period, have a mean portfolio breakeven point at a Brent price of $25 per barrel, and are therefore resilient even in low carbon scenarios. - development of renewables and green business: the promotion of renewables aims at reaching an installed electricity generation capacity equal to about 5 GW by 2025. In the green business sector, stage two of the Venice bio-refinery is expected to be completed by 2021, resulting in an increase in capacity to 560 ktons/year (360 ktons/year at present) and the start-up of the Gela biorefinery, with a capacity of up to 720 ktons/year, is scheduled in early 2019. The consolidation in Green Chemistry is continuing and in 2018 it saw the acquisition of the organic business of the Mossi & Ghisolfi Group and the development of recycling and recovery projects. In the medium term, Eni aims to achieve the net zero carbon footprint on direct emissions of upstream activities valued (on an equity basis) by 2030, maximizing decarbonization initiatives and developing forestry projects to offset residual emissions. An important role will also be played by the implementation of solutions allowing the capture, storage and reuse of CO2. As a further decarbonization driver, Eni intends to develop circular economy initiatives aimed at enhancing waste and biomass to extract new energy, new products or materials and to give new life to decommissioned or reclaimed assets. Overall spending in the four-year period 2019-22 for decarbonization, the circular economy and renewables is approximately €3.6 billion including scientific and technological research activities designed to support these issues. METRICS AND COMMENTS As part of its decarbonization strategy, Eni has adopted indicators that illustrate the progress achieved so far in the reduction of GHG emissions into the atmosphere, the use and consumption of energy from primary sources and the production of energy from renewables. With specific reference to emission rates, calculated on data 100% of the operated asset for which Eni has set strategic objectives, an overview of the results obtained in 2018 compared to the set targets is provided below. Reduction of the upstream GHG emission intensity index by 43% by 2025 vs. 2014: the upstream GHG intensity index, expressed as the ratio between direct emissions7 in tonnes of CO2eq and thousands of barrels of oil equivalent, recorded a 6% decrease in 2018 compared to 2017, reaching 21.44 tCO2eq/kboe. This is a 20% reduction compared to 2014, which is in line with the 2025 reduction target. The improvement in the index in 2018 is mainly due to the reduction in flaring emissions, the contribution to production of the gas fields in Egypt (Zohr) and Indonesia (Jangkrik) and the return to full operation in Norway (Goliat). Overall, these activities have a lower emission intensity comapared to the portfolio average. Zero process gas flaring by 2025: the volume of hydrocarbons sent for process flaring in 2018 was equal to 1.4 billion Sm3, a decrease of 9% compared to 2017 (1.6 billion Sm3), mainly as a result of “zero flaring” achieved in Turkmenistan (Burun field). Through the measures implemented, the volume of hydrocarbons sent for process flaring was reduced by 16% compared to 2014, in line with the goal of zero process flaring by 2025. In 2018, Eni invested €39 million in flaring-down projects, especially in Nigeria and Libya. Reduction of upstream fugitive methane emissions by 80% by 2025 vs. 2014: in 2018, upstream fugitive methane emissions were 38.8 kton CH4 (-66% vs. 2014) and were unchanged compared to 2017 yet overall in line with the target. In this area, monitoring and maintenance campaigns (Leak Detection And Repair - LDAR) not only in the upstream sector, but also in the mid-downstream sector (Sergaz), with a 6% reduction in total Eni fugitive methane emissions compared to 2017. Average improvement of 2% per year at 2021 compared to the 2014 operating efficiency index: the target extends the GHG reduction objectives (scope 1 and scope 2) to all business areas with the goal of improving the operating efficiency index by 2% a year8. This objective refers to the overall Eni index, maintaining the appropriate flexibility in the trends of the individual businesses. In 2018, the index stood at 33.90 tonCO2eq/kboe, down 5.9% from 2017 (36.01 tonCO2eq/kboe). This reduction already makes it possible to achieve the 2021 target, but Eni is nonetheless set on pursuing an improvement of at least 2% per annum in coming years as well. In addition to the upstream results already mentioned, this reduction was also made possible by a reduction in the emission intensity of refineries even with an increase in the performance index of EniPower. In 2018, Eni invested about €10 million in energy efficiency projects, which, once in full operation, will yield energy savings of 313 ktoe/year, amounting to a reduction in emissions of around 0.8 million tonnes of CO2eq. In 2018, GHG direct emissions, calculated on all Eni activities, amounted to 43.35 million tonCO2eq (figure for 100% operated assets) and were stable (+0.5%) compared to 2017, while compared to 2010 they decreased by 26%. Flaring emissions decreased by 8% compared to the previous year, also as a result of emergency flaring containment measures, while venting emissions are in line with 2017. In 2018, electricity produced from photovoltaic grew by 20% YOY (19.3 vs. 16.1 GWh in 2017), while the production of biofuels stood at 219 thousand tonnes, up 6% YOY. For 2018, Eni’s economic investment in scientific research and technological development amounted to €197.2 million, of which €74 million was spent on investments regarding the Path of Decarbonization. Energy transition, biorefining, green chemistry, renewable sources, emissions’ reduction and energy efficiency were the main areas targeted by these investments. (6) Percentage of gas on total equity hydrocarbon resources 3P+ Contingent at 31/12/2018. (7) The GHG emissions from methane venting have been revised following the refinement of the estimation methodology, in line with international methodologies developed thanks to the CCMP OGMP Partnership. Therefore, the historical series of this emission category has been revised in order to ensure the consistency of the performance indices with respect to the reduction targets of the GHGs communicated by Eni. (8) It expresses the GHG emissions intensity (scope 1 and scope 2 calculated on an operatorship basis expressed in tonCO2eq and which consider the contributions of CO2, CH4 e N2O) of Eni’s main industrial productions compared to operated production (converted by homogeneity into barrels of oil equivalent using the Eni average conversion factors published in the Fact Book) in the individual businesses of reference, thus measuring their degree of operating efficiency in a decarbonization scenario. Scope 1 emissions are direct emissions from the Company’s own assets. Scope 2 indirect emissions relate to the generation of electricity, steam and heat purchased from third parties. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION111 2018 2017 2016 Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities 43.35 33.89 6.26 1.08 2.12 28.15 24.41 3.07 0.48 0.19 43.15 33.03 6.83 1.14 2.15 28.30 42.15 24.05 32.39 3.37 0.66 0.23 5.40 2.01 2.35 27.76 24.12 2.49 0.95 0.19 Key Performance Indicators Direct GHG emissions (Scope 1)(a) (million tonnes CO2eq) of which: CO2eq from combustion and process of which: CO2eq from flaring of which: CO2eq from methane fugitive emissions of which: CO2eq from venting Carbon efficiency index GHG emissions/100% operated hydrocarbon gross production (UPS) GHG emissions/Equivalent electricity produced (EniPower) GHG emissions/Refinery throughputs UPS methane fugitive emissions Volumes of hydrocarbon sent to flaring of which: sent to process flaring Indirect GHG emissions (Scope 2) Primary sources consumption(b) Primary energy purchased from other companies Electricity produced from photovoltaic(c) Energy consumption from production activities/100% operated hydrocarbon gross production (UPS) Net consumption of primary resources / Electricity produced (EniPower) (tonnes CO2eq/kboe) 33.90 46.32 36.01 51.51 38.26 51.89 21.44 20.91 22.75 24.04 23.56 22.29 (gCO2eq/kWheq) (tonnes CO2eq/kt) (ktonnes CH4) (billion Sm3) (milllion tonnes CO2eq) (Mtoe) (GWh) (GJ/toe) 402 253 38.8 1.9 1.4 0.67 13.0 0.4 19.3 1.42 407 253 15 1.1 0.6 0.56 9.4 0.4 19.2 n.a. 395 258 38.8 2.3 1.6 0.65 13.0 0.4 16.1 1.49 398 258 19.4 1.3 0.6 0.54 9.1 0.3 16.1 n.a. 398 278 72.6 1.9 1.5 0.71 12.5 0.4 13.5 1.71 (toe/MWheq) 0.17 0.17 0.16 0.16 0.16 Energy Intensity Index (refineries) (%) 112.2 112.2 109.2 109.2 101.7 R&D expenditures of which: related to decarbonization First patent filing applications of which: filed on renewable sources Production of biofuels Capacity of biorefinery (€ million) (number) (ktonnes) (ktonnes/year) 197.2 74 43 13 219 360 185 72 27 11 206 360 (a) The GHG emissions from methane venting have been revised following the refinement of the estimation methodology, in line with international methodologies developed thanks to the CCMP OGMP Partnership. Therefore, the historical series of this emission category has been revised in order to ensure the consistency of the performance indices with respect to the reduction targets of the GHGs communicated by Eni. (b) The figure differs from the data of the last year as the reporting method was refined. (c) Unlike the NFI 2017, where the data referred only to EniPower, the data shown relates to the entire Eni perimeter. 402 278 30.3 1.1 0.8 0.58 8.8 0.4 13.5 n.a. 0.16 101.7 161 63 40 12 181 360 CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018112 OPERATIONAL EXCELLENCE MODEL The operational excellence model lies in the constant commitment to minimizing risks and creating opportunities along the whole cycle of activities by enhancing people, safeguarding health and safety, protecting the environment, ensuring respect for and promoting human rights and paying the utmost attention to transparency and the fight against corruption. People Eni’s business model is based on internal skills, an asset that is built up over time and with dedication and which increases its value in the long-term. In the coming years, Eni will continue to be engaged in a crucial transformation process that will see the development of new strategic guidelines – starting with the circular economy and the activities supporting decarbonization – alongside its traditional activities, which are currently in transition. In doing so, it will seize all the opportunities offered by Digital Transformation. Clearly, this will call for a continued effort to develop internal skills in order to ensure that these are constantly aligned with new business needs. A culture of plurality and the development of people. Eni operates on an international scale. Its people are citizens of the world who live alongside the communities with which they work, which is why plurality is an essential value. Diversity is a resource and a source of value that must be safeguarded and promoted both within the Company and in all relationships with its stakeholders. For this reason, Eni promotes the development of local people through selection and professional development processes that ensure uniform management at a global level. With regard to gender diversity, Eni pays particular attention to the choice of members of the Boards of Directors of its subsidiaries, to the promotion of initiatives to attract female talents at a national and international level, and to the development of managerial and professional growth paths for the women in the Company. In this area, Eni takes part in national and international initiatives (Inspiring Girls Project9, the “Manifesto for female employment”10 of Valore D, Consorzio Elis – Sistema Scuola Impresa, WEF11 and ERT12) with the aim of constantly enriching its processes and operating practices to achieve gender parity. Eni also regularly monitors the pay gap between the female and male population for the same position and seniority and has found that wages are substantially aligned. Pursuant to International Labour Organization (ILO) standards, Eni also carries out statistical analyses on the remuneration of local employees. The results show that the minimum levels set by Eni are significantly higher than the local market minimums. Eni has also implemented managerial development and excellence pathways aimed at the core professional areas (dual career), which it supports through training activities, mobility initiatives, job rotation and development tools. In particular, mobility initiatives are offered to the managerial and non-managerial population, in order to maximise opportunities for cross-cutting enhancement and growth. Eni uses various assessment tools to support these development pathways, including the annual review and the performance and feedback process with a focus on senior managers, middle managers and young graduates. In 2018, 90% of the target population was covered by the performance assessment process and 95% by the annual review process. Training. Training is given to Eni people around the world to create shared values and a common culture. Considering its people’s skills which are essential to operational excellence, Eni plans and implements training courses for delivery in a universal and cross- cutting manner, projects for professional families and specialist initiatives for strategic activities with a high technical content. Training needs are mapped and evaluated annually according to specific needs. With reference to the global scenario and the ongoing digitalization process, the development and enhancement of digital skills are among the top priorities; in November 2018, the “Digital Transformation Center” platform was launched to make available the new “digital” skills needed to develop and use innovative technological solutions in operating processes. In addition, virtual reality training is being tested to simulate dangerous situations in controlled environments using the “learn-by-doing” approach. Finally, Eni has provided for training courses available to all on strategic issues, such as the Energy Transition and climate change. Industrial relations. Eni maintains ongoing relations with national and international trade union organizations for the conclusion and renewal of agreements with its counterparts. At international level, the model of trade union relations is based on three pillars: two in Europe (the European Works Council and the European Observatory for the Health and Safety of Workers in Eni) and a global one, namely the Global Framework Agreement on International Industrial Relations and Corporate Social Responsibility13. With regard to this agreement, the second annual meeting was held on December 5, 2018 in Montreux. In addition to IndustriALL Global Union14, it was attended by the main Italian trade unions, the members of the Select Committee of the European Works Council15 and a delegation of workers’ representatives from Eni’s businesses in Congo, Ghana, Mozambique and Nigeria. During the meeting, Eni’s 2018-2021 Strategic Plan was presented, along with a focus on employment, (9) International project against stereotypes of women. (10) Program document aimed at enhancing female talent in the Company and promoted by Valore D with the patronage of the Italian presidency of the G7 and the Department for Equal Opportunities of the Italian Presidency of the Council of Ministers. (11) World Economic Forum. (12) European Round Table. (13) Second meeting since the signing of the Global Framework Agreement of July 7, 2016. (14) Federation, founded in Copenhagen in 2012, representing more than 50 million workers in more than 140 Countries. (15) The European Works Council is a body representing workers provided for by European Directive 94/45/EC to promote the transnational information and consultation of workers in undertakings. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION113 the main HSE performance indicators and initiatives, Eni’s sustainability approach and the activities of the Eni Foundation. Parenthood, Welfare and Inclusion. Eni has continued with its strategy of developing policies in favour of protecting parenthood and the family, also in international mobility, by adopting in 2017, in all the Countries in which Eni operates, concrete policies to support maternity and paternity aimed at guaranteeing, in addition to the international standards of the ILO Convention, a 10-day period of fully paid leave for both parents. In 2018, the smart working pathway for new parents continued and was opened to colleagues with pathologies and in 2019, in Italy and depending on the positions held, a further progressive extension of this work scheme will be assessed. In 2018, Eni’s activities relating to services to people consolidated and reinforced its initiatives in support of families, with particular attention to services to employees who are caregivers of elderly or non-self-sufficient people, as well as those aimed at promoting health protection through the consolidation and extension of health prevention programs. With regard to welfare in Italy, the Flexible Benefit16 scheme has been in place at Eni since 2017 and in 2018 Eni enhanced its supplementary health care offering to all non-managerial employees, guaranteeing increased reimbursements and the recognition of new reimbursable services as required in the “Welfare Protocol” signed on July 4, 2017 with the relevant Trade Unions. At the level of international labour law, a mapping of the ratifications of the main ILO Conventions in the Countries where Eni is present was carried out in 2018. This activity is further proof of the importance of, and Eni’s commitment to, compliance with the fundamental principles set out in the ILO Conventions and is aimed at analyzing the status of ratifications in the Countries in which Eni operates. Health. Eni considers health protection an essential requirement and promotes the physical, psychological and social well-being of Eni’s people, their families and the communities of the Countries in which it operates. The extreme variability of business contexts requires a constant effort to update health risk matrices and makes it particularly challenging to guarantee health at every stage of the business cycle. To rise to this challenge, Eni has developed an operational platform that ensures services to its people, covering occupational health, industrial hygiene, traveller health, healthcare and medical emergency, as well as health promotion initiatives for Eni people and the communities in which it operates. In 2018, all of the Group companies continued the implementation of health management systems with the objective of promoting and maintaining the health and well-being of Eni people and ensuring adequate risk management in the workplace. METRICS AND COMMENTS Overall employment amounts to 30,950 people, of whom 20,576 in Italy (66.5% of Eni employees) and 10,374 abroad (33.5% of Eni employees). In 2018, employment at global level decreased by 1,245 people compared to 2017, equal to -3.9%, with an increase in Italy (+108) and a reduction abroad (-1,353 employees) due mainly to corporate reorganizations17. Overall, in 2018, 1,728 hires were made, of which 1,264 with permanent contracts. Of these, 29.1% covered female staff and about 81% regarded employees under 40 years of age. Of the total number of hires, approximately 42% were in the upstream business area (total 361, of which 186 were with permanent contracts and 175 with fixed-term contracts), 25% in the R&M&C area and 33% in the Gas & Power and Support Function areas. In all, 1,778 contracts were terminated, 1,270 of which were permanent contracts18, and 25% regarded female employees. In 2018, 28.3% of the permanent contracts terminated involved employees under the age of 40. In 2018, the percentage of women in positions of responsibility rose to 25.28%, compared to 24.86% in 2017. Similarly, there was an upward trend in the percentage of women on the management and control bodies of Eni companies, reaching 33% and 39%, respectively, in 2018. In Italy, 868 people were hired, 691 of whom with permanent contracts (28.9% women, up 7% compared to 2017). The number of personnel employed increased, particularly for the younger age group (18-24), mainly due to the hires at industrial sites in Italy including Viggiano, Livorno, Sannazzaro, Mantova and Taranto. In 2018, the number of terminations in Italy rose (+951 employees), of which 640 permanent contracts (of which 21.7% were women). In 2018, 860 hires were made abroad, of which 573 with permanent contracts (of which 29.3% women) with 72.1% of employees under the age of 40. Of the hires abroad, more than 60% refer to the upstream business area (Mexico, Indonesia, Norway, and the UK) and G&P business area (France, Hungary and the UK), with the aim of developing and promoting new initiatives, as well as of supporting turnover. As regards terminations, 827 contracts were terminated, of which 630 permanent contracts. Of these, 43.3% regarded employees under the age of 40, and 28.3% were women. At year end, the balance between hires and terminations abroad was +33 (+860 -827) and was basically the result of the growth of the G&P retail business in France, the consolidation of R&M&C and upstream activities in Mexico and Indonesia, the re-dimensioning of activities in the gas business in Hungary and the release of local and international employees in upstream activities in Nigeria, Pakistan and the Americas. A reduction in local employees was registered outside of Italy (-1,438 compared with the previous year), resulting in a drop in the percentage of local staff out of total employment abroad from 85.4% in 2017 to 82.6% in 2018. A total of 1,802 expatriates (of whom 1,261 are Italian) work abroad, slightly up from 2017 (+27 Italians). The average age of Eni people in the world is 45.4 years (46.7 in Italy and 42.9 abroad; +0.1 years compared to 2017). The average age is 49.3 years (50.3 in Italy and 46.9 abroad) for senior and middle managers, 44.3 years (46 in Italy and 41 abroad) for white collar workers, and 41.3 years (40.5 in Italy and 42.4 abroad) for blue collar workers. In 2018, thanks also to the “digital learning” initiatives delivered through the “Digital Transformation Center”, there was a significant 5.2% increase in training hours compared to 2017. In the field of health, the number of health services sustained19 by Eni in 2018 was 473,437, of which 320,933 for employees, 66,327 for family members, 68,796 for contractors and 17,381 for others (e.g., visitors and external patients). The number of participants in health promotion initiatives19 in 2018 was 170,431, of whom 75,938 were employees, 46,930 contractors and 47,563 family members. (16) Initiative that enables a share of the performance bonus to be converted into goods and services, benefiting from the tax and contributions savings. (17) Of note are the sale of Tigaz and the deconsolidation of Eni Norge. (18) Of which about 50% for retirement and 40% for resignation. (19) The health data consider the companies significant from the point of view of health impacts, with two points of view: the data only for the fully consolidated entities as required by the Decree (data relating to occupational disease claims) and the data including companies under joint operation or joint control or associates in which Eni has control of operations (for all other data). CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018114 As concerns occupational illnesses, claims fell during 2018 from 120 to 81, with an overall reduction of 33%, due to the reduction of illnesses reported, both by former employees (from 108 to 71 claims) and current employees (from 12 to 10 claims). Of the 81 occupational disease claims submitted in 2018, 12 were submitted by heirs (11 relating to former employees and 1 to an employee). Key Performance Indicators Employees as of December, 31st(a) (number) Women Italy Abroad Africa Americas Asia Australia and Oceania Rest of Europe Employees aged 18-24 Employees aged 25-39 Employees aged 40-54 Employees aged over 55 Local employees abroad Employees by professional category: Senior managers Middle managers White collars Blue collars Employees by educational qualification: Degree Secondary school diploma Less than secondary school diploma Employees with permanent contracts(b) Employees with fixed term contracts(b) Employees with full-time contracts Employees with part-time contracts(c) Number of new hires with permanent contracts Number of terminations of permanent contracts Local senior managers & middle managers abroad Seniority Senior managers Middle managers White collars Blue collars Presence of women on the Boards of Directors Presence of women on the Boards of Statutory Auditors(d) Training hours Average hours of training per employee by employee category Senior managers Middle managers White collars Blue collars Employees covered by collective bargaining Italy Abroad Occupational illnesses allegations received Employees Previously employed 2018 30,950 7,307 20,576 10,374 3,374 1,257 2,505 90 3,148 437 9,224 14,058 7,231 8,572 1,008 9,147 15,839 4,956 14,603 13,348 2,999 30,183 767 30,390 560 1,264 1,270 16.70 22.12 20.02 17.03 13.05 2017 32,195 7,580 20,468 11,727 3,303 1,216 2,418 114 4,676 364 9,761 15,022 7,048 10,010 990 9,043 16,600 5,562 14,802 14,300 3,093 31,609 586 31,612 583 992 1,312 15.68 22.08 20.01 17.02 13.05 32 37 1,111,112 34.2 31.7 35.7 34.5 31.6 81.96 100 44.54 120 12 108 2016 32,733 7,607 20,476 12,257 3,546 1,236 2,523 113 4,839 289 10,622 15,281 6,541 10,377 1,000 9,135 16,842 5,756 14,655 14,082 3,996 32,299 434 32,139 594 663 1,417 16.06 22.02 19.08 16.08 13.01 27 37 930,345 28.1 27.6 23.9 30.6 27.5 82.48 100 47.46 133 14 119 (%) (years) (%) (number) 33 39 1,169,385 36.9 41.7 37.2 36.2 37.7 80.89 100 35.33 81 10 71 (%) (number) (a) The data differ from those published in the Annual Report (see inside cover) because they include only fully consolidated companies. (b) The subdivision of fixed-term/permanent contracts does not vary significantly either by gender or by geographical area except for China and Mozambique where it is common practice to insert local resources for fixed term and then stabilize them over a period of 1-3 years. (c) There is a higher percentage of women (7% of total women) on part-time contracts, compared to men (0.1% of total men). (d) Outside of Italy, only the companies which a control body similar to the Italian Board of Statutory Auditors were considered. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION115 developing and implementing a specific management system, in line with international standards, and monitoring it with dedicated audits. In terms of emergency preparedness and response, in addition to continuous drills and monitoring of results, particular attention is paid to the development of alert systems, the timeliness of information communication via simplified flows and research on natural risk scenarios which could interact with its business. The Company’s main safety objectives concern: (i) the Safety Culture Program (SCP), which monitors the level of proactivity through preventive safety management aspects; (ii) the revision of process safety standards in line with international best practices; and (iii) the safety culture, with the launch of a new campaign for office safety (“Safety starts @ office”). In 2018, the Severity Incident Rate (SIR), an Eni weighted internal index that measures the level of incident severity, was consolidated. In particular, this indicator is used in the short-term incentive plan of the CEO and senior managers with strategic responsibilities to focus Eni’s commitment on reducing the most serious accidents. METRICS AND COMMENTS In 2018, the total recordable injuries rate (TRIR) of the workforce increased by 6% compared to 2017. The worsening was determined by the employees’ indicator (due to an increase in accidents), while the contractors’ index remained stable. 4 fatal accidents occurred to upstream contractors: 1 in Nigeria as a result of crushing by a manoeuvring vehicle, 1 in Algeria as a result of burns, and 2 in Egypt for falls from a height. The indicator for injuries at work with serious consequences was affected by two events: one in Alaska (upstream contractor who suffered a serious injury to his right leg) and the other in Egypt (contractor who fell from a height). In Italy, the number of total recordable accidents in 2018 increased (40 events vs. 38 in 2017), but the total recordable injury rate (TRIR) improved by 3%; however, the number of accidents abroad increased (76 events vs. 63 in 2017) and the total recordable injury rate worsened by 12%. Safety Eni believes that the safety of people is a fundamental value to be shared among employees, contractors and local communities and an essential part of its operations. For this purpose, Eni takes all the necessary steps to eliminate the occurrence of accidents, including: risk assessment and management organizational models, training plans, skills development and promotion of a safety culture. In 2018, to underscore the importance of maintaining correct and safe behaviour not only in the workplace, the campaign “Safety starts @ home” (aimed at employees) was launched through the Company intranet, consisting of 10 video clips to promote safety at home starting from the “Safety Golden Rules” (the 10 golden rules for safety at work, mandatory at Eni from 2018) and the initiative “I live safe” (for employees and third parties), a day dedicated to research and the implementation of practical tools for building healthy and safe habits even outside work through tangible and measurable actions (with companies) to be adopted for the entire duration of contracts. Meetings were also organised to raise workers’ awareness of the lessons learned relating to accidents that occurred in the Company, which in 2018 were mainly related to work at height and the handling of loads. In particular, as regards the management of contractors at Eni’s industrial sites, in 2018 control activities in the field were further strengthened through the more than 120 members of the Safety Competence Center20 assigned to the coordination and supervision of the safety of work sites and contract works. More than 2,300 companies, accounting for 70% of Eni’s HSE-critical suppliers in Italy, are constantly called upon to raise awareness to build their safety culture and are monitored and evaluated through tools set out and implemented by the Safety Competence Center. Non-conformities found are immediately redressed with corrective actions and good practices are recognized, shared and disseminated. In 2018, the first trials of the application of the Safety Competence Center’s operational methodologies were carried out abroad (in particular in Tunisia and Angola), with positive results that suggest a systematic implementation in the coming years. Eni has also intensified its focus on process safety culture21, Key Performance Indicators Total Recordable Injury Rate (TRIR) (total recordable injuries/hours worked) x 1.000.000 Employees Contractors Number of fatalities as a result of work- related injury Employees Contractors (number) High-consequence work-related injuries rate (excluding fatalities) (high-consequence work-related injuries/hours worked) x 1.000.000 Employees Contractors Near miss Worked hours Employees Contractors (number) (million of hours) 2018 2017 2016 Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities 0.35 0.37 0.34 4 0 4 0.01 0.00 0.01 1,431 330.6 91.6 239.0 0.41 0.42 0.41 1 0 1 0.01 0.00 0.01 1,128 190.9 57.5 133.4 0.33 0.30 0.34 1 0 1 0.00 0.01 0.00 1,550 306.3 93.1 213.3 0.45 0.44 0.46 0 0 0 0.01 0.02 0.00 1,223 174.2 59.4 114.8 0.35 0.36 0.35 2 0 2 0.01 0.01 0.01 1,643 276.9 93.7 183.2 0.38 0.41 0.36 1 0 1 0.01 0.02 0.01 1,270 168.9 61.4 107.5 (20) Eni Center of Excellence on Safety, which supports Eni’s industrial sites in Italy and abroad in the coordination and supervision of contract works. (21) Process Safety aims at preventing and controlling, throughout the life cycle of its assets, uncontrolled releases of hazardous substances that can become major accidents, protecting the safety of people, environment, productivity, company assets and reputation. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 116 Respect for the environment Eni operates in very different geographical contexts, which require specific assessments of the environmental aspects, and is committed to strengthening control and monitoring of its activities in order to mitigate their impacts on the environment by adopting constantly up-to-date international technical and management good practices and Best Available Technology. Particular attention is paid to the efficient use of natural resources, like water; to reducing operational oil spills and oil spills caused by sabotage; to managing waste through process traceability and control of the entire supply chain; to managing the interaction with biodiversity and ecosystem services, from the first exploration stages up to the end of the project cycle. The transition path towards a circular economy, in which withdrawal of resources from the environment and waste disposal are minimized, represents a challenge and an opportunity for Eni, in terms of both profitability and improvement in environmental performances. This path involves various areas: (i) update of business models, producing renewable energy and/or using recycled or renewable material in production activities (Energy Solutions, Green Refinery and Green Chemistry); (ii) energy and water efficiency programs in all sectors of the business, as well as flaring down projects and projects to reduce methane losses with resulting savings in natural gas; (iii) management of assets to be decommissioned, through conversion, requalification, recovery and sustainable reclamation projects; (iv) management tools, such as green-c procurement and ICT solutions. Eni promotes efficient water management, especially in water- stressed areas, where in 2018 initiatives to reduce fresh water withdrawals and projects in the upstream sector to give access to water to populations in areas where Eni operates continued. In Italy, Eni is committed to increasing, over the period of the four-year plan, the amount of polluted groundwater treated and reused for civil or industrial purposes, to launching initiatives and assessments for the use of poor quality water (waste water or water from polluted groundwater, as well as rainwater and desalinated sea water), replacing fresh water, and reducing the water intensity of production. At the Centro Olio Val d’Agri (COVA), a tender was launched to award a contract for the construction of a Mini Blue water plant, based on proprietary technology, to be installed with a treatment capacity of about 70 m3/h. Blue water consists in an innovative process for the treatment of production water, which leads to their reuse for industrial purposes. Only a small proportion of Eni’s water withdrawals come from freshwater sources (less than 7%). The analysis of river basin stress levels22 and in-depth studies carried out at local level have shown that freshwater samples from water-stressed areas account for less than 2% of Eni’s total water withdrawals. In water-stressed areas, Eni adopts specific water management plans to reduce consumption. For example, at the Brindisi site, a collaboration agreement was signed in 2018 between EniPower and Syndial for the reuse of groundwater to reduce water withdrawals. Considering the potential risks arising from possible water crises, as noted by the annual survey conducted by the WEF23 and the growing demand for information by stakeholders, for the first time, in 2018, a public response was provided to the CDP water to increase transparency on these issues. Eni is committed every day to managing the risk of oil spills in Italy and abroad through increasingly well-integrated actions in all areas, from the administrative level to the technical areas of prevention, control and quality/speed/effectiveness of intervention. In 2018, the installation of the e-vpms® (Eni Vibroacustic Pipeline Monitoring System) and SSPS (Safety Security Pipeline System) tools for the detection of spills due to events, whether operational or caused by sabotage, was completed on the Italian pipeline network and on part of those in Nigeria. To further increase preventive effectiveness, in 2019 an upgrade will be installed on two pilot pipelines to detect activities in the vicinity of the pipeline (excavations, vehicles, etc.) before a sabotage on the pipeline. If the results are positive, it will be extended to all finished product pipelines in Italy and gradually to other Company realities. In 2018, a sabotage was detected in Egypt (JV Agiba), which will be monitored based on the experience gained in Italy and Nigeria, where intense monitoring activities continue through direct surveillance, thanks also to the support of the local communities, the use of aircraft and drones, as well as the installation of mechanical protections. Finally, in terms of preparedness and response, the risk analysis of the areas crossed by pipelines was completed in Italy, identifying the most sensitive points at which to set up potential containment actions in advance. At the same time, Eni will also work on the experimentation/application of techniques for managing impacts in the case of spills to improve the speed, quality and effectiveness of intervention and surveillance. Eni’s commitment to Biodiversity and Ecosystem Services (BES) is an integral part of the Integrated HSE Management System, confirming its awareness of the risks for the natural environment resulting from its sites and activities. Eni’s BES management model is aligned with the strategic objectives of the Convention on Biological Diversity (CBD) and ensures that the reciprocal relationships between environmental and social aspects are correctly identified and managed from the earliest project stages. The biodiversity risk exposure of the global portfolio of the upstream sector is periodically assessed by mapping the geographical proximity to protected areas and areas important for biodiversity conservation. This mapping allows identifying priority sites where to take action with more detailed surveys to characterize the operational and environmental context and assess all potential impacts that are then mitigated through Action Plans, thus ensuring effective management of risk exposure. Eni’s BES management model is described in the BES Policy approved by the CEO and published in 2018 on the Eni website24. (22) Water-stressed areas: areas with a Baseline Water Stress value over 40%. The indicator, defined by the World Resources Institute (WRI - www.wri.org), measures the exploitation of freshwater sources and indicates a stressful situation if withdrawals from a given river basin are greater than 40% of its renewable supply. (23) The Global Risks Landscape 2018 “What is the impact and likelihood of global risks?”. (24) https://www.eni.com/docs/en_IT/enicom/sustainability/Eni-Biodiversity-and-Ecosystem-Services-Policy.pdf CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION117 METRICS AND COMMENTS In 2018, the downward trend (-2% vs. 2017) in freshwater withdrawals continued, particularly thanks to the commissioning of new steam generators at the Porto Marghera petrochemical plant to replace steam/electric power generation units, with a reduction in the amount of freshwater used in cooling cycles. More than 75% of freshwater withdrawals are accounted for by the R&M&C sector, while only 8% relate to the E&P sector. The percentage on freshwater reuse has reached 87%. In the E&P sector, production water re-injected has reached 60%, mainly as a result of the good performance maintained by the fields in Egypt and Ecuador. The number of barrels spilled in operational oil spills has decreased compared with 2017. Two major incidents were recorded, one at the Livorno refinery (spillage from a tank caused by overfilling) and the other at the Sarroch chemical plant in Sardinia (discovery of soil with hydrocarbon product and water at a road crossing), both with spills of about 500 barrels of product. The year 2018 saw a reduction in the number of incidents by sabotage, while the volume spilled increased by 14%; spills were related solely to the E&P activities in Nigeria and Egypt. The barrels spilled in chemical spills relate to upstream activities and Versalis. Waste from production activities generated by Eni in 2018 increased compared to 2017, due in particular to the contribution of non-hazardous waste (88% of the total), while hazardous waste recorded a decrease. The increase is related to the E&P sectors (in particular, due to the ramp-up of the Zohr project in Egypt and the return to full operation of the Val d’Agri Oil Center, which was also affected by the increased production of aquifer water disposed of as waste) and R&M&C (following the general shutdown of the Taranto refinery and the disposals following flooding that occurred in 2017 at the Livorno refinery). The amount of recovered/recycled waste has increased since 2017, reaching almost 40% of total waste disposed25. In 2018, a total of 4.3 million tonnes of waste was generated by reclamation activities (of which 4 million tonnes by Syndial), of which about 64% was groundwater. In 2018, €374 million was spent on soil and groundwater reclamation. The increase in SOX emissions compared to 2017 is due in particular to the updating of the gas composition at some upstream sites, thus resulting in an increased percentage of H2S in the stream sent to the flare. In 2018, biodiversity risk exposure was assessed on all international and national concessions under development and/or exploitation in the upstream sector26 (operated and joint ventures), in order to identify those that affect (even partially) protected areas27 and/or key biodiversity areas (KBAs)28. A detailed analysis of these concessions, relating to the actual position of the production sites within them (plants and/or infrastructures), has shown that in 27 concessions, located in 6 Countries (United Kingdom, United States, Egypt29, Nigeria, Pakistan and Italy), they are within one or more protected areas and/or KBAs; while in another 31 concessions, located in 7 Countries (United States, Ecuador, Tunisia, Congo, Nigeria, Pakistan and Italy), the production sites are located outside, in areas adjacent to one or more protected areas or KBAs. Among the protected areas and/or KBAs that overlap with production sites, 2 are included in the Ramsar List30, 3 are IUCN protected areas31, 7 are other nationally designated protected areas, 15 fall under the Natura 2000 classification, while 12 are identified as KBAs. Of these areas, 26 are found in terrestrial ecosystems, 11 in marine ecosystems and 2 in mixed ecosystems (terrestrial and marine). No production site overlaps with World Heritage sites (WHS32). Instead, among the production sites located in areas adjacent to protected areas or KBAs, only one is located near a WHS natural heritage site (Mount Etna)33. The other areas concerned are: 2 are included in the Ramsar List, 18 are IUCN protected areas, 4 are other nationally designated protected areas, 35 fall under the Natura 2000 classification, while 16 are identified as KBAs. Of these sites, 67 are found in terrestrial ecosystems, 6 in marine ecosystems and 3 in mixed ecosystems (terrestrial and marine). (25) Specifically, in 2018, 16% of hazardous waste disposed of by Eni was recovered/recycled, 12% was subjected to chemical/physical treatment, 11% was incinerated, 3% was disposed of in waste dumps and the remaining 58% was sent for other types of disposal (including transfer to temporary storage plants prior to final disposal). With regard to non-hazardous waste, 42% was recovered/recycled, 1% was subjected to chemical/physical treatment, 0.3% was incinerated, 5% was disposed of in waste dumps and the remaining 51.7% was sent for other types of disposal (including transfer to temporary storage plants prior to final disposal). (26) Source: Company database, June 2018. (27) Source: World Database of Protected Areas, December 2018. (28) Source: World Database of Key Biodiversity Areas, June 2018. KBAs (Key Biodiversity Areas) are sites that contribute significantly to the global persistence of biodiversity, on land, in freshwater or in the seas. These are identified through national processes by local stakeholders using a set of globally agreed scientific criteria. To date, KBAs consist of two subsets: 1) Important Bird and Biodiversity Areas; 2) Alliance for Zero Extinction Sites. (29) In Egypt, 5 concessions have been assessed, of which only 1 belongs to fully consolidated entities as required by Italian Legislative Decree 254/2016; the remaining 4 are included in the “operated” reporting perimeter. (30) List of wetlands of international importance identified by the Countries that signed the Ramsar Convention in Iran in 1971 and which aims to ensure the sustainable development and conservation of biodiversity in these areas. (31) IUCN, International Union for Conservation of Nature. (32) WHS, World Heritage Site. (33) Although the Zubair field (Iraq) is not included among the fully consolidated entities or within the “operated” reporting perimeter, it is located near the Ahwar site classified as a mixed WHS site (natural and cultural). However, no operational infrastructure or activity falls within this protected area. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018118 Key Performance Indicators Total water withdrawals of which sea water of which freshwater of which freshwater from superficial water bodies of which freshwater from subsoil of which freshwater from urban net or tanker of which polluted groundwater treated at TAF(a) plants and used in the production cycle of which freshwater withdrawal from other streams of which brackish water from subsoil or superficial water bodies Fresh water reused Re-injected production water Operational oil spill Total number of oil spills (> 1 barrel) Volume of oil spill (> 1 barrel)(b) Oil spills due to sabotage (including theft) Total number of oil spills (> 1 barrel) Volume of oil spill (> 1 barrel) Chemical spill Total number of oil spills Volume of oil spill 2018 2017 2016 Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities Operated companies Fully Consolidated entities (Mm3) 1,776 1,731 1,786 1,640 1,626 1,650 104 119 72 17 5 4 7 1 88 49 34 79 20 10 4 6 16 86 59 55 1,746 1,638 106 70 17 9 4 6 1 87 45 24 1,851 1,710 129 87 23 9 3 7 12 84 58 85 1,816 1,697 117 78 20 9 3 7 2 85 42 44 724 2,217 3,323 3,049 1,231 94 102 102 158 3,277 3,236 3,236 4,682 158 4,682 34 61 1.3 0.2 1.1 31.6 6.2 13.8 0.8 17 63 1.4 0.7 0.7 55.6 8.4 21.5 1.5 15 50 0.8 0.3 0.5 30.8 6.7 13.4 0.7 24 18 0.8 0.3 0.5 56 8.9 15.9 1.4 24 18 0.6 0.2 0.4 32.1 5.5 9.2 0.7 117 81 19 6 4 7 19 87 60 72 2,665 97 3,697 34 61 2.6 0.3 2.3 53.1 16.5 23.1 1.5 (%) (number) (barrels) (number) (barrels) (number) (barrels) Total waste from production activities (million tonnes) of which hazardous waste of which non-hazardous waste NOX (nitrogen oxides) emissions SOX (sulphur oxides) emissions NMVOC (Non Methane Volatile Organic Compounds) emissions (ktonnes NO2eq) (ktonnes SO2eq) (ktonnes) TSP (Total Suspended Particulate) emissions (a) TAF: Groundwater treatment. (b) The 2017 figure was updated following the closure of some investigations after the publication of the 2017 NFI. This circumstance could also occur for the 2018 data. Human Rights Eni is committed to respecting international human rights standards, starting with the UN’s Guiding Principles on Business and Human Rights, with the aim of continuously improving its due diligence system. Human rights is one of the areas in which the Eni Sustainability and Scenarios Committee (CSS) performs consultative and advisory functions for the BoD. In 2018, the CSS examined numerous aspects that directly or indirectly concern human rights, including the analysis of the results achieved by Eni in the second edition of the Corporate Human Rights Benchmark (CHRB)34 and the draft of Eni’s Statement on Respect for Human Rights, approved by the BoD in December 2018 and drawn up with the support of the inter-functional working group on “Human Rights and Business”35. This Statement strengthens the corporate commitment previously expressed on the subject, aligning it with the main international standards on human rights and business, starting with the United Nations Guiding Principles, and also highlighting the priority areas on which this commitment is focused. During 2018, the activities of the working group continued, making it possible to identify the main areas for improvement and the actions necessary for the continuous improvement of performance. These actions have been incorporated into a specific multi-year plan that has been broken down into managerial objectives linked (34) Eni ranked first among the energy companies and seventh among all 101 companies in the different sectors analysed. (35) Created in 2017 following an event chaired by the CEO addressed to the members of the BoD, Board of Statutory Auditors and Management on the issue of Business and Human Rights. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 119 to human rights performance. In 2018, therefore, 8 out of 16 managers reporting to the CEO were assigned a target directly related to human rights. The subject of respect for human rights is integrated at various levels in Company processes and Eni monitors the risk of possible abuses with specific instruments such as, for example, the Integrated Risk Management (IRM) model, in which these issues are considered in the risk model and integrated in the risk assessment in the social, environmental, health, safety and reputation impact metrics. Following the internal awareness-raising process on human rights launched in 2016, in 2018, human rights training at Eni saw the delivery of specific e-learning courses for some functions, which expanded on the course provided in 2016-2017 to all employees. These courses, developed with the support of the Danish Institute for Human Rights, are aimed at creating a language and a common and shared culture about human rights and at improving understanding of the possible impacts of business on human rights. In 2017, Eni identified 4 areas involving the human rights considered most relevant to the activities carried out directly and those carried out by its business partners, the so-called “Salient Issues”. During 2018, these areas were shared with external stakeholders and authoritative experts: human rights (i) in the workplace36; (ii) in the supply chain; (iii) in communities; and (iv) in security operations. The promotion and protection of human rights in the supply chain is ensured through assessment activities and the application of criteria based on international standards, such as SA 8000 standards. In 2018, 20 suppliers were assessed, including 1 from Ecuador, 2 from Vietnam, 2 from Egypt and 15 from Italy. Eni is also committed to drawing up a code of conduct for suppliers37, which reaffirms the importance of respecting the key principles of sustainability in the supply chain. Further actions to counter modern forms of slavery and human trafficking and to prevent the exploitation of minerals associated with human rights violations in the supply chain are discussed respectively in the Modern Slavery Statement38 and in the Position Statement on “Conflict minerals”39. Eni is committed to preventing possible negative impacts on the human rights of individuals and host communities by providing for appropriate management measures. For this purpose, in 2018, Human Rights Impact Assessments (HRIA) were carried out in Mozambique and Angola, in addition to the follow-up to the one carried out in Myanmar in 2016, for which Eni availed itself of the support of the Danish Institute for Human Rights. A model was also developed for classifying business projects to determine the associated level of risk of social impact and the impact on human rights, based on which appropriate in-depth studies are undertaken, including the HRIAs. Eni manages its security operations in accordance with international principles, including the Voluntary Principles on Security & Human Rights. Eni has designed a coherent set of rules, processes and tools to ensure that: (i) the suppliers of security forces are selected according to human rights criteria; (ii) the contractual terms include provisions on the respect of human rights; (iii) security operators and supervisors receive adequate training; and (iv) the events considered most at risk are managed in accordance with international standards. As a complement to all the actions taken to ensure respect for human rights, since 2006 an Eni procedure has been in place, included in the Anti-Corruption Regulatory Instruments, which regulates the process of receiving, analysing and handling any whistleblowing reports, even anonymously, from employees or third parties. METRICS AND COMMENTS In 2018, the human rights training programme continued (after the massive campaign between 2016 and 2017) with specific follow-up initiatives for thematic insights that will continue in 2019 together with the campaign for the procurement professional area. In addition, the “Sustainability and Business Integration” course in English and French was made available to all Eni employees, for a total of approximately 7,100 enrollments. In 2018, e-learning courses dealt with human rights and specifically: relations with local communities (140 people), workplace (about 1,740 people) and security (207 people), aimed at different employee targets depending on the content of the training modules. Human rights & security are also regularly addressed in all training courses for security personnel, such as workshops for newly appointed Security Managers and Security Officers, and generic and specific e-learning training. Thanks also to the courses mentioned above, the staff belonging to the Security professional area trained in human rights reached 96%. In addition, since 2009 Eni has been conducting a training program for public and private security forces at its subsidiaries, which was recognized as a best practice in the 2013 joint publication Global Compact and Principles for Responsible Investment (PRI) of the United Nations. In 2018, the training session was held in Tunis and was addressed to private security operators who work at Eni’s management and operational sites. With regard to whistleblowing reports, in 2018 investigations were completed on 79 files, 3140 of which included human rights aspects, mainly concerning potential impacts on workers’ rights. Among these, 34 assertions were checked: the events reported were confirmed, at least in part, for only 9 of these, and actions were taken to mitigate and/or minimize the impacts including: (i) actions on the Internal Control and Risk Management System, relating to the implementation and strengthening of controls in place, and awareness-raising and training activities for employees; (ii) actions for suppliers and (iii) actions against employees, including disciplinary measures, in accordance with the 231 Model, the collective labour agreement and other national laws applicable. At the end of the year, 21 files were still open, 5 of which referred to human rights aspects, in particular potential impacts on workers’ rights. (36) Please refer to the section “People” on pages 112-114. (37) In 2018, a draft of the document was drawn up and a pilot campaign was launched, in Italy and abroad, which ended with a good response from suppliers. (38) In accordance with the UK Modern Slavery Act 2015. (39) In accordance with US SEC regulations. (40) All relating to companies consolidated on a line-by-line basis. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018120 Key Performance Indicators Hours of training on human rights In class Distance Employees trained on human rights(a) Security personnel trained on human rights Security personnel (professional area) trained on human rights(c) Security contracts containing clauses on human rights Whistleblowing reports(d) (assertions)(e) on human rights violations closed during the year(f), of which: Founded reports (assertions) Unfounded reports (assertions), with the adoption of corrective/improvement measures Unfounded/generic reports (assertions) (number) (%) (number) (%) 2018 10,653 164 10,489 91 73 96 90 2017 7,805 52 7,753 74 308(b) 88 88 (number) 31 (34) 29 (32) 9 9 16 3 9 20 2016 88,874 354 88,520 - 53 83 91 36 11 6 19 (a) This percentage is calculated as the ratio between the number of registered employees who have completed a course and the total number of registered employees. (b) The variations of the KPI Security resources trained on human rights, in some cases also significant, which can be detected between one year and the next, are linked to the different characteristics of the training projects and to the operating contingencies. (c) This data is a percentage of a value cumulated. (d) Whistleblowing report: it is a summary document of the investigations carried out on the whistleblowing report(s) (which may contain one or more detailed and verifiable assertions) including the summary of the investigation carried out, the results of such investigation and any identified action plan. (e) 2016 data refers to the whistleblowing reports (and not to the assertions). (f) 2016 and 2017 data include some cases related to not fully consolidated entities: - 2016: 1 unfounded report with the adoption of improvement measures; - 2017: 1 report with 1 unfounded/generic assertion. Suppliers Eni adopts qualification and selection criteria for suppliers to assess their capacity to meet Company standards in terms of ethical reliability, health, safety, environmental protection and human rights. Eni meets this commitment by promoting its own values with its suppliers and involving them in the risk prevention process. For this purpose, as part of its Procurement process, Eni: (i) subjects all its suppliers to a qualification and due diligence process to check their professionalism, technical capacity, ethical, economic and financial reliability and to minimize the inherent risks of operating with third parties; (ii) requires from all its suppliers a formal commitment to respect the principles in its Code of Ethics (such as protection and promotion of human rights, high standards of safety at work, environmental protection, anti-corruption, compliance with laws and regulations, ethical integrity and correctness in relations, respect for antitrust laws and fair competition); (iii) monitors observance of this commitment, to ensure the maintenance by Eni suppliers of the qualification requirements over time; (iv) if criticalities emerge, requires the implementation of improvement actions in their operating models or, if they fail to satisfy the minimum standards of acceptability, limits or inhibits their access to tenders. METRICS AND COMMENTS During 2018, more than 5,000 suppliers (including all the new ones) were subject to checks and assessment with reference to environmental and social sustainability aspects (i.e. health, safety, environment, human rights, anti-corruption and compliance). For 19% of these suppliers, potential criticalities and/or possible areas for improvement were identified; in 91% of cases these were not serious enough to compromise the possibility of working with them, while for the remaining 9% of suppliers checked, the criticalities revealed led to the temporary suspension of relations with Eni. In 2018 criticalities and/or areas for improvement were in fact identified on 1,008 suppliers; for 95 of these the assessment at the qualification stage was negative (i.e. non qualified) or Eni issued preventive measures (monitoring, state of attention with clearance, suspension or revocation of qualification); the 2018 figure for supplier suspensions, which shows a drop compared to previous years, reflects the reduced number of investigations for unlawful conduct involving Eni suppliers in the year. The identified criticalities (resulting in the request for the implementation of improvement plans) during the qualification process or Human Rights assessment are related to HSE issues or violations of Human Rights, such as health and safety regulations, violation of the code of ethics, corruption, environmental crimes. Key Performance Indicators Suppliers subjected to assessment regarding social responsibility aspects (number) of which: suppliers with criticalities / areas for improvement of which: suppliers with whom Eni has terminated the relations New suppliers that were screened using social criteria (%) 2018 5,184 1,008 95 100% 2017 5,055 1,248 65 100% 2016 5,171 1,336 131 100% CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 121 Transparency and anti-corruption Eni takes part in the Global Compact (GC), which encourages member companies to align their activities with ten universally recognized principles in terms of human rights, labour, the environment, transparency, and anti-corruption and to contribute to the achievement of the United Nations’ Sustainable Development Goals (SDGs). The GC principles are reflected in Eni’s Code of Ethics. In particular, the repudiation of all forms of corruption has been one of the fundamental ethical principles of Eni’s Code of Ethics since 1998 – shared among all employees when recruited – and the 231 Model. Eni has also designed and developed the Anti-Corruption Compliance Program, in accordance with the applicable rules in force, the international conventions and taking into account relevant guidance and best practices, as well as the policies adopted by the main international organisations. It is an organic system of rules and controls to prevent corruption practices. All Eni’s subsidiaries, in Italy and abroad, are required to adopt, by resolution of their own BoD41, both the Management System Guideline42 and all the other anti-corruption regulatory instruments issued by the parent company. Eni’s Anti-Corruption Compliance Program has evolved over the years with the aim of continuous improvement; in January 2017, Eni SpA was the first Italian company to achieve the ISO 37001:2016 “Antibribery Management Systems” certification. In order to maintain this certification, Eni SpA is subject to annual surveillance audits by the certifying body. At December 31, 2018, Eni was subject to two surveillance audits, both successfully concluded. To guarantee the effectiveness of Eni’s Anti-Corruption Compliance Program, in 2010 an ad hoc organizational structure was formed, the anti-corruption unit, which is responsible for providing specialist support to business lines and subsidiaries in Italy and abroad. This unit also implements an anti-corruption training program, both through e-learning and with classroom events, general workshops and job specific training. The workshops, designed using interactive formats, are carried out on the basis of the index produced annually by Transparency International (Corruption Perception Index) and of Eni’s presence in each Country. These workshops offer an overview of the anticorruption laws applicable to Eni, the risks that could result from their infringement for natural and legal persons and the Anti-Corruption Compliance Program adopted to address these risks. Generally the workshops are accompanied by job specific training, or training for professional areas particularly at risk in terms of corruption. In 2018, a methodology was developed to systematically group Eni’s people for the risk of corruption on the basis of risk drivers such as: Country, position, professional area and number of employees of the site, in order to optimize the identification of the target audience of the various training initiatives. The methodology is expected to be rolled out in 2019. In addition, in 2018 a communication initiative on the Company’s intranet called “Compliance Tips” was implemented to promote the dissemination of the culture of compliance at all levels; it addressed possible situations at risk that an employee might face. In addition, in 2017, a board induction was carried out for the Board of Statutory Auditors and new directors on the integrated compliance and Internal Audit processes, with a focus on whistleblowing reports and additional checks on anti-corruption regulatory instruments. In order to assess the adequacy and effective operation of the Anti- Corruption Compliance Program, as part of the integrated audit plan approved annually by the BoD, Eni carries out specific checks on relevant activities, with audits dedicated to analyses of processes and companies, identified based on the riskiness of the Country in which they operate and materiality, as well as third parties considered to be high risk, where required contractually. As evidence of Eni’s commitment to improve governance and transparency in the extraction sector, which is crucial to foster a proper use of resources and prevent corruption, Eni takes part in the Extractive Industries Transparency Initiative (EITI)43. Membership in the EITI is a value for Eni despite the fact that since 2017 the Company has published the “Report on payments to governments” in accordance with the reporting obligations introduced by the European Directive 2013/34 EU (Accounting Directive). Furthermore, on May 24, 2018, the BoD approved the Tax Strategy Guidelines, which set out Eni’s commitments in terms of tax transparency, aimed at paying taxes in the various Countries where value is generated in a manner consistent with the letter and spirit of the laws in force, in line with OECD recommendations on combating tax evasion and shifting profits towards Countries with low taxation (Base Erosion and Profit Shifting) by Multinational Enterprises. METRICS AND COMMENTS During 2018, 32 audits were carried out in 13 Countries, with anti-corruption checks that confirmed the overall adequacy and effective operation of the Anti-Corruption Compliance Program. In 2018, the anti-corruption e-learning campaign aimed at training the entire Company population continued; these campaigns are gradually being completed, thus ensuring full coverage in terms of training for all Eni people. In 2018, this campaign reached 2,844 employees, 32% of whom were managers, with a coverage that reflects Eni’s presence in the Countries in which it operates: 41% in Italy, 29% in Africa, 17% in Asia, 11% in the rest of Europe and 2% in the Americas. As part of its commitment in the EITI, Eni follows its international activities and, in the member Countries, it contributes annually to drafting the reports. As a member, it participates in the activities of the Multi Stakeholder Group in Congo, Mozambique, East Timor, Ghana, and the UK. In Kazakhstan, Nigeria and Mexico, Eni’s subsidiaries interface with EITI’s local Multi Stakeholder Groups through trade associations in the Countries. (41) Or alternatively the equivalent body depending on the governance of the subsidiary. (42) The MSGs are common guidelines for all Eni units for the management of operating and business support processes and cross-cutting compliance and governance processes. (43) Global initiative to promote responsible and transparent use of the financial resources generated in the extraction sector. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018122 Key Performance Indicators 2018 2017 2016 Audit actions on risk of corruption activities (number) 32 (number of participants) 951 920 493 E-learning for managers E-learning for other resources General Workshop Job specific training Fully Consolidated entities Total Fully Consolidated entities Total Fully Consolidated entities 33 822 Total 865 36 452 1,950 1,765 1,461 1,924 1,857 1,736 9,364 8,952 1,765 1,434 1,329 1,269(a) 1,461 1,539 1,503 1,214(a) Countries where Eni supports EITI’s local Multi Stakeholder Groups (number) 8 9 8 (a) The figure includes a small number of Eni resources belonging to companies not included in the scope of consolidation with the integral method which cannot be separated from the consolidated data. PROMOTION OF LOCAL DEVELOPMENT: COOPERATION MODEL Eni’s distinctive mark has always been its willingness to meet the development needs of the Countries in which it operates, collaborating on a regular basis with local authorities and stakeholders. For this to happen, Eni has adopted a systematic and applicable approach at all stages of the business in all operating contexts. In recent years Eni has ensured that from the negotiation phase, through exploration, to all operational processes, including decommissioning, there are adequate tools to know the local socio-economic context, also in relation to human rights, and to manage the demands of stakeholders as well as the needs of communities. These tools allow defining a structured intervention plan at local level that ensures the integration of both local needs and the guidelines contained in national development plans, in the United Nations 2030 Agenda and in the National Determined Contributions (NDCs). The support for local development strategy is centered on people and is based on enhancement of the energy resources of the Countries and the definition of initiatives to improve the living conditions of local communities. The development of energy sources is the target of Eni’s business model and involves the construction of infrastructure for the production and transport of gas for both export and local consumption, and the construction of off-grid and on-grid electricity production plants. Supporting development tailored to local needs, in line with business objectives in a long-term perspective and minimising socio-economic gaps by involving all stakeholders means today to tackle increasingly complex and global events such as climate change and migratory phenomena that require extending the scope of action beyond the “operating area” of plants. In order to address these current and future challenges, Eni’s cooperation model has three directions: 1. Community investment: Eni promotes a wide range of initiatives to improve people’s living conditions through economic diversification initiatives such as the development of agricultural projects, micro-enterprise, micro-credit or infrastructure projects, and education, water access and through health protection, such as the strengthening of public health services and awareness-raising and empowerment activities of the beneficiary populations. 2. Public Private Partnership: in keeping with the 2015 Addis Ababa agreement “Financing for development”, Eni has started collaborations with development cooperation organizations to pool resources not only in economic terms but also in terms of skills, know-how and experience. Specifically, in 2018 Eni established public-private partnerships with the United Nations Development Programme (UNDP) to contribute to sustainable development and promote the achievement of the SDGs, in particular universal access to energy by 2030, actions to combat climate change and the protection, restoration and sustainable use of the earth’s ecosystem and with the Food and Agricultural Organization (FAO) for access to clean and safe water in Nigeria. 3. Monitoring and evaluation of the direct, indirect and induced effects of Eni’s presence at local level: to measure the impacts and benefits of its initiatives and amplify their effects, in collaboration with the Polytechnic of Milan, Eni has developed two tools: the ELCE (Eni Local Content Evaluation) Model and the Eni Impact Tool44. (44) The ELCE (Eni Local Content Evaluation) Model was developed by Eni and validated by the Polytechnic of Milan to assess the direct, indirect and induced effects generated by Eni’s activities at a local level in the areas in which it operates. The Eni Impact Tool is a methodology developed by Eni and validated by Polytechnic of Milan that allows assessing the social, economic and environmental impacts of its activities at local level, quantifying the generated benefits and directing investment choices for future initiatives. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION123 Another tool for relations with local communities is the Stakeholder Management System for mapping, managing and monitoring relations with its stakeholders in the Countries where it operates and managing grievances at all stages of the business to ensure that all stakeholder suggestions are taken into account, to provide adequate responses and to prevent potential risk factors. As of 2018, this mapping also includes indigenous peoples located close by the operations and operated projects. Monitoring activities also include analyses to measure the percentage spent on local suppliers at some major upstream foreign subsidiaries. The 2018 percentage spent on local suppliers in these Countries is about 33%. METRICS AND COMMENTS In 2018, overall spending on community investment amounted to about €94.8 million (Eni share), of which approximately 98% related to upstream activities. In Asia, approximately €21.9 million was spent, mainly on economic diversification, in particular for the maintenance of road infrastructure (bridges and roads). In Africa a total of €46.7 million was spent, of which €43.9 million was on Sub-Saharan Africa, mainly in the area of professional training and the construction of school infrastructure (net of expenditure on resettlement). About €32.4 million was invested in infrastructure development, of which €13.4 million was in Africa and €15.2 million in Asia. In the field of health, in 2018, in order to assess the potential impact of projects on the health of the communities involved, the upstream sector completed 20 studies (Health Impact Assessment), of which 7 were integrated ESHIA studies (Environmental, Social and Health Impact Assessment). In addition, 3 HRIA (Human Rights Impact Assessment45), studies were carried out. The total number of grievances received is 193, of which 138 cases have been resolved and closed. In particular, 97% of complaints in Ghana were closed. Key Performance Indicators Community investment(a) of which: infrastructure (€ million) 2018 2017 2016 Fully Consolidated entities 73.9 29.6 Total 94.8 32.4 Fully Consolidated entities 66.8 22.1 Total 70.7 22.1 Fully Consolidated entities 60.3 23.3 Total 64.2 23.3 (a) The data includes resettlement activities: amounting to € 19.1 million in 2018. (45) See the section “Human Rights” on pages 118-120 for more information. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018124 KEY SUSTAINABILITY TOPICS For Eni, key sustainability topics are those priority aspects for the Company and its stakeholders that identify the challenges and key opportunities of the entire value creation cycle in the long term. Process for determining key topics For Eni, determining key sustainability topics is based on a process of identifying issues and setting priorities. It takes into account: 1 2 ANALYSIS OF THE SCENARIO Topics emerging from the business environment and progress with respect to the Strategic Plan. The analysis is presented every year at the Sustainability and Scenarios Committee and approved by the Eni BoD. RISK ASSESSMENT RESULTS Main risks including potential environmental, social, reputational and health and safety impacts. These are submitted to the BoD on a quarterly basis by the CEO. 3 STAKEHOLDERS’ PERSPECTIVE Key sustainability topics according to Eni’s various stakeholders46. The identified topics, according to the priorities set for the different business lines, are the basis for the elaboration of the four-year Strategic Plan and the non-financial reporting (Consolidated Disclosure of Non-Financial Information and Eni for). Then, the sustainability management objectives (MBOs) assigned to all managers are determined based on the Strategic Plan. The key topics are then presented to the Management Committee and Sustainability and Scenarios Committee, and reported to the BoD at the beginning of the reporting process. Below are the 2018 key topics associated with the sustainable development goals (SDGs) on which Eni’s activities have a direct or indirect impact. 2018 KEY TOPICS PATH TO DECARBONIZATION COMBATING CLIMATE CHANGE TECHNOLOGICAL INNOVATION OPERATIONAL EXCELLENCE MODEL PEOPLE SAFETY GHG emissions, promotion of natural gas, renewables, biofuels and green chemistry SDGs: 7 - 9 - 12 - 13 - 17 SDGs: 7 - 9 - 12 - 13 - 17 Employment and Diversity and Inclusion Training Occupational health and local communities health SDGs: 3 - 4 - 5 - 8 People safety and asset integrity SDGs: 3 - 8 - 11 REDUCTION OF ENVIRONMENTAL IMPACTS Water resources, biodiversity and oil spills SDGs: 3 - 6 - 12 - 14 - 15 HUMAN RIGHTS Rights of workers and local communities, Supply chain and Security SDGs: 4 - 8 - 10 - 16 - 17 INTEGRITY IN BUSINESS MANAGEMENT Transparency and Anti-Corruption SDGs: 10 - 16 - 17 PROMOTION OF LOCAL DEVELOPMENT: COOPERATION MODEL ACCESS TO ENERGY LOCAL DEVELOPMENT THROUGH PUBLIC-PRIVATE PARTNERSHIPS Economic diversiﬁcation, Education and Training, Access to water and hygiene, Health SDGs: 7 - 9 - 10 - 17 SDGs: 2 - 3 - 4 - 6 - 8 - 10 - 17 LOCAL CONTENT SDGs: 4 - 8 - 9 (46) Identified according to GRI standards, AA1000 Accountability and International Finance Corporation guidelines. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION125 REPORTING PRINCIPLES AND CRITERIA The Consolidated Disclosure of Non-Financial Information is drafted in accordance with the Decree 254/2016 and with the “Sustainability Reporting Standards”, published by the Global Reporting Initiative (GRI Standards), which represent the reporting standard adopted. The document is drafted in accordance with the “core” option of the GRI Standards and had undergone a limited assurance by the independent company which provided assurance to Eni Group’s Annual Report as of December 31, 2018. All figures refer to Eni SpA and its fully consolidated entities. In addition, an additional view was added in line with other corporate documents and in continuity with the past for data concerning safety, environment, climate, whistleblowing reports, anti-corruption training and community investment. The safety, environment and climate data consider the companies significant from the point of view of HSE impacts, with two points of view: the data only for the fully consolidated entities as required by the Decree and the data including companies under joint operation or joint control or associates in which Eni has control of operations47. In addition to providing continuity with respect to past publications and consistency with the objectives that the Company has set itself, the aim is to represent the potential impacts of the activities managed by Eni. Comments on safety, environment and climate data refer to the perimeter including the companies over which Eni has control of operations. Key Performance Indicators, selected according to items identified as the most relevant, are collected on an annual basis according to the consolidation perimeter of the relevant year and relate to the 2016-2018 period. All GRI indicators in the Content Index refer to the version of the GRI Standards published in 2016, with the exception of those of the Standards 403: occupational health and safety, which refer to the 2018 edition. KPI METHODOLOGY CLIMATE CHANGE GHG EMISSIONS EMISSION INTENSITY Scope 1: the GHGs include CO2, CH4 and N2O emissions; the Global Warming Potential used is 25 for CH4 and 298 for N2O. In 2019, the Eni inventory will be certified in accordance with ISAE3000/3410. The emission factors used for the calculations are, where possible, site specific or, as an alternative, drawn from the international documents available. Scope 2: Scope 2 indirect emissions relate to the generation of electricity, steam and heat purchased from third parties and include the contributions of CO2, CH4 and N2O. Numerator: direct GHG emissions (Scope 1) including CO2, CH4 and N2O. Denominator: • UPS: 100% operated hydrocarbon gross production • R&M: incoming processed quantities (raw materials and semi-finished products) from own refineries • EniPower: equivalent electrical energy produced OPERATIONAL EFFICIENCY It expresses the GHG emissions intensity (scope 1 and scope 2 calculated on an operated basis expressed in tonCO2eq) of Eni’s main industrial productions compared to operated production (converted by homogeneity into barrels of oil equivalent using the Eni average conversion factors) in the individual businesses of reference, thus measuring their degree of operating efficiency in a decarbonization scenario. ENERGY CONSUMPTION Consumption from primary sources: sum of consumption of fuel gas, natural gas, refinery/process gas, LPG, light distillates/ petrol, diesel, kerosene, fuel oil, FOK and coke from FCC. Primary energy purchased from other companies: sum of purchases of electricity, heat and steam from third parties. Consumption from renewable sources depends on the national electric mix because consumption from photovoltaic panels installed by Eni on its assets is currently negligible. ENERGY INTENSITY The refining energy intensity index represents the total value of energy actually used in a given year in the various refinery processing plants, divided by the corresponding value determined on the basis of predefined standard consumption values for each processing plant. For comparison between years, the data for 2009 have been taken as the baseline (100%). For these indexes the numerator represents consumption from primary resources and purchases of electricity and/or steam. PEOPLE, HEALTH AND SAFETY EMPLOYMENT Eni uses a large number of contractors to carry out the activities within its own sites. INDUSTRIAL RELATIONS SENIORITY TRAINING HOURS LOCAL SENIOR MANAGERS AND MANAGERS ABROAD Regarding industrial relations, the minimum notice period for operational changes is in line with the provisions of the laws in force and the trade union agreements signed in the Countries in which Eni operates. Employees covered by collective bargaining: are those employees whose employment relationship is governed by collective agreements or contracts, whether national, industry, company or site. Average number of years worked by employees at Eni and its subsidiaries. Hours delivered to Eni employees through training courses managed and carried out by Eni Corporate University (classroom and remote) and through activities carried out by the organisational units of Eni Business areas/Companies independently, also through on-the-job training. Average training hours are calculated as total training hours divided by the average number of employees in the year. Number of local senior managers + managers (employees born in the Country in which their main working activity is based) divided by total employment abroad. (47) This view includes the following non-fully consolidated companies deemed significant from a HSE impacts standpoint: Mozambique Rovuma Venture SpA, Agiba Petroleum Co, Cardón IV SA, Groupment Sonatrach-Agip, InAgip doo, Karachaganak Petroleum Operating BV, Llc “Westgasinvest”, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, United Gas Derivatives Co, Virginia Indonesia Co Llc, Costiero Gas Livorno SpA, Petroven Srl, Servizio Fondo Bombole Metano SpA, Esacontrol SA, Tecnoesa SA, Oleoduc du Rhone SA, OOO Eni-Nefto, Eni Gas Transport Services Srl, Versalis Congo Sarlu, Versalis Kimya Ticaret Limited Sirketi, Versalis Pacific (India) Private Limited, Società EniPower Ferrara Srl, EniProgetti Egypt Ltd. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018126 KPI METHODOLOGY SAFETY TRIR: total recordable injuries rate (injuries leading to days of absence, medical treatments and cases of work limitations). Numerator: number of total recordable injuries; denominator: hours worked in the same period. Result of the ratio multiplied by 1,000,000. High-consequence work-related injuries rate: indicator of frequency of injuries at work with serious consequences (injuries at work with days of absence exceeding 180 days or resulting in total or permanent disability). Numerator: number of injuries at work with serious consequences; denominator: hours worked in the same period. Result of the ratio multiplied by 1,000,000. Near miss: an incidental event, of which the origin, execution and potential effect is accidental in nature, but which is however different from an accident only in that the result has not proved damaging, due to luck or favourable circumstances, or to the mitigating intervention of technical and/or organizational protection systems. Accidental events that do not turn into accidents or injuries are therefore considered to be near misses. The main hazards identified in 2018 at Eni were found in the following types of activities: • work at height: exposes workers to the risk of falls from a height. At Eni, this occurs especially for work that requires the use of scaffolding or that involves the lifting of workers with a safety harness (man rigging); • load handling: exposes workers to collisions, crushing, falls from a height or on the same plane mainly during the lifting of material and the movement on the same plane of various types of materials. HEALTH Number of occupational disease reports presented by heirs: indicator used as a proxy for the number of deaths due to occupational diseases. Recordable cases of occupational diseases: number of occupational disease reports. Main types of diseases: (i) due to exposure to chemical agents: neoplasms, respiratory diseases, blood diseases; (ii) due to exposure to biological agents: malaria; (iii) due to exposure to physical agents: hypoacusis. ENVIRONMENT WATER WITHDRAWAL BY SOURCE BIODIVERSITY OIL SPILLS WASTE AIR PROTECTION Sum of sea water, freshwater, and salt water from subsoil or surface withdrawn. TAF (groundwater treatment plant) water represents the amount of polluted groundwater treated and reused in the production cycle. Number of sites overlapping with protected areas and Key Biodiversity Areas (KBAs): calculated by identifying the active national and international concessions, whether operated or in joint ventures, under development or in production, present in the Company databases (last updated in June 2018) that overlap with one or more protected or key biodiversity areas (data made available to Eni by “World Database on Protected Areas” last updated in December 2018, and “World Database of Key Biodiversity Areas” last updated in June 2018, in the framework of Eni’s membership in the UNEP-WCMC Proteus Partnership) where development/production operations (wells, sealines, pipelines and onshore and offshore plants as documented in the company’s GIS geodatabase) overlap with protected areas and/or KBAs. Number of sites adjacent to protected areas or Key Biodiversity Areas (KBAs): concessions for which the overlap analysis described above has not confirmed the presence of operational sites (development/production) overlapping protected areas or key biodiversity areas, determining their position outside these areas. There are some limitations to consider when interpreting the results of this analysis: • it is globally recognised that there is an overlap between the different databases of protected areas and KBAs, which may have led to a certain degree of duplication in the analysis (some protected areas/KBAs could be counted several times); • the databases of protected or key biodiversity areas used for the analysis, while representing the most up-to-date information available at global level, may not be complete for each Country. Spills from primary or secondary containment into the environment of oil or petroleum derivative from refining or oil waste occurring during operation or as a result of sabotage, theft or vandalism. Waste from production: waste from production activities, including waste from drilling activities and construction sites. Waste from remediation activities: this includes waste from soil securing and remediation activities, demolition and groundwater classified as waste. NOX:total direct emissions of nitrogen oxide due to combustion processes with air. Includes emissions of NOx from flaring activities, sulphur recovery processes, FCC regeneration, etc. Includes emissions of NO and NO2, excludes N2O. SOX:total direct emissions of sulphur oxides, including emissions of SO2 and SO3. NMVOC: total direct emissions of hydrocarbons, hydrocarbon substitutes and oxygenated hydrocarbons that evaporate at normal temperature. They include LPG and exclude methane. PST: direct emissions of Total Suspended Particulates, finely divided solid or liquid material suspended in gaseous flows. Standard emission factors. SUPPLIERS SUPPLIERS SUBJECTED TO ASSESSMENT This indicator relates to processes managed by Eni SpA, Eni Ghana and Eni Pakistan and represents all suppliers subjected to Due Diligence, a qualification process, HSE, compliance or business conduct assessment feedback, human rights feedback process or assessment (SA8000). It relates to all suppliers for which Vendor Management activities are centralized in Eni SpA (i.e. all Italian suppliers, mega-suppliers and international suppliers) and to local suppliers of Eni Ghana and Eni Pakistan. CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION127 KPI METHODOLOGY ANTI-CORRUPTION ANTI- CORRUPTION TRAINING E-learning for managers: online courses for managerial figures. E-learning for other resources: online courses for non-managerial resources. General workshop: in-class training events for staff at risk of corruption. Job specific training: in-class training events for professional areas at risk of corruption. LOCAL COMMUNITIES SPENDING TO LOCAL SUPPLIERS The indicator refers to the 2018 share of expenditure to local suppliers. “Spending to local suppliers” has been defined according to the following alternative methods on the basis of the specific characteristics of the Countries analysed: 1) “Equity Method” (Ghana): the share of spending to local suppliers is determined on the basis of the percentage of ownership of the corporate structure (e.g., for a JV with 60% local component, 60% of total spending to the JV is considered as spending to local suppliers); 2) “Local Currency Method” (Angola): the portion paid in local currency is identified as spending to local suppliers; 3) “Country registration method” (Iraq e Nigeria): spending to suppliers registered in the Country and not belonging to international/ megasupplier groups (e.g., drilling service/drilling support service providers) is identified as local; 4) “Country registration + Local Currency Method” (Congo): spending to suppliers registered in the Country and not belonging to international/megasupplier groups (e.g., drilling service/drilling support service providers) is identified as local. For the latter, spending in local currency is considered to be local. The list of Countries to which the expenditure indicator refers will be expanded starting from 2019. GRIEVANCES Complaints made by an individual or a group of individuals relating to actual or perceived impacts caused by the Company’s operational activities. Correlation table between the key sustainability topics for Eni and GRI Standards KEY SUSTAINABILITY TOPICS GRI STANDARDS INTERNAL BOUNDARY EXTERNAL BOUNDARY AND LIMITATIONS O T H T A P N O I T A Z I N O B R A C E D L E D O M E C N E L L E C X E L A N O I T A R E P O L A C O L F O N O I T O M O R P T N E M P O L E V E D Combating climate change GHG emissions, promotion of natural gas, renewable, biofuels and green chemistry GRI 201 Economic Performance GRI 305 Emissions GRI 302 Energy Technological Innovation - People Employment, diversity and inclusion Training Occupational health and local communities health GRI 202 Market presence GRI 401 Employment GRI 403 Occupational H&S GRI 404 Training and Education GRI 405 Diversity of governance bodies and employees Safety People safety and asset integrity Reduction of environmental impacts Water resources Biodiversity Oil spill Human Rights Rights of workers and local communities Supply chain Security Integrity in business management Transparency and anti-corruption Access to energy, local development through public-private partnerships Economic diversification Education and training Access to water and hygiene Health GRI 403 Occupational H&S GRI 303 Water GRI 304 Biodiversity GRI 306 Effluents and Waste GRI 307 Environmental compliance GRI 406 Non-Discrimination GRI 410 Security Practices GRI 412 Human Rights Assessment GRI 414 Supplier Social Assessment GRI 205 Anti-corruption GRI 203 Indirect Economic Impacts GRI 413 Local Communities Local content GRI 204 Procurement Practices (1) RNES: Reporting not extended to suppliers. (2) RNEC: Reporting not extended to customers. (3) RPES: Reporting partially extended to suppliers. √ √ √ √ √ √ √ √ √ √ Suppliers and customers (RNES1; RNEC2) Suppliers Local security forces; Suppliers (RNES1) Suppliers (RPES3) Suppliers (RNES1) CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 128 GRI Content Index DISCLOSURE INDICATOR DESCRIPTION SECTION AND/OR PAGE NUMBER Organizational profile 102-1 102-2 102-3 102-4 102-5 102-6 102-7 102-8 102-9 102-10 102-11 102-12 102-13 Strategy 102-14 102-15 Ethics and integrity 102-16 Governance 102-18 Stakeholders engagement 102-40 102-41 102-42 102-43 102-44 Reporting practice 102-45 102-46 102-47 102-48 102-49 102-50 102-51 102-52 102-53 Name of the organization Activities, brands, products, and services Annual Report 2018, p. 1 Annual Report 2018, p. 3 Location of headquarters Location of operations Ownership and legal form Markets served Scale of the organization Annual Report 2018, inside back cover Annual Report 2018, p. 3 Annual Report 2018, inside back cover https://www.eni.com/en_IT/company/governance/shareholders.page Annual Report 2018, p. 3 Annual Report 2018, pp. 12-13 NFI, pp. 114; 125 Information on employees and other workers NFI, pp. 114; 125 Supply chain NFI, p. 120 Significant changes to the organization and its supply chain Annual Report 2018, pp. 146-149; 283 Precautionary Principle or approach Annual Report 2018, pp. 20-23 External initiatives Membership of associations Annual Report 2018, p. 15 Annual Report 2018, p. 15 Statement from senior decision-maker Annual Report 2018, pp. 7-11 Key impacts, risks, and opportunities Annual Report 2018, pp. 20-23; 87-102 Values, principles, standards, and norms of behavior Annual Report 2018, pp. 2; 4-5; 29 NFI, 106 Governance structure Annual Report 2018, pp. 24-29 List of stakeholder groups Annual Report 2018, pp. 14-15 Collective bargaining agreements NFI, pp. 114; 125 Identifying and selecting stakeholders Annual Report 2018, pp. 14-15 Approach to stakeholder engagement Key topics and concerns raised Annual Report 2018, pp. 14-15 Annual Report 2018, pp. 14-15 Entities included in the consolidated financial statements Annual Report 2018, pp. 260-283 NFI, p. 125 Defining report content and topic Boundaries List of material topics Restatements of information Changes in reporting Reporting period Date of most recent report Reporting cycle NFI, pp. 124; 127 NFI, pp. 124; 127 NFI, pp. 111; 118; 125 NFI, pp. 124; 127 NFI, p. 125 https://www.eni.com/en_IT/documentations.page NFI, p. 125 Contact point for questions regarding the report https://www.eni.com/en_IT/sustainability/contacts-sustainability.page 102-54 / 102-55 Claims of reporting in accordance with the GRI Standards and content index 102-56 External assurance NFI, pp. 125; 128-130 NFI, pp. 131-133 CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 129 Specific Standard disclosures DISCLOSURE INDICATOR DESCRIPTION SECTION AND/OR PAGE NUMBER OMISSION CATEGORY: ECONOMIC METRICS AND COMMENTS Economic performance - DMA (103-1; 103-2; 103-3) NFI, pp. 106-111; 124; 127 201-2 Financial implications and other risks and opportunities due to climate change Annual Report 2018, pp. 22-23; 99-100 NFI, pp. 108-111 Market presence - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 112-114; 124-125; 127 202-2 Proportion of senior management hired from the local community NFI, pp. 113-114; 125 Indirect economic impacts - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 122-124; 127 203-1 Infrastructure investments and services supported NFI, p. 123 Procurement practices - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 122-124; 127 204-1 Proportion of spending on local suppliers NFI, pp. 122-123; 127 Anti-corruption - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 121-122; 124; 127 205-2 Communication and training about anti-corruption policies and procedures NFI, pp. 121-122; 127 CATEGORY: ENVIRONMENTAL METRICS AND COMMENTS Energy - DMA (103-1; 103-2; 103-3) NFI, pp. 106-111; 124-125; 127 302-3 Energy intensity NFI, pp. 110-111; 125 Water - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 116-118; 124; 126-127 303-1 Water withdrawal by source NFI, pp. 117-118; 126 Biodiversity - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 116-118; 124; 126-127 304-1 Operational sites owned, leased, managed in, or adjacent to, protected areas and areas of high biodiversity value outside protected areas NFI, pp. 117; 126 The biodiversity disclosure is limited to the upstream sector only. Emissions - DMA (103-1; 103-2; 103-3) NFI, pp. 106-111; 124-125; 127 305-1 305-4 Direct (Scope 1) GHG emissions GHG emissions intensity NFI, pp. 110-111; 125 NFI, pp. 110-111; 125 Effluents and waste - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 116-118; 124; 126-127 306-2 306-3 Waste by type and disposal method Significant spills NFI, pp. 117-118; 126 NFI, pp. 117-118; 126 Environmental compliance - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 116-118; 124; 127 307-1 Environmental compliance Annual Report 2018, pp. 205-209 CATEGORY: SOCIAL METRICS AND COMMENTS Employment - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 112-114; 124-125; 127 401-1 New employee hires and employee turnover NFI, pp. 113-114; 125 Occupational health and safety - DMA (103-1; 103-2; 103-3; 403-1; 403-2; 403-3; 403-4; 403-5; 403-6; 403-7) NFI, pp. 106-107; 112-115; 124; 126-127 403-9 Work-related injuries 403-10 Work-related ill health NFI, pp. 115; 126 NFI, pp. 113-114; 126 CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 130 DISCLOSURE INDICATOR DESCRIPTION SECTION AND/OR PAGE NUMBER OMISSION Training and education - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 112-114; 124-125; 127 404-1 Average hours of training per year per employee NFI, pp. 113-114; 125 Diversity and equal opportunity - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 112-114; 124; 127 405-1 Diversity of governance bodies and employees NFI , pp. 113-114 Non-discrimination - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 118-120; 124; 127 406-1 Incidents of discrimination and corrective actions taken NFI, pp. 119-120 Security practices - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 118-120; 124; 127 410-1 Security personnel trained in human rights policies or procedures NFI, pp. 119-120 Human rights assessment - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 118-120; 124; 127 412-2 Employee training on human rights policies or procedures NFI, pp. 119-120 Local communities - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 122-124; 127 413-1 Operations with local community engagement, impact assessments, and development programs NFI, pp. 122-123 Supplier social assessment - DMA (103-1; 103-2; 103-3) NFI, pp. 106-107; 120; 124; 126-127 414-1 New suppliers that were screened using social criteria NFI, pp. 120; 126 CATEGORY: TECHNOLOGICAL INNOVATION Innovation - DMA (103-1; 103-2; 103-3) NFI, pp. 106-111; 124; 127 CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION Independent auditors’ report 131 132 133 134 OTHER INFORMATION Acceptance of Italian responsible payments code Coherently with Eni’s policy on transparency and accuracy in managing its suppliers, Eni SpA adhered to the Italian responsible payments code established by Assolombarda in 2014. In 2018, payments to Eni’s suppliers were made within 55 days, in line with contractual provisions. Article No. 15 (former Article No. 36) of Italian regulatory exchanges (Consob Resolution No. 20249 published on December 28, 2017). Continuing listing standards about issuers that control subsidiaries incorporated or regulated in accordance with laws of extra-EU Countries. Certain provisions have been enacted to regulate continuing Italian listing standards of issuers controlling subsidiaries that are incorporated or regulated in accordance with laws of extra- EU Countries, also having a material impact on the consolidated financial statements of the parent company. Regarding the aforementioned provisions, the Company discloses that: - as of December 31, 2018, nine of Eni’s subsidiaries: Eni Congo SA, Eni Petroleum Co Inc, Nigerian Agip Oil Co Ltd, Nigerian Agip Exploration Ltd, Eni Finance USA Inc, Eni Trading & Shipping Inc, Eni Canada Holding Ltd, Eni Turkmenistan Ltd and Eni Ghana Exploration and Production Ltd - fall within the scope of the new continuing listing standards; - the Company has already adopted adequate procedures to ensure full compliance with the new regulations. Branches In accordance with Article No. 2428 of the Italian Civil Code, it is hereby stated that Eni has the following branches: San Donato Milanese (MI) - Via Emilia, 1; San Donato Milanese (MI) - Piazza Vanoni, 1. Subsequent events Subsequent business developments are described in the operating review of each of Eni’s business segments. GLOSSARY 135 The glossary of oil and gas terms is available on Eni’s web page at the address eni.com. Below is a selection of the most frequently used terms. | Average reserve life index Ratio between the amount of reserves at the end of the year and total production for the year. | Barrel/bbl Volume unit corresponding to 159 liters. A barrel of oil corresponds to about 0.137 metric tonnes. | LNG Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed and consumed. One ton of LNG corresponds to 1,400 cubic meters of gas. | LPG Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous at normal pressure and easily liquefied at room temperature through limited compression. | Boe (Barrel of Oil Equivalent) Is used as a standard unit | Mineral Potential (Potentially recoverable hydrocarbon measure for oil and natural gas. From July 1, 2012, Eni has updated the conversion rate of gas to 5,492 cubic feet of gas equals 1 barrel of oil (it was 5,550 cubic feet of gas per barrel in previous reporting periods). | Conversion Refinery process allowing the transformation of heavy fractions into lighter fractions. Conversion processes are cracking, visbreaking, coking, the gasification of refinery residues, etc. The ration of overall treatment capacity of these plants and that of primary crude fractioning plants is the conversion rate of a refinery. Flexible refineries have higher rates and higher profitability. | Elastomers (or Rubber) Polymers, either natural or synthetic, which, unlike plastic, when stress is applied, return, to a certain degree, to their original shape, once the stress ceases to be applied. The main synthetic elastomers are polybutadiene (BR), styrene-butadiene rubber (SBR), ethylenepropylene rubber (EPR), thermoplastic rubber (TPR) and nitrylic rubber (NBR). | Emissions of NOx (Nitrogen Oxides) Total direct emissions of nitrogen oxides deriving from combustion processes in air. They include NOx emissions from flaring activities, sulphur recovery processes, FCC regeneration, etc. They include NO and NO2 emissions and exclude N2O emissions. | Emissions of SOx (Sulphur Oxides) Total direct emissions of sulfur oxides including SO2 and SO3 emissions. Main sources are combustion plants, diesel engines (including maritime engines), gas flaring (if the gas contains H2S), sulphur recovery processes, FCC regeneration, etc. | Enhanced recovery Techniques used to increase or stretch over time the production of wells. | Green House Gases (GHG) Gases in the atmosphere, transparent to solar radiation, can consistently trap infrared radiation emitted by the earth’s surface, atmosphere and clouds. The six relevant greenhouse gases covered by the Kyoto Protocol are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6). GHGs absorb and emit radiation at specific wavelengths within the range of infrared radiation determining the so called greenhouse phenomenon and the related increase of earth’s average temperature. Eni’s emissions are reported in CO2 equivalent (CO2eq) because they include not only carbon dioxide but also other climating gases as methane (CH4) and nitrouse oxide (N2O), characterized by a conversion factor of 25 and 298 respectively (source: IPCC). | Infilling wells Infilling wells are wells drilled in a producing area in order to improve the recovery of hydrocarbons from the field and to maintain and/or increase production levels. volumes) Estimated recoverable volumes which cannot be defined as reserves due to a number of reasons, such as the temporary lack of viable markets, a possible commercial recovery dependent on the development of new technologies, or for their location in accumulations yet to be developed or where evaluation of known accumulations is still at an early stage. | Natural gas liquids Liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that used to be defined natural gasoline, are natural gas liquids. | Oil spills Discharge of oil or oil products from refining or oil waste occurring in the normal course of operations (when accidental) or deriving from actions intended to hinder operations of business units or from sabotage by organized groups (when due to sabotage or terrorism). | Olefins (or Alkenes) Hydrocarbons that are particularly active chemically, used for this reason as raw materials in the synthesis of intermediate products and of polymers. | Over/underlifting Agreements stipulated between partners regulate the right of each to its share in the production of a set period of time. Amounts different from the agreed ones determine temporary over/underlifting situations. | Production Sharing Agreement (PSA) Contract in use in African, Middle Eastern, Far Eastern and Latin American Countries, among others, regulating relationships between states and oil companies with regard to the exploration and production of hydrocarbons. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “cost oil” is used to recover costs borne by the contractor and “profit oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from Country to Country. | Proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from know reservoirs, and under existing economic conditions. 136 The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. | Reserves Quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. Reserves can be: (i) developed reserves quantities of oil and gas anticipated to be through installed extraction equipment and infrastructure operational at the time of the reserves estimate; (ii) undeveloped reserves: oil and gas expected to be recovered from new wells, facilities and operating methods. | Ship-or-pay Clause included in natural gas transportation contracts according to which the customer for which the transportation is carried out is bound to pay for the transportation of the gas also in case the gas is not transported. | Take-or-pay Clause included in natural gas purchase contracts gas set in the contract also in case it is not collected by the customer. The customer has the option of collecting the gas paid and not delivered at a price equal to the residual fraction of the price set in the contract in subsequent contract years. | Upstream/downstream The term upstream refers to all hydrocarbon exploration and production activities. The term mid-downstream includes all activities inherent to oil industry subsequent to exploration and production. Process crude oil and oil-based feedstock for the production of fuels, lubricants and chemicals, as well as the supply, trading and transportation of energy commodities. It also includes the marketing business of refined and chemicals products. | Wholesale sales Domestic sales of refined products to wholesalers/distributors (mainly gasoil), public administrations and end consumers, such as industrial plants, power stations (fuel oil), airlines (jet fuel), transport companies, big buildings and households. They do not include distribution through the service station network, marine bunkering, sales to oil and petrochemical companies, importers and international organizations. | Workover Intervention on a well for performing significant according to which the purchaser is bound to pay the contractual price or a fraction of such price for a minimum quantity of the maintenance and substitution of basic equipment for the collection and transport to the surface of liquids contained in a field. Abbreviations /d /y bbbl bbl bboe bcf bcm per day per year billion barrels barrels billion barrels of oil equivalent billion cubic feet billion cubic meters bln liters billion liters bln tonnes billion tonnes boe cm GWh LNG LPG kbbl kboe barrels of oil equivalent cubic meter gigawatthour Liquefied Natural Gas Liquefied Petroleum Gas thousand barrels thousand barrels of oil equivalent km ktoe kilometers thousand tonnes of oil equivalent ktonnes thousand tonnes mmbbl mmboe mmcf mmcm million barrels million barrels of oil equivalent million cubic feet million cubic meters mmtonnes million tonnes MTPA Million Tonnes Per Annum No. NGL PCA ppm PSA Tep TWh number Natural Gas Liquids Production Concession Agreement parts per million Production Sharing Agreement Ton of equivalent petroleum Terawatt hour GLOSSARYConsolidated ﬁnancial statements 2018 2 | M A N A G E M E N T R E P O R T 1 3 7 | C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Financial statements Notes on consolidated financial statements Supplemental oil and gas information Management’s certification Report of Independent Auditors 2 5 9 | A N N E X 138 146 237 252 253 138138 CONSOLIDATED BALANCE SHEET (€ million) ASSETS Current assets Cash and cash equivalents Financial assets held for trading Financial assets available for sale Other current financial assets Trade and other receivables Inventories Income tax receivables Other tax receivables Other current assets Non-current assets Property, plant and equipment Inventory - compulsory stock Intangible assets Equity-accounted investments Other investments Other non-current financial assets Deferred tax assets Other non-current assets Assets held for sale TOTAL ASSETS LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities Short-term debt Current portion of long-term debt Trade and other payables Income tax payables Other tax payables Other current liabilities Non-current liabilities Long-term debt Provisions for contingencies Provisions for employee benefits Deferred tax liabilities Other non-current liabilities Liabilities directly associated with assets held for sale TOTAL LIABILITIES SHAREHOLDERS’ EQUITY Non-controlling interest Eni shareholders’ equity Share capital Retained earnings Cumulative currency translation differences Other reserves Treasury shares Interim dividend Net profit (loss) Total Eni shareholders’ equity TOTAL SHAREHOLDERS’ EQUITY TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY December 31, 2018 December 31, 2017 Note Total amount of which with related parties Total amount of which with related parties 73 834 30 1,214 46 164 2,808 60 23 (5) (6) (15) (7) (8) (9) (9) (10) (23) (11) (8) (12) (14) (14) (15) (22) (10) (23) (24) (18) (18) (16) (9) (9) (17) (23) (18) (20) (21) (22) (17) (23) (24) (25) 10,836 6,552 300 14,101 4,651 191 561 2,258 39,450 60,302 1,217 3,170 7,044 919 1,253 3,931 792 78,628 295 118,373 2,182 3,601 16,747 440 1,432 3,980 28,382 20,082 11,886 1,117 4,272 1,502 38,859 59 67,300 57 4,005 36,702 6,605 1,672 (581) (1,513) 4,126 51,016 51,073 118,373 49 633 71 915 160 661 3,664 63 23 7,363 6,012 207 316 15,421 4,621 191 729 1,573 36,433 63,158 1,283 2,925 3,511 219 1,675 4,078 1,323 78,172 323 114,928 2,242 2,286 16,748 472 1,472 1,515 24,735 20,179 13,447 1,022 5,900 1,479 42,027 87 66,849 49 4,005 35,966 4,818 1,889 (581) (1,441) 3,374 48,030 48,079 114,928 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS CONSOLIDATED PROFIT AND LOSS ACCOUNT 139139 (€ million) REVENUES Net sales from operations Other income and revenues COSTS Purchases, services and other Net (impairment losses) reversals of trade and other receivables Payroll and related costs Other operating income (expense) Depreciation and amortization Net (impairment losses) reversals of tangible and intangible assets Write-off of tangible and intangible assets OPERATING PROFIT (LOSS) FINANCE INCOME (EXPENSE) Finance income Finance expense Net finance income (expense) from financial assets held for trading Derivative financial instruments INCOME (EXPENSE) FROM INVESTMENTS Share of profit (loss) from equity-accounted investments Other gain (loss) from investments PROFIT (LOSS) BEFORE INCOME TAXES Income taxes Net profit (loss) for the year - continuing operations Net profit (loss) for the year - discontinued operations Net profit (loss) for the year Attributable to Eni: - continuing operations - discontinued operations Attributable to non-controlling interest: - continuing operations - discontinued operations Earnings per share attributable to Eni (€ per share) Basic Diluted Earnings per share attributable to Eni – Continuing operations (€ per share) Basic Diluted (33) (33) 2018 2017 2016 Total amount of which with related parties Total amount of which with related parties Total amount of which with related parties Note (28) 75,822 1,116 76,938 1,383 8 66,919 4,058 70,977 1,567 41 55,762 931 56,693 1,238 74 (29) (55,622) (8,009) (51,548) (9,164) (43,278) (8,212) (7) (29) (23) (11) (12) (13) (11) (12) (30) (30) (30) (23) (14) (31) (32) (24) 247 157 (145) 27 (415) (3,093) 129 (6,988) (866) (100) 9,983 3,967 (4,663) 32 (307) (971) (68) 1,163 1,095 10,107 (5,970) 4,137 4,137 4,126 4,126 11 11 1.15 1.15 1.15 1.15 26 (22) 319 (913) (2,951) (32) (7,483) 225 (263) 8,012 (34) 331 (846) (2,994) 16 (7,559) 475 (350) 2,157 115 (283) 3,924 (5,886) 191 (4) 5,850 (6,232) (111) 837 (1,236) (267) 335 68 6,844 (3,467) 3,377 3,377 3,374 3,374 3 3 0.94 0.94 0.94 0.94 (21) (482) (885) (326) (54) (380) 892 (1,936) (1,044) (413) (1,457) (1,051) (413) (1,464) 7 7 (0.41) (0.41) (0.29) (0.29) CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018 140140 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (€ million) Net profit (loss) Other items of comprehensive income (loss) Items that are not reclassified to profit or loss in later periods Remeasurements of defined benefit plans Fair value valuation of minor investments with effect to other comprehensive income Tax effect related to other comprehensive income not to be reclassified to profit or loss in subsequent periods Items that may be reclassified to profit or loss in later periods Currency translation differences Change in the fair value of available-for-sale financial instruments Change in the fair value of cash flow hedging derivatives Share of other comprehensive income on equity-accounted entities Tax effect related to other comprehensive income to be reclassified to profit or loss in subsequent periods Total other items of comprehensive income (loss) Total comprehensive income (loss) Attributable to Eni - continuing operations - discontinued operations Attributable to non-controlling interest - continuing operations - discontinued operations 2017 3,377 2016 (1,457) (33) 16 Note (25) (25) (25) (25) (25) (25) (25) 2018 4,137 (15) 15 (2) (2) 1,787 (243) (24) 58 1,578 1,576 5,713 29 (4) (5,573) (5) (6) 69 1 (5,514) (5,518) (2,141) 5,702 (2,144) 5,702 (2,144) 11 11 3 3 (35) (19) 1,198 (4) 883 32 (220) 1,889 1,870 413 819 (413) 406 7 7 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY 141141 Eni shareholders’ equity s e c n e r e ff d n o i t a i l s n a r t y c n e r r u c e v i t a l u m u C s g n i n r a e d e n i a t e R l a t i p a c e r a h S s e v r e s e r r e h t O s e r a h s y r u s a e r T d n e d i v i d m i r e t n I r a e y e h t r o f ) s s o l ( t fi o r p t e N 4,005 4,005 35,966 245 36,211 4,818 1,889 (581) (1,441) 3,374 4,818 1,889 (581) (1,441) 3,374 4,126 (17) 15 (2) (185) (24) (209) (211) 1,787 1,787 1,787 4,126 l a t o T 48,030 245 48,275 4,126 (17) 15 (2) 1,787 (185) (24) 1,578 5,702 1,441 (2,881) (1,440) (1,513) (1,513) t s e r e t n i g n i l l o r t n o c - n o N 49 49 11 11 (3) y t i u q e ’ s r e d l o h e r a h s l a t o T 48,079 245 48,324 4,137 (17) 15 (2) 1,787 (185) (24) 1,578 5,713 (1,440) (1,513) (3) 493 493 5 (7) (2) 36,702 (493) (3,374) (72) (2,953) (3) (2,956) (6) (6) 1,672 6,605 (581) (1,513) 4,126 5 (13) (8) 51,016 5 (13) (8) 51,073 57 e t o N (25) (3) (25) (25) (25) (25) (25) (25) (25) (€ million) Balance at December 31, 2017 Changes in accounting policies (IFRS 9 and 15) Balance at January 1, 2018 Net profit for the year Other items of comprehensive income (loss) Items that are not reclassified to profit or loss in later periods Remeasurements of defined benefit plans net of tax effect Change of minor investments measured at fair value with effects recognised in OCI Items that may be reclassified to profit or loss in later periods Currency translation differences Change in the fair value of cash flow hedge derivatives net of tax effect Share of “Other comprehensive income” on equity-accounted entities Total comprehensive income (loss) of the year Transactions with shareholders Dividend distribution of Eni SpA (€0.40 per share in settlement of 2017 interim dividend of €0.40 per share) Interim dividend distribution of Eni SpA (€0.42 per share) Dividend distribution of other companies Allocation of 2017 net income Other changes in shareholders’ equity Long-term share-based incentive plan Other changes Balance at December 31, 2018 (25) 4,005 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018 142142 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued) Eni shareholders’ equity s e c n e r e ff d n o i t a i l s n a r t y c n e r r u c e v i t a l u m u C s g n i n r a e d e n i a t e R l a t i p a c e r a h S e t o N s e v r e s e r r e h t O s e r a h s y r u s a e r T d n e d i v i d m i r e t n I r a e y e h t r o f ) s s o l ( t fi o r p t e N t s e r e t n i g n i l l o r t n o c - n o N y t i u q e ’ s r e d l o h e r a h s l a t o T l a t o T (25) 4,005 40,367 10,319 1,832 (581) (1,441) (1,464) 3,374 53,037 3,374 49 3 53,086 3,377 (€ million) Balance at December 31, 2016 Net profit for the year Other items of comprehensive income (loss) Items that are not reclassified to profit or loss in later periods Remeasurements of defined benefit plans net of tax effect Items that may be reclassified to profit or loss in later periods Currency translation differences Change in the fair value of other available-for- sale financial instruments net of tax effect Change in the fair value of cash flow hedge derivatives net of tax effect Share of “Other comprehensive income” on equity-accounted entities Total comprehensive income (loss) of the year Transactions with shareholders Dividend distribution of Eni SpA (€0.40 per share in settlement of 2016 interim dividend of €0.40 per share) Interim dividend distribution of Eni SpA (€0.40 per share) Dividend distribution of other companies Allocation of 2016 net loss Other changes in shareholders’ equity Other changes (25) (25) (25) (25) (25) (25) (25) Balance at December 31, 2017 (25) 4,005 (4) (4) 2 (4) (6) 69 61 57 (5,575) (5,575) (5,575) (4) (4) (4) (4) (5,573) (5,573) (4) (6) 69 (5,514) (2,144) 3,374 1,441 (2,881) (1,440) (1,441) (1,441) (4) (6) 69 (5,514) (2,141) 3 (1,440) (1,441) (3) (3) (4,345) (4,345) (56) (56) 35,966 74 74 4,818 4,345 1,464 (2,881) (3) (2,884) 1,889 (581) (1,441) 3,374 18 18 48,030 18 18 48,079 49 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued) 143143 Eni shareholders’ equity s e c n e r e ff d n o i t a i l s n a r t y c n e r r u c e v i t a l u m u C s g n i n r a e d e n i a t e R l a t i p a c e r a h S s e v r e s e r r e h t O s e r a h s y r u s a e r T d n e d i v i d m i r e t n I r a e y e h t r o f t fi o r p t e N l a t o T t s e r e t n i g n i l l o r t n o c - n o N y t i u q e ’ s r e d l o h e r a h s l a t o T 4,005 51,985 9,129 1,173 (581) (1,440) (8,778) (1,464) 55,493 (1,464) 1,916 7 57,409 (1,457) (19) (19) 8 (4) 663 32 699 680 1,190 1,190 1,190 (1,028) (10,630) (11,658) (19) (19) 1,198 (4) 663 32 1,889 406 (1,464) 1,440 (1,852) (1,440) (1,441) (1,441) (19) (19) 1,198 (4) 663 32 1,889 413 (1,440) (1,441) (4) 7 (4) 10,630 8,778 (1) (2,881) (4) (2,885) (8) 48 40 40,367 10,319 (20) (1) (21) 1,832 (581) (1,441) (1,464) (1,872) (1,872) (28) 47 19 53,037 2 (1,870) 49 (28) 49 (1,851) 53,086 (€ milioni) Balance at December 31, 2015 Net profit (loss) for the year Other items of comprehensive income (loss) Items that are not reclassified to profit or (loss) in later periods Remeasurements of defined benefit plans net of tax effect Items that may be reclassified to profit or (loss) in later periods Currency translation differences Change in the fair value of other available-for-sale financial instruments net of tax effect Change in the fair value of cash flow hedge derivatives net of tax effect Share of “Other comprehensive income” on equity-accounted entities Total comprehensive income (loss) of the year Transactions with shareholders Dividend distribution of Eni SpA (€0.40 per share in settlement of 2015 interim dividend of €0.40 per share) Interim dividend distribution of Eni SpA (€0.40 per share) Dividend distribution of other companies Allocation of 2015 net loss Other changes in shareholders’ equity Exclusion from the scope of consolidation of Saipem group following the sale of the control Reclassification to profit and loss account of amounts previously recognized in other comprehensive income related to Saipem Other changes Balance at December 31, 2016 4,005 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018 14 414 4 15 334 642 (238) 879 CONSOLIDATED STATEMENT OF CASH FLOWS (€ million) Net profit (loss) of the year - continuing operations Adjustments to reconcile net profit (loss) to net cash provided by operating activities Depreciation and amortization Net Impairments (reversals) of tangible and intangible assets Write-off of tangible and intangible assets Share of (profit) loss of equity-accounted investments Net gain on disposal of assets Dividend income Interest income Interest expense Income taxes Other changes Changes in working capital: - inventories - trade receivables - trade payables - provisions for contingencies - other assets and liabilities Cash flow from changes in working capital Change in the provisions for employee benefits Dividends received Interest received Interest paid Income taxes paid, net of tax receivables received Net cash provided by operating activities - of which with related parties Investing activities: - tangible assets - intangible assets - consolidated subsidiaries and businesses net of cash and cash equivalent acquired - investments - securities - financial receivables - change in payables in relation to investing activities and capitalized depreciation Cash flow from investing activities Disposals: - tangible assets - intangible assets - consolidated subsidiaries and businesses net of cash and cash equivalent disposed of - tax on disposals - investments - securities - financial receivables - change in receivables in relation to disposals Cash flow from disposals Net cash used in investing activities - of which with related parties Note (11) (12) (13) (11) (12) (14) (31) (31) (32) (36) (11) (12) (26) (14) (26) (36) 2018 4,137 6,988 866 100 68 (474) (231) (185) 614 5,970 (474) 1,632 109 275 87 (609) (5,226) 13,647 (2,707) (8,778) (341) (119) (125) (432) (554) 408 (9,941) 1,089 5 (47) 195 61 496 606 2,405 (7,536) (3,314) (346) 657 284 96 749 2017 3,377 7,483 (225) 263 267 (3,446) (205) (283) 671 3,467 894 1,440 38 291 104 (582) (3,437) 10,117 (2,843) (8,490) (191) (510) (316) (657) 152 (10,012) 2,745 2 2,662 (436) 482 224 999 (434) 6,244 (3,768) (3,115) (273) 1,286 1,495 (1,043) 647 2016 (1,044) 7,559 (475) 350 326 (48) (143) (209) 645 1,936 (9) 2,112 22 212 160 (780) (2,941) 7,673 (3,749) (9,067) (113) (1,164) (1,336) (1,208) (8) (12,896) 19 (362) 508 20 8,063 205 8,453 (4,443) 3,752 CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS 145145 CONSOLIDATED STATEMENT OF CASH FLOWS (continued) (€ million) Increase in long-term financial debt Repayments of long-term financial debt Increase (decrease) in short-term financial debt Dividends paid to Eni’s shareholders Dividends paid to non-controlling interest Net cash used in financing activities - of which with related parties Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries) Effect of cash and cash equivalents pertaining to discontinued operations Effect of exchange rate changes and other changes on cash and cash equivalents Net cash flow of the year Cash and cash equivalents - beginning of the year Cash and cash equivalents - end of the year(a) Note (18) (18) (18) (36) (5) (5) 2018 3,790 (2,757) (713) 320 (2,954) (3) (2,637) 16 18 3,492 7,363 10,855 2017 1,842 (2,973) (581) (1,712) (2,880) (3) (4,595) (16) 7 (72) 1,689 5,674 7,363 2016 4,202 (2,323) (2,645) (766) (2,881) (4) (3,651) (192) (5) 889 2 465 5,209 5,674 (a) Cash and cash equivalents as of December 31, 2018, include €19 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item Assets held for sale in the balance sheet. CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018 146 NOTES ON CONSOLIDATED FINANCIAL STATEMENTS assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below. 1 | Significant accounting policies, estimates and judgements PRINCIPLES OF CONSOLIDATION BASIS OF PREPARATION The Consolidated Financial Statements of the Eni Group have been prepared in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB) and adopted by the European Union (EU) pursuant to article 6 of the EC Regulation No. 1606/2002 of the European Parliament and of the Council of July 19, 2002, and in accordance with article 9 of Legislative Decree No. 38/052. Oil and natural gas exploration and production activity is accounted for in accordance with internationally accepted accounting standards taking into account the applicable IFRS requirements. The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the accounting policies that follow. The 2018 Consolidated Financial Statements, approved by the Eni’s Board of Directors on March 14, 2019, were audited by the external auditor EY SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, EY SpA takes the responsibility of their work. The Consolidated Financial Statements are presented in euro and all values are rounded to the nearest million euros (€ million), except where otherwise indicated. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGEMENTS The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognised in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are based on complex judgements and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, employee benefits and recognition of environmental liabilities. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and SUBSIDIARIES The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns. Subsidiaries are consolidated, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases. Assets, liabilities, income and expenses of consolidated subsidiaries are fully recognised with those of the parent in the Consolidated Financial Statements; the parent’s investment in each subsidiary is eliminated against the corresponding parent’s portion of equity of each subsidiary. Non-controlling interests are presented separately in the balance sheet within equity; the profit or loss attributable to non-controlling interests is presented in a specific line item of the profit and loss account. For entities acting as sole-operator in the management of Oil & Gas contracts on behalf of companies participating in a joint project, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognised directly in the financial statements of the companies involved based on their own share. Some subsidiaries are not consolidated because they are not significant, either individually or in the aggregate; this exclusion has not produced significant3 effects on the Consolidated Financial Statements4. When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the non-controlling interests are adjusted is attributed to Eni shareholders’ equity. Conversely, the sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred net assets; (ii) any gain or loss recognised as a result of the re-measurement of any investment retained in the former subsidiary at its fair value; and (iii) any amount related to the former subsidiary previously recognised (1) IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC). (2) The Consolidated Financial Statements are compliant with IFRSs as issued by the IASB and effective for the year 2018. (3) According to the requirements of the Conceptual Framework for Financial Reporting, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”. (4) Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”; for further information, see the annex “List of companies owned by Eni SpA as of December 31, 2018”. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS147 in other comprehensive income which may be reclassified subsequently to the profit and loss account5. Any investment retained in the former subsidiary is recognised at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria. INTERESTS IN JOINT ARRANGEMENTS Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. In the Consolidated Financial Statements, Eni recognises its share of the assets/liabilities and revenue/expenses of joint operations on the basis of its rights and obligations relating to the arrangements. After the initial recognition, the assets/liabilities and revenue/ expenses of the joint operations are measured in accordance with the applicable measurement criteria. Not significant joint operations are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of any impairment losses. INVESTMENTS IN ASSOCIATES An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”. Investments in subsidiaries, joint arrangements and associates as of December 31, 2018 are presented separately in the annex “List of companies owned by Eni SpA as of December 31, 2018”. This annex includes also the changes in the scope of consolidation. Consolidated companies’ financial statements are audited by external auditors who audit also the information required for the preparation of the Consolidated Financial Statements. THE EQUITY METHOD OF ACCOUNTING Investments in joint ventures, associates and not significant unconsolidated subsidiaries, are accounted for using the equity method6 7. Under the equity method, investments are initially recognised at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s assets/liabilities; if this allocation is provisionally recognised at initial recognition, it can be retrospectively adjusted within one year from the date of initial recognition, to reflect new information obtained about facts and circumstances that existed at the date of initial recognition. Subsequently, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Distributions received from an equity- accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). When there is objective evidence of impairment (e.g. relevant breaches of contracts, significant financial difficulty, probable default of the counterparty, etc.), the recoverability is tested by comparing the carrying amount and the related recoverable amount determined by adopting the criteria indicated in the accounting policy for “Property, plant and equipment”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognised in the profit and loss account within “Other gain (loss) from investments”. The impairment reversal shall not exceed the previously recognised impairment losses. Losses arising from the application of the equity method in excess of the carrying amount of the investment, recognised in the profit and loss account within “Income (Expense) from investments”, reduce the carrying amount of any financing receivables towards the investee for which settlement is neither planned nor likely to occur in the foreseeable future and which are, in substance, an extension of the investment in the investee (the so-called long-term interests). The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognised as a result of the re- measurement of any investment retained in the former joint venture/ associate at its fair value8; and (iii) any amount related to the former joint venture/associate previously recognised in other comprehensive income which may be reclassified subsequently to the profit and loss account9. Any investment retained in the former joint venture/ associate is recognised at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria. The investor’s share of losses of an investee, that exceeds the carrying amount of the investment and any long-term interests, is recognised in a specific provision only to the extent that the investor has incurred legal or constructive obligations or made payments on behalf of the investee. (5) Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity. (6) In the case of step acquisition of significant influence (joint control), the investment is recognised, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity. (7) Joint ventures, associates and not significant unconsolidated subsidiaries are accounted for at cost less any accumulated impairment losses, if this does not result in a misrepresentation of the Company’s financial position and performance. (8) If the retained investment continues to be accounted for using the equity method, no re-measurement at fair value is recognised in the profit and loss account. (9) Conversely, any amount related to the former joint venture/associate previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018148 BUSINESS COMBINATION Business combinations are accounted for by applying the acquisition method. The consideration transferred in a business combination is the sum of the acquisition-date fair value of the assets transferred, the liabilities incurred and the equity interests issued by the acquirer. Acquisition-related costs are accounted for as expenses when incurred. The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values10, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed is recognised, in the balance sheet, as goodwill; conversely, a gain on a bargain purchase is recognised in the profit and loss account. Any non-controlling interests are measured as the proportionate share in the recognised amounts of the acquiree’s identifiable net assets at the acquisition date excluding, hence, the portion of goodwill attributable to them (partial goodwill method); as an alternative, non-controlling interests may be measured at fair value, which means that goodwill includes the portion attributable to them (full goodwill method)11. The choice of measurement basis for goodwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis. In a business combination achieved in stages, the purchase price is determined by summing the acquisition-date fair value of previously held equity interests in the acquiree and the consideration transferred for obtaining control; the previously held equity interests are re-measured at their acquisition-date fair value and the resulting gain or loss, if any, is recognised in the profit and loss account. Furthermore, on obtaining control, any amount recognised in other comprehensive income related to the previously held equity interests is reclassified to the profit and loss account, or in another item of equity when such amount may not be reclassified to the profit and loss account. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognised at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. The acquisition of interests in a joint operation whose activity constitutes a business is accounted for applying the principles on business combinations accounting. Significant accounting estimates and judgements: investments and business combinations The assessment of the existence of control, joint control, significant influence over an investee, as well as for joint operations, the assessment of the existence of enforceable rights and obligations imply that the management makes complex judgements on the basis of the characteristics of the investee’s structure, arrangements between parties and other relevant facts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed, in a business combination, at their acquisition-date fair values. For such measurement, to be performed also for the application of the equity method, Eni adopts the valuation techniques generally used by market participants taking into account the available information; for the most significant business combinations, Eni engages external independent evaluators. INTRAGROUP TRANSACTIONS All balances and transactions between consolidated companies, and not yet realised with third parties, including unrealised profits arising from such transactions have been eliminated. Unrealised profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity. In both cases, unrealised losses are not eliminated unless the transaction provides evidence of an impairment loss of the asset transferred. FOREIGN CURRENCY TRANSLATION The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into euro using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: Reuters - WMR). The cumulative resulting exchange differences are presented in the separate component of the Eni shareholders’ equity “Cumulative currency translation differences”12. Cumulative amount of exchange differences relating to a foreign operation are reclassified to the profit and loss account when the entity disposes the entire interest in that foreign operation or when the partial disposal involves the loss of control, joint control or significant influence over the foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account. The financial statements of foreign operations which are translated into euro are denominated in the foreign operations’ functional currencies which generally is the US dollar. The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below: (10) Fair value measurement principles are described below in the accounting policy for “Fair value measurements”. (11) The choice between partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account. (12) When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognised as part of “Non-controlling interest”. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS149 (currency amount for 1 €) US Dollar Pound Sterling Norwegian Krone Australian Dollar Annual average exchange rate 2018 Exchange rate at December 31, 2018 Annual average exchange rate 2017 Exchange rate at December 31, 2017 Annual average exchange rate 2016 Exchange rate at December 31, 2016 1.18 0.88 9.60 1.58 1.15 0.89 9.94 1.62 1.13 0.88 9.33 1.47 1.20 0.89 9.83 1.53 1.11 0.82 9.29 1.49 1.05 0.86 9.09 1.46 SIGNIFICANT ACCOUNTING POLICIES The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below. OIL AND NATURAL GAS EXPLORATION, APPRAISAL, DEVELOPMENT AND PRODUCTION EXPENDITURE ACQUISITION OF EXPLORATION RIGHTS Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalised within the line item “Intangible assets” as “exploration rights – unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortised, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that can show the existence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognised in the profit and loss account as write-off. Lower value exploration rights are pooled and amortised on a straight- line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. Upon reclassification, as well as whether there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are amortised according to the unit of production method (the so- called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortisation”). ACQUISITION OF MINERAL INTERESTS Costs incurred for the acquisition of mineral interests are capitalised in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows. Acquired exploration potential is measured in accordance with the criteria illustrated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortised according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortisation”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortised until classified as proved reserves; in case of a negative result, it is written-off. EXPLORATION AND APPRAISAL EXPENDITURE Geological and geophysical exploration costs are recognised as an expense as incurred. Costs directly associated with an exploration well are initially recognised within tangible assets in progress, as “exploration and appraisal costs – unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalised in the following 12-month period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalised if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalised costs are recognised in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognised as unproved is reclassified to proved exploration and appraisal costs, within tangible assets in progress. Upon reclassification, as well as whether there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortisation”). DEVELOPMENT EXPENDITURE Development expenditure, including the costs related to unsuccessful and damaged development wells, are capitalised as “Tangible asset in progress – proved”. Development costs are incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the Oil & Gas. They are amortised, from the commencement of production, generally on a UOP basis. When development projects are unfeasible/not carried on, the related costs are written-off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018150 UOP DEPRECIATION, DEPLETION AND AMORTISATION Proved Oil & Gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of Oil & Gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and Oil & Gas reserves. Proved exploration rights and acquired proved mineral interests are amortised over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves. PRODUCTION COSTS Production costs are those costs incurred to operate and maintain wells and field equipment and are recognised as an expense as incurred. PRODUCTION SHARING AGREEMENTS AND BUY-BACK CONTRACTS Oil and gas reserves related to Production Sharing Agreements and buy-back contracts are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the lifted production, against both Cost Oil and Profit Oil, are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above- mentioned accounting policies. The Company’s share of production volumes and reserves includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognise at the same time an increase in the taxable profit, through the increase of the revenue, and a tax expense. DECOMMISSIONING AND RESTORATION LIABILITIES Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalised, consistently with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis. Significant accounting estimates and judgements: oil and natural gas activities Engineering estimates of the Company’s Oil & Gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated Oil & Gas reserves can be categorised as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgement. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such carried costs are reviewed, at least, on an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery. Field reserves will be categorised as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production. Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation, amortisation and depletion charges and impairment charges. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, amortisation and depletion charge using the UOP method. Conversely, a decrease in estimated proved developed reserves increases depreciation, amortisation and depletion charge. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the Oil & Gas activity. In addition, estimated proved reserves are used to calculate future cash flows from Oil & Gas properties, which are used to assess any impairment loss. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment, including investment properties, are recognised using the cost model and stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. For assets that necessarily take a substantial period of time to get ready for their intended use, the purchase price or construction cost comprises the borrowing costs incurred in the period to get the asset ready for use that would have been avoided if the expenditure had not been made. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS151 In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs (a corresponding amount is recognised as part of a specific provision). Changes resulting from revisions to the timing or the amount of the original estimate of the provision are accounted for as described in the accounting policy for “Provisions, contingent liabilities and contingent assets”13. Property, plant and equipment are not revalued for financial reporting purposes. Assets held under finance lease, or under arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards incidental to ownership of the leased asset, are recognised, at the commencement of the lease term, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financing payable to the lessor is recognised. Expenditures on upgrading, revamping and reconversion are recognised as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary for running the business. Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis, using a straight-line method over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company. When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when acquired together with a building. Tangible assets held for sale are not depreciated (see the accounting policy for “Assets held for sale and discontinued operations”). Changes in the asset’s useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, are accounted for prospectively. Assets to be handed over for no consideration are depreciated over the shorter term between the duration of the concession or the asset’s useful life. Replacement costs of identifiable parts in complex assets are capitalised and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Leasehold improvement costs are depreciated over the useful life of the improvements or, if lower, over the residual length of the lease, considering any renewal period if renewal depends entirely on the lessee and is virtually certain. Expenditures for ordinary maintenance and repairs are recognised as an expense as incurred. The carrying amount of property, plant and equipment is reviewed for impairment whenever there is any indication that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the asset’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal. Expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the asset, giving greater weight to external evidence. With reference to commodity prices, management assumes the price scenario adopted for economic and financial projections and for whole life appraisal for capital expenditures. In particular, for the cash flows associated to oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors and is based on management’s planning assumptions, in the short and medium term, takes into account the projections of market analysts and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. Discounting is carried out at a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the expected future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the asset. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined on the basis of a sample of companies operating in the same segment/business, adjusted to take into consideration the risk premium of the specific Country of the activity. For the other segments/businesses, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash-generating unit”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognised in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. The carrying amount of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognised in the profit and loss account. (13) These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing and Chemicals and Gas & Power segments are recognised when the cost is actually incurred and the amount of the liability can be reliably estimated, considering that undetermined settlement dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining & Marketing and Chemicals and Gas & Power segments for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018152 INTANGIBLE ASSETS GRANTS RELATED TO ASSETS Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits. Intangible assets are initially recognised at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with finite useful lives are amortised on a systematic basis over their useful life; the amount to be amortised and the recoverability of the carrying amount are determined in accordance with the criteria described in the accounting policy for “Property, plant and equipment”. Goodwill and intangible assets with indefinite useful lives are not amortised. Their carrying amounts are tested for impairment at least annually and whenever there is any indication of impairment. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal management purposes. When the carrying amount of the cash-generating unit, including goodwill allocated thereto, calculated considering any impairment loss of the non-current assets belonging to the cash-generating unit, exceeds its recoverable amount14, the excess is recognised as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit, up to the recoverable amount of assets with finite useful lives. An impairment loss recognised for goodwill is not reversed in a subsequent period15. Costs of obtaining a contract with a customer are recognised in the balance sheet if the Company expects to recover those costs. The intangible asset arising from those costs is amortised on a systematic basis, that is consistent with the transfer to the customer of the goods or services to which the asset relates, and is tested for impairment16. Costs of technological development activities are capitalised when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits. The carrying amount of intangible assets is derecognised on disposal or when no future economic benefits are expected from its use or disposal; any arising gain or loss is recognised in the profit and loss account. Government grants related to assets are recognised by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received. INVENTORIES Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual selling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost. The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis. When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations, are measured using the pricing formulas contractually defined. They are recognised under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after the settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn – the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realisable value, determined adopting the same criteria described for inventories. Significant accounting estimates and judgements: impairment of non-financial assets Non-financial assets are impaired whenever events or changes in circumstances indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilisation of plants and, for Oil & Gas properties, significant downward revisions of estimated (14) For the definition of recoverable amount see the accounting policy for “Property, plant and equipment”. (15) Impairment losses recognised in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a smaller amount or would not have been recognised. (16) The previous accounting policies required the capitalisation of directly attributable customer acquisition costs when the following conditions are met: (i) the capitalised costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenue from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS153 proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for demand and supply conditions on a global or regional scale. Similar remarks are valid for assessing the physical recoverability of assets recognised in the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses, as well as for assessing the recoverability of deferred tax assets (see also accounting policy for “Income taxes”), which requires complex processes for evaluating the existence of adequate future taxable profit. The expected future cash flows used for impairment analyses are based on judgemental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to Oil & Gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialised analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. FINANCIAL INSTRUMENTS17 FINANCIAL ASSETS Financial assets are classified, on the basis of both contractual cash flow characteristics and the entity’s business model for managing them, in the following categories: (i) financial assets measured at amortised cost; (ii) financial assets measured at fair value through other comprehensive income (hereinafter also OCI); (iii) financial assets measured at fair value through profit or loss. At initial recognition, a financial asset is measured at its fair value; at initial recognition, trade receivables that do not have a significant financing component are measured at their transaction price. After initial recognition, financial assets whose contractual terms give rise to cash flows that are solely payments of principal and interest on the principal amount outstanding are measured at amortised cost if they are held within a business model whose objective is to hold financial assets in order to collect contractual cash flows (the so-called hold to collect business model). For financial assets measured at amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses18 (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account. Conversely, financial assets that are debt instruments are measured at fair value through OCI (hereinafter also FVTOCI) if they are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets (the so-called hold to collect and sell business model). In these cases: (i) interest income determined using the effective interest rate, foreign exchange differences and any impairment losses (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve related to other comprehensive income, is reclassified to the profit and loss account when the financial asset is derecognised. A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is measured at fair value through profit or loss (hereinafter FVTPL); financial assets held for trading fall into this category. Interest income on assets held for trading contributes to the fair value measurement of the instrument and is recognised in “Finance income (expense)”, within “Net finance income (expense) from financial assets held for trading”. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date. IMPAIRMENT OF FINANCIAL ASSETS The expected credit loss model is adopted for the impairment of financial assets that are debt instruments, but are not measured at fair value through profit or loss. In particular, the expected credit losses are generally measured by multiplying: (i) the exposure to the counterparty’s credit risk net of any collateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be recovered in case of default (LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.). With reference to trade and other receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non- financial assets. (17) The accounting policies related to financial instruments were defined on the basis of IFRS 9 “Financial Instruments” effective from 2018; as required by the standard, the new requirements have been applied starting from January 1, 2018 without restating the prior years under comparison. With reference to the financial instruments held by the Company, the previous accounting policies (see 2017 Annual Report on Form 20-F) required essentially: (i) the classification of financial assets on the basis of the categories under IAS 39; (ii) recognition and measurement of impairment losses if there was objective evidence that an impairment loss had been incurred (the so-called incurred loss model); and (iii) more stringent hedge accounting requirements (mainly referred to the assessment of hedge effectiveness). (18) Receivables and other financial assets measured at amortised cost are presented in the balance sheet net of their loss allowance. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018154 For customers without internal credit ratings, the expected credit losses are measured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the basis of their historical credit loss experiences, adjusted, where appropriate, to take into account forward-looking information on credit risk of the counterparty or clusters of counterparties19. Considering the characteristics of the reference markets, financial assets with more than 180 days past due or, in any case, with counterparties undergoing litigation, restructuring or renegotiation, are considered to be in default. Counterparties are considered undergoing litigation when judicial/legal proceedings aimed to recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognised in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net impairment reversals (losses) of trade and other receivables”. The financing receivables held for operating purposes, granted to associates and joint ventures, which in substance form part of the entity’s net investment in these investees, are tested for impairment considering also the underlying industrial operations and the macroeconomic scenarios of the Countries where the investees operate. Significant accounting estimates and judgements: impairment of financial assets Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the existence of any collaterals or other credit enhancements, the expected exposure that will not be recovered in case of default, as well as the definition of customers’ clusters to be adopted. INVESTMENTS IN EQUITY INSTRUMENTS Investments in equity instruments, that are not held for trading, are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognised in the profit and loss account, within the line item “Income (Expense) from investments”. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value. FINANCIAL LIABILITIES At initial recognition, financial liabilities, other than derivative financial instruments, are measured at their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortised cost. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGE ACCOUNTING Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value. With reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging instrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the quantity of the hedged item and the quantity of the hedging instrument (the so-called hedge ratio) consistently with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is adjusted, where appropriate, after taking into account any adequate rebalancing. A hedging relationship is discontinued prospectively, in its entirety or a part of it, when it no longer meets the risk management objectives on the basis of which it qualified for hedge accounting, it ceases to meet the other qualifying criteria or after rebalancing it. When derivatives hedge the risk of changes in the fair value of the hedged items (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured. When derivatives hedge the exposure to variability in cash flows of the hedged items (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the effective changes in the fair value of the derivatives are initially recognised in the equity reserve related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account. If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognised in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”). The changes in the fair value of derivatives, that are not designated as hedging instruments, including any ineffective portion of changes in fair value of hedging derivatives, are recognised in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognised in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognised in the profit and loss account line item “Other operating (expense) income”. Derivatives embedded in financial assets are no longer accounted for separately; in such circumstances, the entire hybrid instrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Derivatives embedded in financial liabilities and/or non-financial assets are separated if: (i) the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract; (ii) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and (iii) the entire hybrid contract is not measured at FVTPL. (19) For exposures arising from intragroup transactions, the recovery rate is assumed equal to 100% taking into account the possibility to provide capital injections of investees. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS155 The entity assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs. Contracts to buy or sell commodities entered into and continue to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognised on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption). OFFSETTING OF FINANCIAL ASSETS AND LIABILITIES Financial assets and liabilities are set off in the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realise the asset and settle the liability simultaneously). DERECOGNITION OF FINANCIAL ASSETS AND LIABILITIES Transferred financial assets are derecognised when the contractual rights to receive the cash flows from the financial assets expire or are transferred to another party. Financial liabilities are derecognised when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired. CASH AND CASH EQUIVALENTS Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due, generally, within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value. PROVISIONS, CONTINGENT LIABILITIES AND CONTINGENT ASSETS A provision is a liability of uncertain timing or amount on the balance sheet date. Provisions are recognised when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount recognised as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties at the balance sheet date. The amount recognised for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognised as “Finance income (expense)”. Where an obligation exists for an item of property, plant and equipment (e.g. site dismantling and restoration), the provision is recognised together with a corresponding amount as part of the related item of property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. A provision for restructuring costs is recognised only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring. Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognised in the same profit and loss account line item where the original provision was charged, or, when the liability regards tangible assets (e.g. site dismantling and restoration), changes in the provision are recognised with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognised in the profit and loss account. Contingent liabilities are: (i) possible, but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognised in the financial statements, but are disclosed. Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognised unless the realisation of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are recognised in the financial statements of the period in which the change occurs. Significant accounting estimates and judgements: decommissioning and restoration liabilities, environmental liabilities and other provisions The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgements with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the Countries where Eni operates, as do political, environmental, safety and public expectations. Where the effect of the time value of money is material, the amount recognised as provision is the present value of the expenditures expected to be required to settle the obligation. After the initial recognition, the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on complex managerial judgements. As other Oil & Gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018156 concerning its Oil & Gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental provisions are recognised when it becomes probable that an outflow of resources will be required to settle the obligation and such obligation can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements. In addition to liabilities related to environmental and decommissioning and restoration liabilities, Eni recognises provisions primarily related to legal, trade and tax proceedings. These provisions are estimated on the basis of complex managerial judgements related to the amounts to be recognised and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate. EMPLOYEE BENEFITS Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment. Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due. The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. Net interest includes the return on plan assets and the interests cost to be recognised in the profit and loss account. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognised in “Finance income (expense)”. Re-measurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognised within the statement of comprehensive income. Re-measurements of the net defined benefit liability, recognised within other comprehensive income, are not reclassified subsequently to the profit and loss account. Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of re-measurements are taken to profit and loss account in their entirety. SHARE-BASED PAYMENTS The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistently with its actual remunerative nature20. The cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognised on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions, the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account. Significant accounting estimates and judgements: employee benefits and share-based payments Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates are based on the market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds) and on the expected inflation rates in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilisation and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved. Differences in the amount of the net defined benefit liability (asset), deriving from the re-measurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. (20) The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS157 Similarly to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plans is measured by using complex valuation techniques and identifying, through structured judgements, the assumptions to be adopted. TREASURY SHARES Treasury shares, including shares held to meet the future requirements of the share-based incentive plans, are recognised as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognised in equity. REVENUE FROM CONTRACTS WITH CUSTOMERS21 Revenue from contracts with customers is recognised on the basis of the following five steps: (i) identifying the contract with the customer; (ii) identifying the performance obligations, that are promises in a contract to transfer goods and/or services to a customer; (iii) determining the transaction price; (iv) allocating the transaction price to each performance obligation on the basis of the relative stand-alone selling prices of each good or service; and (v) recognising revenue when (or as) a performance obligation is satisfied, that is when a promised good or service is transferred to a customer. A promised good or service is transferred when (or as) the customer obtains control of it. Control can be transferred over time or at a point in time. With reference to the most important products sold by Eni, revenue is generally recognised for: - crude oil, upon shipment; - natural gas and electricity, upon delivery to the customer; - petroleum products sold to retail distribution networks, upon delivery to the service stations, whereas all other sales of petroleum products are recognised upon shipment; and - chemical products and other products, upon shipment. Revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers is recognised on the basis of the quantities actually lifted and sold (sales method); costs are recognised on the basis of the quantities actually sold22. Revenue is measured at the fair value of the consideration to which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties. In determining the transaction price, the promised amount of consideration is adjusted for the effects of the time value of money if the timing of payments agreed to by the parties to the contract provides the customer or the entity with a significant benefit of financing the transfer of goods or services to the customer. The promised amount of consideration is not adjusted for the effect of the significant financing component if, at contract inception, it is expected that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. If the consideration promised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events. If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (for example sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the customer that it would not receive without entering into that contract. When goods or services are exchanged for goods or services which are of a similar nature and value, the exchange is not regarded as a transaction which generates revenues. Significant accounting estimates and judgements: revenue from contracts with customers Revenue from sales of electricity and gas to retail customers includes amount accrued for electricity and gas supplied between the date of the last invoiced meter reading (actual or estimated) of volumes consumed and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by the management, which can impact on them. Therefore, revenue is accrued as a result of a complex estimate based on the volumes distributed and allocated, communicated by third parties, likely to be adjusted, according to applicable regulations, within the fifth year following the one in which they are accrued. Considering the contractual obligations on the supply delivery points, revenue from sales of electricity and gas to retail customers includes costs for transportation and dispatching and in these cases the gross amount of consideration to which the entity is entitled is recognised. COSTS Costs are recognised when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, determined on the basis of the market prices, are recognised in relation to the amounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations, are recognised as intangible assets. Revenue related to emission quotas is recognised when they are sold and, if applicable, purchased emission rights are considered the first to be sold. Monetary receivables granted to replace the free award emission rights are recognised as a contra to the line item “Other income and revenues”. Lease payments under an operating lease are recognised as an expense over the lease term. The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalised (see also the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred. (21) The previous accounting policies about revenue are described in the 2017 Annual Report on Form 20-F. (22) In accordance with the previous accounting policy (entitlement method), revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers were recognised on the basis of Eni’s net working interest in those properties. In the balance sheet, lifting imbalances were recognised respectively as payables and receivables and measured at current prices at the balance sheet date. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018158 EXCHANGE DIFFERENCES Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognised. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realisable value are retranslated using the exchange rate at the date when the value is determined. DIVIDENDS Dividends are recognised at the date of the general shareholders’ meeting in which they were declared, except when the sale of shares before the ex-dividend date is certain. INCOME TAXES Current income taxes are determined on the basis of estimated taxable profit. The estimated liability is included in “Income tax payables”. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets and liabilities are recognised for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets are recognised when their recoverability is considered probable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognised to the extent that their recoverability is probable. The carrying amount of the deferred tax assets is reviewed, at least, on an annual basis. Income tax assets that are uncertain in the amount to be recovered are recognised in accordance with the probable threshold. Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognised if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognised in the line item “Deferred tax assets” and, if negative, in the line item “Deferred tax liabilities”. When the results of transactions are recognised directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS Non-current assets and current and non-current assets included within disposal groups are classified as held for sale, if their carrying amounts will be recovered principally through a sale transaction rather than through their continuing use. This condition is regarded as met only when the sale is highly probable and the asset or the disposal group is available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognised in the balance sheet separately from other assets and liabilities. Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities in the disposal group are measured in accordance with applicable IFRSs. Subsequently, non- current assets held for sale are not depreciated or amortised and they are measured at the lower of the fair value less costs to sell and their carrying amount. If an equity-accounted investment, or a portion of that investment, meets the criteria to be classified as held for sale, it is no longer accounted for using the equity method and is measured at the lower of its carrying amount at the date the equity method is discontinued, and its fair value less costs to sell. Any retained portion of the equity-accounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place. After the disposal takes place, any retained interest in the investee is measured in accordance with the measurement criteria indicated in the accounting policy for “Investments in equity instruments”, unless the retained interest continues to be an equity-accounted investment. Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognised up to the cumulative impairment losses, including those recognised prior to qualification of the asset as held for sale. Non-current assets classified as held for sale and disposal groups are considered a discontinued operation if, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognised on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements. If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non- current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortisation, impairment losses and reversals that would have been recognised had the asset or CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS159 disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. If the interruption of a plan of sale concerns a subsidiary, joint operation, joint venture, associate, or a portion of an interest in a joint venture or an associate, financial statements for the period since classification as held for sale are amended. FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximise the value of the asset. The fair value of a liability, both financial and non-financial, or of the Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the Company’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA). In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. Significant accounting estimates and judgements: fair value Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgement and could result in expected values other than the actual ones. 2 | Financial statements23 Assets and liabilities on the balance sheet are classified as current and non-current. Items on the profit and loss account are presented by nature24. Assets and liabilities are classified as current when: (i) they are expected to be realised/settled in the entity’s normal operating cycle or within twelve months after the balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non- hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realised/settled within twelve months after the balance sheet date; on the contrary, they are classified as non-current. The statement of comprehensive income (loss) shows net profit (loss) integrated with income and expenses that are not recognised in the profit and loss account according to IFRSs. The statement of changes in shareholders’ equity includes the total comprehensive income (loss) for the year, transactions with shareholders in their capacity as shareholders and other changes in shareholders’ equity. The statement of cash flows is presented using the indirect method, whereby net profit (loss) is adjusted for the effects of non-cash transactions. 3 | Changes in accounting policies IFRS 15 “Revenue from Contracts with Customers” and the document “Clarifications to IFRS 15 Revenue from Contracts with Customers” (hereinafter IFRS 15), which set out the requirements for recognising and measuring revenue arising from contracts with customers, have been adopted by the Commission Regulations No. 2016/1905 and 2017/1987 issued by the European Commission, respectively, on September 22, 2016 and October 31, 2017. Eni has applied IFRS 15 starting from January 1, 2018, by recognising, in accordance with the transition requirements of the standard, the cumulative effect of initially applying IFRS 15 as an adjustment to the opening balance of equity as of January 1, 2018, taking into account the contracts existing at that date, without restating the comparative information. In particular, the adoption of IFRS 15 resulted in a decrease in equity of €49 million arising from: (i) a negative change of €103 million (€259 million before taxes) in the Exploration & Production segment, related to the accounting for amounts of production lifted by a partner within Oil & Gas operations different from its proportionate entitlement (the so- called lifting imbalances), by recognising revenue on the basis of the quantities actually sold (the so-called sales method) instead of the entitled quantities (the so-called entitlement method); costs are recognised on the basis of the quantities actually sold. Moreover the adoption of sales method resulted in the reclassification of underlifting assets (quantities lifted smaller than the entitled ones) and overlifting liabilities (quantities lifted higher than the entitled ones), represented as (23) The impacts on the financial statements arising from the adoption, starting from January 1, 2018, of the new IFRSs, as well as the other changes in the financial statements are described in the note 3 – Changes in accounting policies. (24) Further information about classification of financial instruments is provided in note 27 – Guarantees, commitments and risks - Other information about financial instruments. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018160 receivables and payables under the entitlement method, into the other assets and liabilities; (ii) a positive change of €60 million (€87 million before taxes), related to the capitalisation of the costs of obtaining contracts with customers in the Gas & Power segment, net of their amortisation; (iii) a negative change of €6 million of equity-accounted investments. IFRS 9 “Financial Instruments” (hereinafter IFRS 9) has been adopted by the Commission Regulation No. 2016/2067 issued by the European Commission on November 22, 2016. Eni has applied IFRS 9 starting from January 1, 2018. As allowed by the transition requirements of the standard, considering also the complexity of the restatement at the beginning of the first comparative year without the use of hindsight, the impacts of the new classification and measurement requirements, including impairment, of financial assets, have been recognised as an adjustment to the opening balance of equity as of January 1, 2018, without restating the comparative information; with reference to hedge accounting, the adoption of the new requirements did not have significant impacts. In particular, the adoption of IFRS 9 resulted in an increase in equity of €294 million arising from the fair value measurement of investments in equity instruments previously measured at cost (€681 million), partially offset by the additional impairment losses (€356 million) of trade and other receivables (€427 million before taxes), recognised under the expected credit loss model and by the decrease of the carrying amount of equity-accounted investments (€31 million). As indicated in the accounting policy for “Investments in equity instruments”, Eni elected to designate the investments in equity instruments, held as of January 1, 2018, as assets measured at FVTOCI. Moreover, with reference to the classification and measurement of financial assets, Eni reclassified the portfolio of financial assets previously classified as available for sale into the financial assets measured at FVTPL (€207 million), on the basis of the facts and circumstances existing as of January 1, 2018. The breakdown of the abovementioned quantitative effects and reclassifications25, deriving from the initial application, as of January 1, 201826, of IFRS 9 and IFRS 15, is as follows: (€ million) Selected line items only Current assets - of which: Financial assets held for trading - of which: Financial assets available for sale - of which: Other current financial assets - of which: Trade and other receivables - of which: Other current assets Non-current assets - of which: Intangible assets - of which: Equity-accounted investments - of which: Other investments - of which: Deferred tax assets Current liabilities - of which: Trade and other payables - of which: Other current liabilities Non-current liabilities - of which: Deferred tax liabilities December 31, 2017 Adoption of IFRS 9 Adoption of IFRS 15 Reclassifications Total effect of the first application As restated January 1, 2018 36,433 6,012 207 316 15,421 1,573 78,172 2,925 3,511 219 4,078 24,735 16,748 1,515 42,027 5,900 (427) (372) (427) (372) 721 (31) 681 71 247 87 (6) 166 (113) (113) 37 37 207 (207) (466) 466 (1,330) 1,330 (799) 207 (207) (1,265) 466 968 87 (37) 681 237 (113) (1,443) 1,330 37 37 35,634 6,219 316 14,156 2,039 79,140 3,012 3,474 900 4,315 24,622 15,305 2,845 42,064 5,937 Shareholders’ equity 48,079 294 (49) 245 48,324 With reference to year 2018, the application of the previous revenue recognition requirements does not have a significant impact on the Consolidated Financial Statements. For each kind of financial assets adjusted/reclassified upon the initial application of IFRS 9, the table below provides for the following information: (i) the original measurement category determined in accordance with IAS 39; (ii) the new measurement category determined in accordance with IFRS 9; (iii) the carrying amounts determined in accordance with IAS 39, recognised as of December 31, 2017, and the carrying amounts determined in accordance with IFRS 9 as of January 1, 2018. (25) Under IFRS 15, short-term advances from customers have been reclassified from the line item “Trade and other payables” into the line item “Other current liabilities” of the balance sheet in order to present them together with the other current contract liabilities (e.g. customer loyalty programs, deferred income, etc.), already recognised within such line item. (26) The IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” is also effective starting from January 1, 2018, but it did not have a significant impact on the Consolidated Financial Statements. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 161 (€ milioni) Financial assets Financial assets held for trading Financial assets available for sale Trade and other receivables(**) Other investments Total Classification under IAS 39 Classification under IFRS 9 Carrying amount under IAS 39 Adjustments Reclassifications Other changes(*) Carrying amount under IFRS 9 Held for trading Available-for-sale Financing receivables Cost FVTPL FVTPL Amortized cost FVTOCI 6,012 207 15,421 219 21,859 (427) 681 254 207 (207) 6,219 14,156 900 21,275 (838) (838) (*) Other changes result from the effects related to a different classification under IFRS 15 of receivables for underlifting which have been reclassified as other assets in application of the sales method. (**) Compared to the values presented in the balance sheet at December 31, 2017, the item no longer includes financial receivables, which have been reclassified under the new item “Other current financial assets”. The adoption of the new requirements resulted in some updates of the line items presented in the financial statements; in particular: - in the profit and loss account: (i) as a consequence of the adoption of IFRS 9, an additional line item to present separately impairment losses/reversals of trade and other receivables (named “Net (impairment losses) reversals of trade and other receivables”) was presented; these items were previously recognised within the line item “Purchases, services and other”. Consequently, in order to have homogeneous comparative information, these items referred to the comparative years, determined in accordance with the superseded IAS 39, were reclassified into the new line item; and (ii) the line item “Net (impairments) reversals” was renamed as “Net (impairment losses) reversals of tangible and intangible assets”; in the statement of comprehensive income (loss) an additional line item aimed to present subsequent change of minor investments measured at fair value with effects recognised in OCI was presented within items that may not be reclassified subsequently to the profit and loss account. - Furthermore, the following changes have been made in the balance sheet: - the current financing receivables were reclassified out of the line item “Trade and other receivables” into the new line item “Other current financial assets”, both in the current and comparative year; this new presentation of the balance sheet was aimed, essentially, to present separately the trade and other exposures from the financial ones, being characterised by different originations, risk profiles and evaluation processes; - the breakdown of the items of Eni shareholders’ equity was updated to present separately the related most relevant items. 4 | IFRSs not yet effective IFRSs ISSUED BY THE IASB AND ADOPTED BY THE EU By the Commission Regulation No. 2017/1986 issued by the European Commission on October 31, 2017, IFRS 16 “Leases” (hereinafter IFRS 16), which replaces IAS 17 and related interpretations, was adopted. In particular, IFRS 16 defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ - - financial statements; in particular, for all leases that have a lease term of more than 12 months, it is required: - in the balance sheet, to recognise a right-of-use asset, that represents a lessee’s right to use an underlying asset (hereinafter also RoU asset), and a lease liability, that represents the lessee’s obligation to make the contractual lease payments; as allowed by the standard, the right-of-use assets and the lease liabilities are presented separately from other assets and other liabilities; in the profit and loss account, to recognise, within operating costs, the depreciation charges of the right-of-use asset and, within finance expense, the interest expense on the lease liability, if not capitalised, rather than recognising the operating lease payments within operating costs under IAS 17, effective until year 2018. The depreciation charges of the right-of-use asset and the interest expense on the lease liability directly attributable to the construction of an asset are capitalised as part of the cost of such asset and subsequently recognised in the profit and loss account through depreciation, impairments or write-off, mainly in the case of exploration assets. Moreover, the profit and loss account will include: (i) the lease expenses relating to short-term leases or leases of low-value assets, as allowed under the simplified approach provided for by IFRS 16; and (ii) the variable lease payments that are not included in the measurement of the lease liability (e.g., payments based on the use of the underlying asset); in the statement of cash flows, to recognise cash payments for the principal portion of the lease liability within the net cash used in financing activities and interest expenses within the net cash provided by operating activities, if they are recognised in the profit and loss account, or within the net cash used in investing activities if they are capitalised as referred to leased assets that are used for the construction of other assets. Consequently, compared with the requirements of IAS 17 related to operating leases, the adoption of IFRS 16 will result in a significant impact in the statement of cash flows, by determining: (a) an improvement of the net cash provided by operating activities, which will no longer include the operating lease payments, not capitalised, but will only include the cash payments for the interest portion of the lease liability that are not capitalised27; (b) an improvement of the net cash used in investing activities, which will no longer include capitalised lease payments for property, plant and equipment and intangible assets, but will only include cash payments for the capitalised interest portion of the lease liability; and (c) a worsening in the net cash used in financing activities, which will include cash payments for the principal portion of the lease liability. (27) The net cash provided by operating activities will include also: (i) the short-term lease payments and payments for leases of low-value assets; and (ii) variable lease payments not included in the measurement of the lease liability. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 162 Conversely, a lessor continues to classify its leases as either operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and for lessors. IFRS 16 shall be applied for annual reporting periods beginning on or after January 1, 2019. In 2018, the Group completed the analytical activities aimed to identify the areas affected by the adoption of the new requirements, update the processes and systems and assess the expected impacts on the Consolidated Financial Statements. The adoption of the new requirements affects most of the Group companies; in terms of amounts and/or volumes, the main cases are the following: (i) in the Exploration & Production segment, contracts for the lease of drilling rigs and floating production storage and offloading vessels (the so-called FPSOs); (ii) in the Refining & Marketing and Chemicals segment, highway concessions, leases of lands, service stations for the sale of oil products, as well as car fleet dedicated to the car sharing business (enjoy); (iii) in the Gas & Power segment, leases of vessels used for shipping activities and gas distribution facilities, as well as tolling contracts; (iv) for corporate activities, leases of property. In the Exploration & Production segment, the activities are often carried out through unincorporated joint operations, managed by one of the partners (the operator), which has the responsibility to carry out the operations and the approved work programmes. The operator usually enters into a contract (including lease contracts), as the sole signatory, for the activities of the unincorporated joint operation. Accordingly, the operator manages the leases, makes lease payments to the lessor and recharges the costs to the other partners (the so-called followers) proportionally. On this regard, the indications of the IFRS Interpretations Committee (hereinafter also the IFRIC) issued in September 2018 applies. In particular, the IFRIC indicated that, in the case of unincorporated joint operations, the operator recognises the entire lease liability, as, by signing the contract, it has primary responsibility for the liability towards the third-party supplier. Therefore, if, based on the contractual provisions and any other relevant facts and circumstances, Eni has primary responsibility, it shall recognise in the balance sheet: (i) the entire lease liability and (ii) the entire RoU asset, unless there is a sublease with the followers. On the other hand, if the lease contract is signed by all the partners, Eni shall recognise its share of the RoU asset and lease liability based on its working interest. If Eni does not have primary responsibility for the lease liability, it does not recognise any RoU asset or lease liability related to the lease contract. The followers’ share of the RoU asset, recognised by the operator, will be recovered according to the joint operation’s arrangements by billing the project costs attributable to the followers and collecting the related cash calls. Costs recovered from the followers are recognised as “Other income and revenues” in the profit and loss account and as net cash provided by operating activities in the statement of cash flows. The IFRIC indications have been confirmed at its March 2019 meeting. The complexity of the contracts, as well as their multiannual duration, has required a complex judgement by management to determine the assumptions to be applied in order to estimate the expected impacts deriving from the adoption of the new requirements. In particular, the main assumptions were the following ones: - for lease contracts related to assets used in the Oil & Gas operations (mainly drilling rigs and FPSOs) set out as operator of the Oil & Gas activities, the recognition of 100% of the lease liability and the right-of-use asset in line with the indications provided by the IFRIC. When the lease contracts are set out by companies, other than subsidiaries, that act as operators on behalf of the other participating companies (the so-called operating companies), consistently with the provision to recover from the followers the costs related to the Oil & Gas activities, the participating companies recognise their shares of the right-of-use assets and the lease liabilities based on their working interest, considering any available information on the expected use of the underlying assets; - the separation of non-lease components, also on the basis of in-depth analyses performed with external experts, with reference to the main contracts related to the upstream activities (drilling rigs) which provide for single payments relating to both lease and non-lease components; - the assessment of extension or termination options in order to determine the lease term; - the identification of variable lease payments and their characteristics in order to establish whether or not28 they shall be included in the measurement of the lease liability and the right-of- use asset; - the discount rate used to measure the lease liability that is the lessee’s incremental borrowing rate. This rate have been defined considering the lease term of the lease contracts, the currencies and the characteristics of the lessees’ economic environment, defined on the basis of the country risk premium assigned to each Country where Eni operates. On initial application, Eni elects to apply the following practical expedients allowed by the accounting standard: - possibility to adopt the modified retrospective approach, by recognising the cumulative effect of initially applying the new standard as an adjustment to the opening balance at January 1, 2019, without restating the comparative information; - possibility not to reassess each contract existing at January 1, 2019, by applying IFRS 16 to all contracts previously identified as leases (under IAS 17 and IFRIC 4), while not applying IFRS 16 to the contracts that were not previously identified as leases; - for contracts previously classified as operating leases, possibility to measure the right-of-use asset at an amount equal to the lease liability, adjusted, if necessary, by any prepaid amounts already recognised in the balance sheet; - as an alternative to performing an impairment review, possibility to adjust the right-of-use assets, existing at January 1, 2019, by the amount of any provision for onerous lease contracts recognised at December 31, 2018; - upon transition, election not to consider leases for which the lease term ends within 12 months of January 1, 2019 as short-term leases. Based on the available information, the adoption of IFRS 16 results in the recognition of right-of-use assets for €5.7 billion and lease liabilities for €5.8 billion; the estimated amount of the lease liabilities includes the payables for lease fees outstanding at January 1, 2019, previously classified as trade payables. The estimated impacts of the initial adoption of IFRS 16 might be (28) Under IFRS 16, variable lease payments linked to future sales or use of an underlying asset are recognised in the profit and loss account and so they are not included in the measurement of the lease liability/right-of-use asset. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS163 subject to change due to any evolution in the interpretations deriving, among others, from further IFRIC indications, as well as due to the development of the data process upon initial adoption of the standard in the 2019 financial reports. Moreover, the estimated amount of the lease liabilities includes the share of the lease liabilities corresponding to the followers’ working interest for €2.0 billion, while the Eni working interest is €3.8 billion. Based on the currently available information, a reconciliation between the amount of future minimum lease payments under non-cancellable operating leases at December 31, 2018 and the opening balance of the lease liability at January 1, 2019 is provided below: (€ billion) Future minimum lease payments under non-cancellable operating leases at December 31, 2018 - Recognition of the shares of leases related to followers - Effect of discounting - Extension options - Other changes Lease liability at January 1, 2019 4.0 2.0 (1.5) 1.2 0.1 5.8 By the Commission Regulation No. 2018/1595 issued by the European Commission on October 23, 2018, IFRIC 23 “Uncertainty over Income Tax Treatments” (hereinafter IFRIC 23) was adopted. IFRIC 23 clarifies the accounting for (current and/or deferred) tax assets and liabilities when there is uncertainty over income tax treatments. IFRIC 23 shall be applied for annual reporting periods beginning on or after January 1, 2019. By the Commission Regulation No. 2019/237 issued by the European Commission on February 8, 2019, the amendments to IAS 28 “Long- term Interests in Associates and Joint Ventures” (hereinafter the amendments to IAS 28) were adopted. The amendments to IAS 28 clarify that entities account for long-term interests in an associate or joint venture, that, in substance, form part of the entity’s net investment in the investee and for which settlement is neither planned nor likely to occur in the foreseeable future, using the provisions of IFRS 9, including those related to impairment. The amendments to IAS 28 shall be applied for annual reporting periods beginning on or after January 1, 2019. By the Commission Regulation No. 2019/402 issued by the European Commission on March 13, 2019, the amendments to IAS 19 “Plan Amendment, Curtailment or Settlement” (hereinafter the amendments to IAS 19) were adopted. The amendments to IAS 19 require to use updated actuarial assumptions to determine current service cost and net interest, when an amendment, curtailment or settlement to an existing defined benefit pension plan takes place, for the remainder reporting period after the change of the plan. The amendments to IAS 19 shall be applied for annual reporting periods beginning on or after January 1, 2019. IFRSs ISSUED BY THE IASB AND NOT YET ADOPTED BY THE EU On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts” (hereinafter IFRS 17), which sets out the accounting for the insurance contracts issued and the reinsurance contracts held. IFRS 17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for annual reporting periods beginning on or after January 1, 2021. On March 29, 2018, the IASB issued the document “Amendments to References to the Conceptual Framework in IFRS Standards”, which includes, basically, technical and editorial changes to existing IFRS standards in order to update references in those standards to previous versions of the IFRS Framework with the new Conceptual Framework for Financial Reporting, issued by the IASB on the same date. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2020. On October 22, 2018, the IASB issued the amendments to IFRS 3 “Business Combinations” (hereinafter the amendments to IFRS 3), which clarify the definition of a business. The amendments to IFRS 3 shall be applied for annual reporting periods beginning on or after January 1, 2020. On October 31, 2018, the IASB issued the amendments to IAS 1 and IAS 8 “Definition of Material” (hereinafter the amendments to IAS 1 and IAS 8), which clarify, and align across all IFRS Standards and other publications, the definition of material to help companies make better materiality judgements. In particular, information is material if omitting, misstating or obscuring it could be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements. The amendments to IAS 1 and IAS 8 shall be applied for annual reporting periods beginning on or after January 1, 2020. On December 12, 2017, the IASB issued the document “Annual Improvements to IFRS Standards 2015-2017 Cycle”, which includes, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual reporting periods beginning on or after January 1, 2019. Eni is currently reviewing the IFRSs not yet effective in order to determine the likely impact on the Consolidated Financial Statements. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018164 5 | Cash and cash equivalents Cash and cash equivalents of €10,836 million (€7,363 million at December 31, 2017) included financial assets with maturity generally of up to three months at the date of inception amounting to €8,732 million (€5,591 million at December 31, 2017) and mainly included short-term deposits with financial institutions having notice of more than 48 hours. Cash and cash equivalents consist essentially of bank deposits in euro and US dollars as a way to employ the Group cash on hand with a view of funding the Group’s short-term financing needs. The average maturity of bank deposits in euro of €7,653 million was 29 days and the interest rate of return was a negative 0.29%; the average maturity of bank deposits in US dollars of €1,074 million was 12 days with an internal rate of return of 2.59%. 6 | Financial assets held for trading (€ million) Quoted bonds issued by sovereign states Other December 31, 2018 1,083 5,469 6,552 December 31, 2017 1,022 4,990 6,012 From January 1, 2018, financial assets held by the Group captive insurance company Insurance DAC of €207 million, previously classified as available for sale, have been classified as held for trading in accordance to the provisions of IFRS 9 on the base of the conditions existing at the adoption date. The Company has established a liquidity reserve as part of its internal targets and financial strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the financial optimization of returns, within a predefined and authorized level of risk tolerance, targeting the preservation of the invested capital and the ability to promptly convert it into cash. Financial assets held for trading of Eni SpA include securities subject to lending agreements of €1,301 million (€845 million at December 31, 2017). The breakdown by currency is provided below: (€ million) Euro US dollars Other currencies December 31, 2018 4,573 1,614 365 6,552 December 31, 2017 4,232 1,025 755 6,012 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS The breakdown by issuing entity and credit rating is presented below: Quoted bonds issued by sovereign states Fixed rate bonds Italy Other(*) Floating rate bonds Italy Other(*) Total quoted bonds issued by sovereign states Other Bonds Fixed rate bonds Quoted bonds issued by industrial companies Quoted bonds issued by financial and insurance companies Other Floating rate bonds Quoted bonds issued by financial and insurance companies Quoted bonds issued by industrial companies Other Total other bonds Total other financial assets held for trading (*) Individual amounts included herein are lower than €50 million. 165 ’ s y d o o M g n i t a R P & S g n i t a R Baa3 from Aaa to Baa3 BBB from AAA to BBB- Baa3 from Aaa to Baa3 BBB from AAA to BBB- from Aa2 to Baa3 from Aaa to Baa3 from A1 to Baa3 from AA to BBB- from AAA to BBB- from A+ to BBB- from Aaa to Baa3 from Aa2 to Baa2 from Aa3 to Baa3 from AAA to BBB- from AA to BBB from AA- to BBB- e u l a v l i a n m o N ) n o i l l i m € ( 523 336 859 130 86 216 1,075 1,628 1,270 51 2,949 1,562 987 158 2,707 5,656 6,731 e u l a v r i a F ) n o i l l i m € ( 529 349 878 129 76 205 1,083 1,581 1,269 48 2,898 1,453 976 142 2,571 5,469 6,552 The fair value hierarchy is level 1 for €6,362 million and level 2 for €190 million. During 2018, there were no transfers between the different hierarchy levels of fair value. 7 | Trade and other receivables As of January 1, 2018, the effects of the application of IFRS 9 and IFRS 15 are the following: (€ million) Amount as of 31 December 2017 Changes in accounting policies (IFRS 9) Changes in accounting policies (IFRS 15) Reclassification to other current asssets (IFRS 15) Amount as of 1 January 2018 Trade and other receivables 15,421 (427) (372) (466) 14,156 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 166 The adoption of IFRS 9 determined an increase in the provision for doubtful accounts of €427 million in application of the expected loss model. The application of IFRS 15 determined a decrease in Other receivables for €372 million due to the fact that Eni now adopts the sales method versus the entitlement method previously adopted under the previous accounting policy as disclosed in note 3 – Changes in accounting policies. In applying IFRS 15, €466 million of assets related to lifting imbalances accounted for using the sales method have been reclassified to other current assets. More information about the application of IFRS 9 and IFRS 15 is disclosed in note 3 – Changes in accounting policies. The following is the analysis of trade and other receivables: (€ million) Trade receivables Receivables from divestments Receivables from joint operators in E&P activities Other receivables December 31, 2018 9,520 122 3,024 1,435 14,101 December 31, 2017 10,182 597 3,369 1,273 15,421 Generally, trade receivables do not bear interest and provide payment terms within 180 days. Trade receivables decreased by €662 million, of which €641 million related to the Gas & Power segment. At December 31, 2018, Eni sold without recourse trade receivables due in 2019 for €1,769 million (€2,051 million at December 31, 2017 due in 2018). Derecognized receivables related to the Gas & Power segment for €1,419 million and to the Refining & Marketing and Chemicals segment for €350 million. Receivables from divestments decreased by €475 million due to: (i) the collection of the price installments related the sale of 10% and 30% interests in the Zohr asset in Egypt made in 2017 respectively to BP and Rosneft for a total amount of €433 million. An additional installment relating to the transaction with BP will be collected in June 2019 (€119 million); (ii) the collection for €153 million of the third and last instalment of a receivable on the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas. Amounts receivable from operators in exploration and production projects included amounts owed by partners in Nigeria for €977 million (€1,507 million at December 31, 2017). This latter comprised an amount of €681 million in large part overdue (€713 million at December 31, 2017) owed by the Nigerian national oil company NNPC in respect of the contractual recovery of the expenditures incurred at certain projects operated by Eni. During the year, the Company recovered €140 million of the overdue amount due to the implementation of the “Repayment Agreement” agreed with the counterparty, whereby Eni is to be reimbursed through the sale of the profit oil attributable to NNPC in certain rig-less petroleum initiatives with low mineral risk. Based on Eni’s Brent price scenario, the reimbursement will be accomplished over a time horizon of three to five years. The overdue receivables are stated net of a discount factor. In addition, a receivable relating to the recovery of a disputed amount of expenditures due to the same counterpart was completely written down (€153 million at December 31, 2017). Receivables from others comprised the recoverable value amounting to €300 million of certain overdue trade receivables towards the state-owned oil company of Venezuela, PDVSA, in relation to gas equity volumes supplied by the joint venture Cardón IV, equally participated by Eni and Repsol in 2016 and in 2018. The two shareholders purchased those receivables from the venture. The proceeds from the sale were utilized to reimburse part of the financing loan provided by the same shareholders to fund the development of the gas project reserves. The recoverable amount of those receivables was estimated considering the lifetime expected credit losses which were evaluated based on a financial model built around empirical evidence and outcomes from a thorough review of sovereign defaults. Risks associated with the complex financial outlook of the Country and the deteriorated operating environment were appreciated in the recoverability estimation by assuming a deferral in the timing of collection of future revenues and overdue credit amounts. Trade and other receivables stated in euro and US dollars amounted to €7,100 million and €6,119 million, respectively. Credit risk exposure and expected losses relating to trade and other receivables has been prepared on the basis of internal ratings as follows: (€ million) December 31, 2018 Business customers National Oil Companies and public administrations Other counterparties Gross amount Allowance for doubtful accounts Net amount Expected loss (% net of counterpart risk mitigation factors) Performing receivables Low risk Medium Risk High Risk Defaulted receivables Eni gas e luce customers 2,454 1,292 1,494 5,240 (9) 5,231 0.2 3,585 157 77 3,819 (3) 3,816 0.1 1,152 672 156 1,980 (44) 1,936 2.6 1,350 2,217 271 3,838 (2,237) 1,601 62.5 2,374 2,374 (857) 1,517 36.1 Total 8,541 4,338 4,372 17,251 (3,150) 14,101 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 167 Eni has classified its business customers and the associated commercial or industrial exposures based on an individual assessment of the credit and the counterparty risks. Business customers other than National Oil Companies (NOC) and public administrations, each of whom has undergone an individual credit evaluation, have assigned a probability of default calculated based on internal ratings which factor in: (i) a full assessment of each customer profitability, financial condition and liquidity and business a financial prospects on an ongoing basis; (ii) history of the contractual relationship (timeliness in invoice payment, number of claims, etc.); (iii) presence of mitigation factor of credit risk (e.g. securitization package, insurance against the credit risk, guarantee from third parties, etc.); (iv) other specialized pieces of information obtained by the Company’s business commercial function or by specialized info-providers; (v) industrial and market trends. Internal ratings and the probability of default are constantly updated by means of back-testing analysis and risk assessment of the current credit portfolio. The loss given default associated with those industrial customers is estimated by the business based on the past experience in credit recoverability; in the case of defaulting customers, loss given default is estimated based on the recovery rates obtained in situations of credit restructurings or litigation procedures. The probability of default associated with NOCs and public administrations is estimated based on the country risk premium incorporated in the risk-adjusted weighted average cost of capital utilized by the Company to perform the impairment review of its fixed assets. The loss given default of these business partners is estimated based on historical averages of delays in collecting overdue receivables, substantially assessing the time value of money. The resulting loss given default is adjusted to factor in any existing mitigation factors. In case of particular market conditions or sovereign defaults, the expected loss associated with NOCs is re-rated based on the empirical evidence and outcomes obtained from restructuring of sovereign debts considering the specificities of trading relationships with energy companies. Customers of Eni gas e luce have been grouped into homogeneous clusters with different credit risk and probability of default which have been estimated based on past experience on credit collection, systematically updated and, in case of particular market conditions, adjusted to take into account expected market and credit trends in any given cluster. The exposure to credit risk and expected losses relating to retail customers of Eni gas e luce was assessed on the basis of a provision matrix as follows: (€ million) December 31, 2018 Customers - Eni gas e luce: - Retail - Middle - Other Gross amount Allowance for doubtful accounts Net amount Expected loss (%) Not-past due from 0 to 3 months from 3 to 6 months from 6 to 12 months over 12 months Ageing 575 449 207 1,231 (20) 1,211 1.6 49 43 2 94 (18) 76 19.1 34 13 1 48 (18) 30 37.5 64 29 2 95 (56) 39 58.9 554 349 3 906 (745) 161 82.2 Total 1,276 883 215 2,374 (857) 1,517 36.1 Trade and other receivables are stated net of the valuation allowance for doubtful accounts which has been determined considering the counterparty risk mitigation factors amounting to €3,072 million: (€ million) Carrying amount at December 31, 2017 Changes in accounting policies (IFRS 9) Carrying amount at January 1, 2018 Additions on trade and other performing receivables Additions on trade and other defaulted receivables Deductions on trade and other performing receivables Deductions on trade and other defaulted receivables Other changes Carrying amount at December 31, 2018 Carrying amount at December 31, 2016 Additions Deductions Other changes Carrying amount at December 31, 2017 Trade and other receivables 2,639 427 3,066 126 372 (189) (532) 307 3,150 2,303 927 (454) (137) 2,639 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 168 Additions to allowance for doubtful accounts on trade and other performing receivables related for €108 million to the Gas & Power segment, particularly in the retail business. Additions to allowance for doubtful accounts on trade and other defaulted receivables related for €291 million to the Exploration & Production segment and in connection with receivables for the supply of equity hydrocarbons to State-owned companies and other commercial partners. Utilizations of allowance for doubtful accounts on trade and other performing and defaulted receivables amounted to €721 million and mainly related to the Gas & Power segment for €613 million, in particular utilizations against charges of €579 million mainly in the retail business. The mitigation measures regarding the counterparty risk executed by the Company, including better customer selection, allowed to reduce the incidence of unpaid amounts on retail sales of gas and power to physiological levels. Net (impairment losses) reversals of trade and other receivables are disclosed as follows: (€ million) Net (impairment losses) reversals of trade and other receivables New or increased provisions Credit losses Reversal of unutilized provisions 2018 (498) (37) 120 (415) The following is the analysis of the 2017 ageing of trade and other receivables stated according to the valuation criteria in force before the application of IFRS 9 “Financial instruments”: (€ million) Neither impaired nor past due Impaired (net of the valuation for doubtful accounts) Not impaired and past due: - within 90 days - from 3 to 6 months - from 6 to 12 months - over 12 months December 31, 2017 Trade receivables Other receivables 8,800 567 478 46 147 144 815 10,182 4,604 31 21 9 202 372 604 5,239 Because of the short-term maturity and conditions of remuneration of trade and other receivables, the fair value approximated the carrying amount. Receivables with related parties are disclosed in note 36 – Transactions with related parties. 8 | Non-current and current inventories (€ million) Raw and auxiliary materials and consumables Materials and supplies Finished products and goods Certificates and emission rights December 31, 2018 889 1,451 2,274 37 4,651 December 31, 2017 999 1,566 2,000 56 4,621 Raw and auxiliary materials and consumables include oil-based feedstock, catalysts and other consumables pertaining to refining and chemical activities. Materials and supplies include materials to be consumed in drilling activities and spare parts related to the Exploration & Production segment for €1,334 million (€1,441 million at December 31, 2017). Finished products and goods included gas and petroleum products for €1,543 million (€1,287 million at December 31, 2017) and chemical products for €547 million (€489 million at December 31, 2017). Certificates and emission rights are measured at the fair value. The fair value hierarchy is level 1. Inventories of €95 million (€86 million at December 31, 2017) were CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 169 pledged to guarantee the estimated imbalance in volumes input to/off- taken from the national gas network operated by Snam Rete Gas SpA. Inventories are stated net of a write down provision of €578 million (€245 million at December 31, 2017). Net additions to write down provision for 2018 amounted to €337 million and primarily related to the alignment of the carrying amount of crude oil and oil products inventories to their net realizable values at the period end, as a consequence of the rapid decline in hydrocarbons prices recorded in the final months of 2018. Inventories held for compliance purposes of €1,217 million (€1,283 million at December 31, 2017) primarily related to Italian subsidiaries for €1,200 million (€1,267 million at December 31, 2017) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws. 9 | Current income tax receivables and payables (€ million) Income taxes Other taxes and duties December 31, 2018 December 31, 2017 Receivables 191 561 752 Payables 440 1,432 1,872 Receivables 191 729 920 Payables 472 1,472 1,944 Income taxes are described in note 32 – Income tax expense. Receivables for other taxes and duties included VAT credits for €383 million (€452 million at December 31, 2017) in relation to down payments by Italian subsidiaries made in December. Payables for other taxes and duties consisted of excise and custom duties of €636 million (€824 million at December 31, 2017). 10 | Other assets (€ million) Fair value of derivative financial instruments Other current assets December 31, 2018 Current 1,594 664 2,258 Non-current 68 724 792 December 31, 2017 Current 1,231 342 1,573 Non-current 80 1,243 1,323 The fair value related to derivative financial instruments is disclosed in note 23 – Derivative financial instruments. The increase in other assets of €322 million included the reclassification as of January 1, 2018, from the item Trade and other receivables of the underlifting imbalances related to the Exploration & Production segment for €466 million following the adoption of the sales method in application of IFRS 15. Other assets include: (i) non-current tax assets for € 422 million (€507 million at December 31, 2017); (ii) gas volumes prepayments that were made in previous years due to the take-or-pay obligations in relation to the Company’s long-term supply contracts of €26 million (€119 million at 31 December 2017); (iii) non-current receivables from others for €35 million (€44 million at December 31, 2017); (iv) non-current receivables for investing activities for €9 million (€118 million at December 31, 2017). Transactions with related parties are described in note 36 – Transactions with related parties. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018170 11 | Property, plant and equipment (€ million) 2018 Net carrying amount - beginning of the year Additions Depreciation Reversals Impairments Write-off Disposals Currency translation differences Decrease through loss of control of subsidiary Transfers Other changes Net carrying amount - end of the year Gross carrying amount - end of the year Provisions for depreciation and impairments 2017 Net carrying amount - beginning of the year Additions Depreciation Reversals Impairments Write-off Disposals Currency translation differences Transfers Other changes Net carrying amount - end of the year Gross carrying amount - end of the year Provisions for depreciation and impairments s g n i d l i u b d n a d n a L 1,313 18 (65) 41 (61) (2) 2 1 81 (54) 1,274 4,060 2,786 1,258 22 (71) 5 (2) (15) (5) 84 37 1,313 4,061 2,748 t n a l p , s l l e w P & E y r e n i h c a m d n a 45,782 432 (6,012) 299 (477) (12) (400) 1,623 (4,388) 6,795 (786) 42,856 135,467 92,611 47,090 42 (6,583) 608 (491) (3) 3 (5,155) 9,940 331 45,782 137,223 91,441 d n a t n a l p r e h t O y r e n i h c a m 3,877 173 (529) 86 (73) (1) (9) 36 32 461 (152) 3,901 27,516 23,615 3,789 190 (545) 273 (83) (2) (6) (143) 629 (225) 3,877 26,746 22,869 l a s i a r p p a d n a s t e s s a n o i t a r o l p x e P & E s t e s s a e l b i g n a t P & E s s e r g o r p n i s s e r g o r p n i s t e s s a e l b i g n a t r e h t O s e c n a v d a d n a 1,371 330 9,469 6,947 (66) (32) 53 (58) (294) (37) 1,267 1,267 1,905 351 (232) (193) (265) (195) 1,371 1,371 (548) (4) (198) 385 (474) (6,501) 119 9,195 12,559 3,364 15,135 7,302 169 (146) (2) (1,376) (1,527) (9,673) (413) 9,469 12,315 2,846 1,346 878 (117) (1) 2 (1) 10 (542) 234 1,809 2,415 606 1,616 583 (126) (54) (2) (715) 44 1,346 2,061 715 l a t o T 63,158 8,778 (6,606) 426 (1,276) (84) (639) 2,098 (4,877) (676) 60,302 183,284 122,982 70,793 8,490 (7,199) 1,055 (848) (239) (1,448) (7,025) (421) 63,158 183,777 120,619 Capital expenditures included capitalized finance expenses of €52 million (€72 million in 2017) related to the Exploration & Production segment (€37 million). The interest rate used for capitalizing finance expense ranged from 2.3% to 2.4% (1.6% to 2.7% at December 31, 2017). Capital expenditures primarily related to the Exploration & Production segment for €7,757 million (€7,638 million in 2017) and included the consideration paid for the award of the interests in the already producing Concession Agreements of Umm Shaif and Nasr (10%) and Lower Zakum (5%) and the Concession Agreement of Gasha (25%) under development, located in the offshore of Abu Dhabi (United Arab Emirates). The price paid of €869 million was allocated to proved mineral interest (E&P wells, plant and machinery) for €382 million and to unproved mineral interest for (E&P tangible assets in progress) €487 million. More information is reported in note 35 – Segment information and information by geographical area. The main depreciation rates used were substantially unchanged from the previous year and ranged as follows: (%) Buildings Mineral exploration wells and plants Refining and chemical plants Gas pipelines and compression stations Power plants Other plant and machinery Industrial and commercial equipment Other assets 2 - 10 UOP 2 - 17 2 - 12 5 6 - 12 5 - 25 10 - 20 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 171 The criteria adopted by Eni for determining net (impairments) reversals is reported in note 13 – Net reversal (impairment) of tangible and intangible assets. Disposals related to a 10% interest in the Zohr asset in Egypt to Mubadala Petroleum Llc with a gain of €418 million. Foreign currency translation differences primarily related to subsidiaries which utilize the US dollar as functional currency (€2,209 million). Property, plant and equipment decreased by €4,800 million due to the exclusion from the consolidation of the assets of the former Eni’s subsidiary Eni Norge AS which was merged with Point Resources AS, fully-owned by HitecVision AS, to establish the equity-accounted joint venture Vår Energi AS, jointly controlled by Eni (69.60%) and HitecVision AS, with the initial recognition among equity-accounted investments of Eni’s interest in the combined entity. Transfers from E&P tangible assets in progress to E&P wells, plant and machinery related for €2,750 million to progress in the development of reserves at large projects, comprising Zohr, Jangkrik, East Hub, Noroos and OCTP projects. Changes in exploration and appraisal activities related to: (i) the successful completion of exploration and appraisal activities at certain suspended exploration wells and their transfer to tangible assets for €297 million; (ii) the write-off of exploration wells for €66 million due to the negative outcome of exploration and appraisal activities, mainly relating to two offshore projects in Morocco and Vietnam. Other changes included a downward revision of estimates of the decommissioning provision of the Exploration & Production segment (negative for €503 million) due to increased discount rates curve, especially for the US dollar. Exploration and appraisal activities related for €1,101 million to costs of suspended exploration wells pending final determination and for €166 million to costs of exploration wells in progress at the end of the year. Changes relating to suspended wells are showed: (€ million) Costs for exploratory wells suspended - beginning of the period Increases for which is ongoing the determination of proved reserves Amounts previously capitalized and expensed in the period Reclassification to successful exploratory wells following the estimation of proved reserves Disposals Decrease through loss of control of subsidiary Reclassification to assets held for sale Currency translation differences Costs for exploratory wells suspended - end of the period 2018 1,263 235 (61) (297) (6) (58) (24) 49 1,101 2017 1,684 451 (217) (278) (199) (178) 1,263 2016 1,737 282 (109) (276) 50 1,684 The following information relates to the stratification of the suspended wells pending final determination (ageing): Costs capitalized and suspended for well activity - within 1 year - between 1 and 3 years - beyond 3 years Costs capitalized for suspended wells - fields including wells drilled over the last 12 months - fields for which the delineation campaign is in progress - fields including commercial discoveries that proceeds to sanctioning 2018 2017 2016 (€ million) (number of wells in Eni’s interest) (€ million) (number of wells in Eni’s interest) (€ million) (number of wells in Eni’s interest) 111 87 903 1,101 111 217 773 1,101 7.02 2.88 24.20 34.10 7.02 4.66 22.42 34.10 222 241 800 1,263 148 261 854 1,263 7.95 3.87 21.44 33.26 5.88 4.69 22.69 33.26 16 609 1,059 1,684 9 251 1,424 1,684 1.05 10.25 21.55 32.85 0.55 3.51 28.79 32.85 Unproved mineral interests include the purchase price allocated to unproved reserves following business combinations or acquisition of individual properties. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 172 Unproved mineral interests were as follows: (€ million) 2018 Book amount at the beginning of the year Additions Net (impairments) reversals Reclassification to proved mineral interest Other changes and currency translation differences Book amount at the end of the year 2017 Book amount at the beginning of the year Additions Net (impairments) reversals Reclassification to proved mineral interest Other changes and currency translation differences Book amount at the end of the year o g n o C 1,162 26 (429) (32) 42 769 a i r e g i N 825 56 40 921 n a t s i n e m k r u T 192 (76) (44) 5 77 A S U 99 4 103 1,254 938 138 113 72 (7) (157) 1,162 (113) 825 75 (21) 192 (14) 99 a i r e g l A 105 (32) 4 77 112 (7) 105 t p y g E 7 23 (2) 1 29 7 7 b a r A d e t i n U s e t a r i m E 487 15 502 l a t o T 2,390 592 (505) (110) 111 2,478 2,450 112 147 (7) (312) 2,390 Unproved mineral interest comprised a property denominated Oil Prospecting License 245 (“OPL 245”), located in the offshore of Nigeria, with a net book value of €857 million, which corresponded to the price paid to the Nigerian Government to acquire a 50% interest in the property, with the partner Shell acquiring the remaining 50%. As of December 31, 2018, the net book value of the property was €1,159 million, including capitalized exploration costs and pre-development costs. The acquisition of OPL 245 is subject to judicial proceedings in Italy and in Nigeria for alleged corruption and money laundering in respect of the Resolution Agreement signed on April 29, 2011, relating to the purchase of the license by Eni and Shell. Those proceedings are disclosed in note 27 – Guarantees, Commitments and Risks. Additions for the year related to the acquisition of unproved reserves as part of the deals to acquire interests in Oil & Gas assets in production/ development phase in the offshore of Abu Dhabi (United Arab Emirates), the extension of the concession terms in Nigeria and Egypt and contractual revisions in Congo. Accumulated provisions for impairments amounted to €16,471 million (€16,005 million at December 31, 2017). At December 31, 2018, Eni pledged property, plant and equipment for €24 million primarily as collateral against certain borrowings (same amount as of December 31, 2017). Government grants recorded as a decrease of property, plant and equipment amounted to €125 million (€110 million at December 31, 2017). Assets acquired under financial lease agreements amounted to €46 million (€29 million at December 31, 2017). Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 27 – Guarantees, commitments and risks - Liquidity risk. Property, plant and equipment under concession arrangements are described in note 27 – Guarantees, commitments and risks - Assets under concession arrangements. Property, plant and equipment by segment are described in note 35 – Segment information and information by geographical area. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 12 | Intangible assets (€ million) 2018 Net carrying amount - beginning of the year Changes in accounting policies (IFRS 9 and 15) Net carrying amount restated - beginning of the year Additions Amortization Impairments Write-off Currency translation differences Change through loss of control of subsidiary Other changes Net carrying amount at the end of the year Gross carrying amount at the end of the year Provisions for amortization and impairment 2017 Net carrying amount - beginning of the year Additions Amortization Reversals Impairments Write-off Currency translation differences Other changes Net carrying amount - end of the year Gross carrying amount - end of the year Provisions for amortization and impairment 173 s t h g i r n o i t a r o l p x E 995 995 133 (71) (15) 39 1,081 1,686 605 1,092 91 (65) 32 (14) (24) (115) (2) 995 1,504 509 s t n e t a p l a i r t s u d n I l a u t c e l l e t n i d n a s t h g i r y t r e p o r p 240 240 28 (87) 40 221 1,534 1,313 259 17 (84) (1) 49 240 1,466 1,226 e l b i g n a t n i r e h t O s t e s s a 486 87 573 180 (226) (16) (1) 74 584 4,188 3,604 598 83 (137) (2) (56) 486 3,778 3,292 s t e s s a e l b i g n a t n I l u f e s u e t i n fi h t i w s e v i l 1,721 87 1,808 341 (384) (16) (16) 39 74 40 1,886 7,408 5,522 1,949 191 (286) 32 (14) (24) (118) (9) 1,721 6,748 5,027 l l i w d o o G 1,204 1,204 8 46 26 1,284 1,320 (23) (93) 1,204 l a t o T 2,925 87 3,012 341 (384) (16) (16) 47 120 66 3,170 3,269 191 (286) 32 (14) (24) (141) (102) 2,925 Exploration rights comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which are suspended pending a final determination of the success of the exploratory activity or until management confirms its commitment to the initiative. Additions for the year related to signature bonuses paid for the acquisition of new exploration acreage in United Arab Emirates, United States and Mexico. The breakdown of exploration rights by type of asset was as follows: (€ million) Proved licence and leasehold property acquisition costs Unproved licence and leasehold property acquisition costs Other mineral interests December 31, 2018 357 684 40 1,081 December 31, 2017 403 586 6 995 Industrial patents and intellectual property rights mainly regarded the acquisition and internal development of software and rights for the use of production processes and software. Other intangible assets comprised: (i) customer acquisition costs relating to the retail gas business for €166 million; (ii) concessions, licenses, trademarks and similar items for €151 million comprised transmission rights for natural gas imported from Algeria of €27 million; (iii) capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights for €78 million (same amount as of December 31, 2017). CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 174 The main amortization rates used were substantially unchanged from the previous year and ranged as follows: (%) Exploration rights Transport rights of natural gas Other concessions, licenses, trademarks and similar items Service concession arrangements Capitalized costs for customer acquisition Other intangible assets UOP - 33 3 3 - 33 20 - 33 25 - 33 4 - 20 The carrying amount of goodwill at the end of the year amounted to €2,422 million, net of cumulative impairments charges. A breakdown of the stated goodwill by operating segment is provided below: (€ million) Gas & Power Exploration & Production Refining & Marketing Other activities December 31, 2018 977 187 119 1 1,284 December 31, 2017 932 179 93 1,204 Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition. The amount of goodwill outstanding at the reporting date mainly related to the Gas & Power segment. A breakdown is disclosed below. (€ million) Domestic gas market European gas market December 31, 2018 835 142 977 December 31, 2017 835 97 932 Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU including any allocated goodwill. In assessing the recoverability of the carrying amount of the CGU domestic gas market, including the allocated portion of goodwill, management determined the value in use of the CGU considering the sales margin exclusively of the retail market (excluding margins on sales to wholesalers, industrial and power generation customers). The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating the perpetuity of the last year of the plan to determine the terminal value by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 5.4% for Italy. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. The excess of the recoverable amount of the CGU Domestic gas market over its carrying amount including the allocated portion of goodwill (headroom) amounting to €1,701 million would be reduced to zero under each of the following alternative hypothesis: (i) a decrease of 63% on average in the projected volumes or commercial margins; (ii) an increase of 12.1 percentage points in the discount rate; and (iii) a final negative nominal growth rate of 26.2%. Goodwill allocated to the CGU European gas market increased by €45 million following the acquisition of the residual 51% interest in Gas Supply Company Thessaloniki-Thessalia SA operating in Greece, previously participated with a 49% of the share capital. The residual amount of €95 million relates to Eni Gas & Power France SA (former Altergaz SA). The impairment review performed at the balance sheet date by using a method similar to the Domestic gas market CGU confirmed the recoverability of the carrying amount of the France gas market CGU including any allocated goodwill by using a post-tax WACC adjusted considering a country risk for France of 6.1%, while the impairment review for the Greek gas market CGU was part of the acquisition evaluation. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 175 13 | Net reversal (impairment) of tangible and intangible assets In assessing whether impairment is required, the carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher between an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized. Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by estimating assets’ values-in-use. The valuation is carried out for individual assets or for the smallest identifiable group of assets that generates cash inflows that are largely independent from the cash inflows from other assets, or groups of assets (cash generating unit - CGU). The Group has identified the following CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, in addition to the CGUs to which goodwill arisen from business combinations was allocated, electricity generation plants, international pipelines and LNG vessels; (iii) in the Refining & Marketing business line, refining plants, retail networks and assets related to other distribution channels grouped by Country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical business line has been assessed to be a single CGU. The value-in-use is calculated by discounting the estimated future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from disposal at the end of their useful lives. Cash flows are determined based on the best information available at the time of the assessment. Cash flow projections for the first four years of each CGU evaluation are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected Oil & Gas production volumes, sales volumes, capital expenditure, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. The estimation of CGUs’ terminal values is based on cash flow projections beyond the four-year plan horizon, which are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the Oil & Gas CGUs, management assumed the residual life of the reserves and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing business line and power plants are evaluated based on the plant economic and technical life and the associated, normalized projections of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. The terminal value of the Chemical business integrated CGU considers the economic useful lives of the underlying assets and factors a normalized EBITDA (to reflect the cyclicality of the sector) defined based on the average contribution margin of the plan. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns. The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair. Values-in-use is estimated by discounting post-tax cash flows at a rate, which corresponds for the Exploration & Production segment and Refining & Marketing business line to the Company’s weighted average cost of capital (WACC) net of the risk factors attributable to the Gas & Power segment and the Chemical business line, the WACC of which is assessed on a stand-alone basis. Then specific discount rates are adjusted to factor in risks specific to each Country of activity (adjusted post-tax WACC). Post- tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. The framework of impairment indicators of exogenous origin remained substantially stable compared to the context relating to the assessments performed in the previous year. In the final part of 2018, after touching a multi-year high at approximately 85 $/BBL, the Brent crude oil price made a sharp downturn driven by a slowdown in macroeconomic growth, oversupplies and uncertainties tied with the trade dispute between USA and China, the Brexit and local geopolitical crises. In spite of the remarkable correction in oil prices which declined by more than 20 $/BBL to close the year at approximately 60 $/ BBL, based on the review of market fundamentals in the medium-long term which remain supportive of continued demand growth, as well as willingness on part of producers to maintain oil markets in balance and the market view of financial analysts and industry observers, management retained a long-term Brent price of 70 $/BBL in real terms 2022, substantially in line with the assumption made in the annual report 2017, on which basis management performed the 2018 assets impairment review and elaborated financial projections for the four-year plan 2019- 2022. Prices of natural gas in Europe are projected to reach a higher level than in previous planning assumptions driven by an improved balance between gas demand and supplies supported by a continuing decline in continental mature fields production and the phase-out of nuclear and coal power plants. The SERM benchmark refining margin is projected unchanged from the previous plan at approximately 5 $/BBL in the long- term, based on expectations of continuing competitive pressures in Europe from cheaper products streams imported from USA and Middle East, the effects of which will be mitigated by enactment of stricter environmental regulations on the sulphur content of marine fuels effective from 2020. Projections of margins for the main petrochemicals commodities were scaled down due to management’s expectations of continued competitive pressures in European markets from more competitive producers based in USA and Middle East and a slowdown in end markets. However, the projections of margins in the petrochemicals business determined only a modest reduction in the value-in-use of the Company’s petrochemicals CGU because the impairment review is based on a normalized scenario which factors in the cyclicality of the industry. Moreover, although at the balance sheet date the market capitalization of Eni was about 3% lower than the book value of consolidated net assets, this tendency registered a significant trend reversal and, at the date of approval of the Financial Statements by the Board of Directors, the market capitalization exceeded the book value by about 10%. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018176 The management tested for impairment the totality of the Group’s fixed assets as provided by the Company’s internal guidelines. The 2018 WACC of Eni, which is the driver for calculating the post-tax WACC of the Oil & Gas and refining business CGUs to assess their value-in-use, recorded an increase 0.5 percentage point to 7.3% compared to 2017. This increase was driven by the projections of higher risk-free yields that Eni’s methodology links to ten-year Italian government bonds. The WACC used in the Gas & Power segment and the Chemical business, subject to separate valuation compared to the Eni’s assessment, line resulted unchanged from 2017. The post-tax WACC rates for 2018 highlighted a certain dispersion of values compared to the mean, reflecting large differences in the country risk premiums which were affected by ongoing developments in each Country operating environment. The adjusted WACC rates used for impairment test purposes in 2018 ranged from 6.2% to 16.0% in the Exploration & Production segment. In the Exploration & Production segment the Company recorded impairment losses before taxes for €1,025 million driven by a lower-than- expected performance at certain oilfields, particularly in Congo and USA, a deteriorated operating environment of a specific project and alignment to fair value of assets divested or held for sale in Croatia and Ecuador. These losses were partially offset by reversals of prior-year impairment losses for €299 million due to better gas prices in Europe and reduced country risk premiums in certain locations. The post-tax WACC relating to impairment losses/reversals of impairments of more than €100 million amounted to 6%, corresponding to pre-tax rates ranging from 6% to 9%. In the Refining & Marketing business line the Company recorded impairment losses for €156 million related to the investments of the year for compliance and stay-in-business related to CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review. In the Gas & Power segment the Company recorded a reversals of impairment losses at a gas transportation asset for €66 million driven by a lower discount rate adjusted for the country risk. In the power business, reversals and impairments relating to each individual plant resulted offset. 14 | Investments EQUITY-ACCOUNTED INVESTMENTS (€ million) Carrying amount - beginning of the year Changes in accounting policies (IFRS 9 and 15) Carrying amount restated - beginning of the year Additions and subscriptions Divestments and reimbursements Share of profit of equity-accounted investments Share of loss of equity-accounted investments Deduction for dividends Changes in the scope of consolidation Currency translation differences Other changes Carrying amount - end of the year n i s t n e m t s e v n I d e t a d i l o s n o c n u s e i t i t n e i n E y b d e l l o r t n o c 116 116 (33) 8 (5) (6) 2 13 95 2018 i s e r u t n e v t n i o J 2,332 (34) 2,298 28 (3) 16 (415) (19) 3,448 25 119 5,497 s e t a i c o s s A 1,063 (3) 1,060 92 (115) 385 (10) (25) 54 11 1,452 n i s t n e m t s e v n I l a t o T 3,511 (37) 3,474 120 (151) 409 (430) (50) 3,448 81 143 7,044 d e t a d i l o s n o c n u s e i t i t n e n E y b d e l l o r t n o c 2017 s e r u t n e v t n o J i s e t a i c o s s A l a t o T 168 168 9 (7) (32) 2 (13) (11) 116 2,675 1,197 4,040 2,675 63 49 (340) (41) (127) 53 2,332 1,197 444 (462) 66 (6) (13) (128) (35) 1,063 4,040 507 (462) 124 (353) (86) 2 (268) 7 3,511 Acquisitions and share capital increases mainly related to: (i) the capital contribution to Coral FLNG SA (€48 million) which is engaged in the development of a floating production and storage unit of LNG in natural gas-rich Area 4, offshore Mozambique; (ii) the acquisition for €42 million of a 33.72% interest in Commonwealth Fusion System Llc (CFS), a company created as a spin-out of the Massachusetts Institute of Technology for the development of the technology of power generation from fusion. Divestments and reimbursements related to the capital reimbursement of Angola LNG Ltd for €95 million. The share of Eni’s profit of equity-accounted entities related for €353 million to the equity result of Angola LNG Ltd, driven by a reversal of about €260 million of prior-year impairment losses of the LNG project. The economics of the project improved due to the favorable outcome of an arbitration proceeding which established the settlement of a contract to utilize the re-gasification terminal of Pascagoula owned by Gulf Energy Ltd, where the fees associated with the contract were previously discounted in the future cash flow of the upstream project and of the related downstream activity of gas marketing. The outcome of the arbitration led to the recognition of an equivalent expense through loss. The accounting under the equity method of Saipem SpA resulted in a loss of €146 million due to the recognition by the investee of restructuring costs and impairment losses of assets. As of December 31, 2018, the book value of the investment in Saipem amounting to €1,228 million, which was aligned to the corresponding share of the net assets of the investee, exceeded by approximately 22% the fair value represented by the market capitalization of Saipem share. Considering this impairment indicator and ongoing uncertainties surrounding a recovery in the investing cycle of oil companies and competitive pressure in the E&C sector, management performed an impairment review of the investment to assess its recoverability based on an internal financial model of future CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 177 cash flows of Saipem estimated based on financial projections made by the sell-side analysts who cover the Saipem share, publicly available data on Saipem and the observed historical correlation which link the Saipem turnover to crude oil prices and spending in capital projects made by oil companies. This review supported the book value of the investment. At date of approval of the financial statements, the book value of the investment exceeded by approximately 23% the fair value represented by the market capitalization. Share of losses of equity-accounted investments included a loss of €219 million accounted at the joint ventures with the Venezuelan state-owned company PDVSA, PetroJunín SA, (Eni’s interest 40%) and Cardón IV SA (Eni’s interest 50%), which are operating the onshore heavy-oil Junín field and the Perla gas field, respectively. The loss was driven by the de-booking of the project’s undeveloped proved reserves (down by 106 million boe) due to a deteriorated operating environment, as required by the US SEC rules. Deduction for dividends related for €24 million to United Gas Derivatives Co. Other increases included for €3,498 million the initial recognition of Eni’s participating interest in the joint venture Vår Energi AS (69.60%), which was established following the business combination between the former Eni subsidiary Eni Norge AS and Point Resources AS. The joint venture will be equity-accounted. The book value of the joint venture equals Eni’s share of the fair values of the combined net assets. Net carrying amount of equity-accounted investments related to the following: (€ million) Investments in unconsolidated entities controlled by Eni Eni BTC Ltd Other investments(*) Joint ventures Vår Energi AS Saipem SpA Unión Fenosa Gas SA Gas Distribution Company of Thessaloniki-Thessaly SA Cardón IV SA Lotte Versalis Elastomers Co Ltd PetroJunín SA AET - Raffineriebeteiligungsgesellschaft mbH Other investments(*) Associates Angola LNG Ltd Coral FLNG SA Novamont SpA United Gas Derivatives Co Commonwealth Fusion Systems Llc Other investments(*) (*) Each individual amount included herein was lower than €25 million. December 31, 2018 December 31, 2017 i g n y r r a c t e N t n u o m a 31 64 95 3,498 1,228 335 137 98 75 47 32 47 5,497 1,106 102 67 62 42 73 1,452 7,044 t n e m t s e v n i e h t f o % 100.00 69.60 30.99 50.00 49.00 50.00 50.00 40.00 33.33 13.60 25.00 25.00 33.33 33.72 i g n y r r a c t e N t n u o m a 63 53 116 1,413 350 137 114 210 32 76 2,332 802 54 71 82 54 1,063 3,511 t n e m t s e v n i e h t f o % 100.00 31.00 50.00 49.00 50.00 40.00 33.33 13.60 25.00 25.00 33.33 Results of equity-accounted investments by segment are disclosed in note 35 – Segment information and information by geographical area. The carrying amounts of equity-accounted investments included differences between the purchase price of acquired interests and their underlying book value of net assets amounting to €58 million, related to Novamont SpA for €43 million and Unión Fenosa Gas SA for €15 million. These surpluses were driven by the long-term profitability outlook of the acquired companies at the time of the acquisition. As of December 31, 2018, the market value of the investments listed in regulated stock markets was as follows: (€ million) Number of shares held % of the investment Share price (€) Market value (€ million) Book value (€ million) Additional information is included in note 37 − Other information about investments. Saipem SpA 308,767,968 30.99 3.265 1,008 1,228 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 178 OTHER INVESTMENTS (€ million) Carrying amount - beginning of the year Changes in accounting policies (IFRS 9) Carrying amount restated - beginning of the year Additions and subscriptions Change in the fair value Divestments and reimbursements Currency translation differences Other changes Carrying amount - end of the year December 31, 2018 219 681 900 5 15 (22) 31 (10) 919 December 31, 2017 276 276 3 (19) (23) (18) 219 In applying IFRS 9, minor investments were recognized at fair value resulting in an asset write-up of €681 million as of January 1, 2018. Those investments in equity instruments were previously accounted for under IAS 39 which permitted entities to measure unquoted investments in equity instruments at cost if their fair value could not be determined reliably. This increase related to: (i) Nigeria LNG Ltd for €511 million (carrying amount of €99 million at December 31, 2017). The investment book value as of December 31, 2018 was €651 million net of the dividends paid in the year; (ii) Saudi European Petrochemical Co “IBN ZAHR” for €130 million (carrying amount of €13 million at December 31, 2017). The investment book value as at December 31, 2018 was €144 million net of the dividends paid in the year. The fair value of the main non-controlling interests in unquoted undertakings, classified within level 3 of the fair value hierarchy, was estimated based on a methodology that combines expected additional earnings and sum-of-the-parts measurements (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected results, as a gauge of the future profitability of the investees, derived from the business plans, but adjusted, where appropriate, to include the assumptions that market participants would incorporate; (ii) the cost of capital, adjusted to include the risk premium of the specific Country in which each investee operates. Changes of 1% of the cost of capital considered in the valuation do not produce significant changes at the fair value evaluation. Dividends paid by those investments are disclosed in note 31 – Income (expense) from investments. Investments in subsidiaries, joint arrangements and associates as of December 31, 2018 are presented in the annex “List of companies owned by Eni SpA as of December 31, 2018”. This annex includes also the changes in the scope of consolidation. 15 | Other financial assets (€ million) Long-term financing receivables held for operating purposes Long-term financing receivables held for operating purposes Financing receivables held for non-operating purposes Securities held for operating purposes Non-current 1,189 December 31, 2018 Current 61 51 112 188 300 1,189 1,189 64 1,253 Non-current 1,602 December 31, 2017 Current 23 84 107 209 316 1,602 1,602 73 1,675 316 Financing receivables are stated net of allowance for doubtful accounts as follows: 300 (€ million) Carrying amount at December 31, 2017 Additions Deductions Currency translation differences Carrying amount at December 31, 2018 Allowance for doubtful accounts of financing receivables 730 279 (596) 17 430 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 179 Financing receivables held for operating purposes of €1,301 million (€1,709 million at December 31, 2017) related principally to funds provided to joint ventures and associates in the Exploration & Production segment (€1,075 million) and the Gas & Power segment (€103 million). The greatest exposure is towards the joint venture Cardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating the Perla offshore gas field, for €705 million at December 31, 2018 (€955 million at December 31, 2017). The recoverability of those assets was assessed considering the performance of the industrial initiatives financed, in addition to other factors. Financing receivables held for operating purposes due beyond five years amounted to €1,088 million (€1,393 million at December 31, 2017). The fair value of non-current financing receivables held for operating purposes of €1,188 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.2% to 2.9% (-0.2% and 2.5% at December 31, 2017). This valuation methodology does not apply to assess the recoverability of the financial loan granted to the joint venture Cardón IV SA to fund the development projects carried out by the venture, which can be assimilated to net capital employed. The recoverability of this financing loans depends on the future cash flows of the industrial project, which are exposed to a credit risk given the difficult financial condition of Venezuela. In assessing the recoverability of the loan, management carried out an appreciation of the risk to convert in cash the project future revenues by projecting a deferral in the timing of revenues collection and discounting the resulting future cash flows at a rate adjusted for the country risk that factors in the deteriorated operating environment of the Country. The outcomes of the assessment confirmed the carrying amount of the financial loan. The recoverability of other long-term financial assets was assessed by considering the expected probability default in the next twelve months only, as the creditworthiness suffered no significant deterioration in the reporting period. Additions to the allowance for doubtful accounts related to a loss taken at a financing receivable granted to a joint venture in Russia engaged in the execution of an exploratory project in the Black Sea due to the unsuccessful outcome of the initiative. Financing receivables held for non-operating purposes related to bank deposits with the purpose to invest cash surpluses and restricted deposits in escrow to guarantee transactions on derivative contracts. Financing receivables held for operating purposes were denominated in euro and US dollar for €188 million and € 1,299 million, respectively. Securities held for operating purpose related to listed bonds issued by sovereign states (listed bonds issued by sovereign states for €69 million and by the European Investment Bank for €4 million at December 31, 2017). Securities for €20 million (same amount as of December 31, 2017) were pledged as guarantee of the deposit for gas cylinders as provided for by the Italian law. The following table analyses securities per issuing entity: t s o c d e z i t r o m A ) n o i l l i m € ( 24 29 8 3 64 e u l a v l i a n m o N ) n o i l l i m € ( 24 29 8 3 64 e u l a v r i a F ) i n o i l i m € ( 25 29 8 3 65 e t a r l i a n m o N n r u t e r f o % e t a d y t i r u t a M ’ s y d o o M - g n i t a R P & S - g n i t a R from 0.20 to 4.75 from 0.05 to 4.40 from 2019 to 2025 from 2019 to 2023 Baa3 from Aa3 to Baa1 BBB from AA to A- from 2019 to 2020 2022 Baa3 Baa3 BBB BBB- Sovereign states Fixed rate bonds Italy Others(*) Floating rate bonds Italy Others(*) Total sovereign states (*) Amounts included herein are lower than €25 million. Securities having a maturity within five years amounted to €63 million. The fair value of securities was derived from quoted market prices. Receivables with related parties are described in note 36 – Transactions with related parties. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 180 16 | Trade and other payables As of January 1, 2018, the effects of the application of IFRS 15 are the following: (€ million) Carrying amount at December 31, 2017 Changes in accounting principles (IFRS 15) Reclassification to other current liabilities (IFRS 15) Carrying amount at January 1, 2018 Down payments and advances from customers 545 (545) Trade payables 10,890 10,890 Down payments and advances from joint venture partners in Exploration & Production 252 252 Other payables 5,061 (113) (785) 4,163 Trade and other payables 16,748 (113) (1,330) 15,305 The application of IFRS 15 determined a decrease in the stated amount of payables recognized in connection with lifting imbalances in the Exploration & Production segment for €113 million in application of the sales method in lieu of the entitlement method. The reclassification to other current liabilities (IFRS 15) related to: (i) lifting imbalances of the Exploration & Production segment recognized by using the sales method for €785 million; (ii) down payments and advances from customers reclassified as liabilities from contracts with customers. More information about the application of IFRS 9 and IFRS 15 is reported in note 3 – Changes in accounting policies. The breakdown of trade and other payables is the following: (€ million) Trade payables Down payments and advances from customers Down payments and advances from partners in Exploration & Production activities Payables for purchase of non-current assets Payables due to partners in Exploration & Production activities Other payables December 31, 2018 11,645 207 2,530 1,151 1,214 16,747 December 31, 2017 10,890 545 252 2,094 1,968 999 16,748 Trade payables were denominated in euro for €6,484 million and in US dollar for €9,403 million. Because of the short-term maturity and conditions of remuneration of trade payables, the fair values approximated the carrying amounts. Payables due to related parties are described in note 36 – Transactions with related parties. 17 | Other liabilities (€ million) Fair value of derivatives financial instruments Liabilities from contracts with customers Cautionary deposits Other liabilities December 31, 2018 Current 1,445 1,108 Non-current 40 518 268 676 1,502 1,427 3,980 December 31, 2017 Current 1,011 Non-current 91 504 1,515 255 1,133 1,479 In applying IFRS 15: (i) liabilities from contracts with customers included the reclassification as of January 1, 2018, from the item Trade and other liabilities of down payments and advances from customers of €545 million; (ii) other current liabilities included the reclassification as of January 1, 2018, from the item Trade and other receivables of the lifting imbalances in the Exploration & Production CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 181 segment for €785 million following the adoption of the sales method. Fair value related to derivative financial instruments is disclosed in note 23 – Derivative financial instruments and hedge accounting. Liabilities from contracts with customer of €1,626 million included: (i) advances denominated in local currency of €716 million relating to future supplies of equity hydrocarbons to our Egyptian State- owned partners in relation to the operations of Eni’s Concession Agreements in the Country for the next four-year period and in particular, among these, the Zohr project; (ii) the current portion of advances received by Engie SA (former Suez) relating to a long-term agreement for supplying natural gas and electricity for €66 million; the non-current portion amounted to €518 million. Cautionary deposits related to deposits from retail customers for the supply of gas and electricity of €233 million (€215 million at December 31, 2017). Other current liabilities included overlifting imbalances of the Exploration & Production segment for €1,004 million. Other non-current liabilities included tax liabilities for €61 million (€45 million at December 31, 2017) and other debts for €155 million (€45 million at December 31, 2017). Transactions with related parties are described in note 36 – Transactions with related parties. 18 | Financial liabilities (€ million) Banks Ordinary bonds Convertible bonds Commercial papers Other financial institutions December 31, 2018 December 31, 2017 t b e d m r e t - t r o h S 383 915 884 2,182 f o n o i t r o p t n e r r u C t b e d m r e t - g n o l 768 2,781 52 3,601 t b e d m r e t - g n o L 2,710 16,923 390 59 20,082 l a t o T 3,861 19,704 390 915 995 25,865 t b e d m r e t - t r o h S 201 1,664 377 2,242 f o n o i t r o p t n e r r u C t b e d m r e t - g n o l 801 1,445 40 2,286 t b e d m r e t - g n o L 3,200 16,520 387 72 20,179 l a t o T 4,202 17,965 387 1,664 489 24,707 Financial liabilities included an increase of €1,158 million driven by: (i) new issuances net of repayments made of €320 million; (ii) currency translation differences relating to companies having debt denominated in currency other than the functional currency for €314 million (iii) the de-recognition of Eni Norge AS cash and cash equivalents for €494 million due to the loss of control on the former subsidiary, which were deposited at the Group’s financial companies. Commercial papers were issued by the Group’s financial subsidiaries. The following table reflects long-term debt and current portion of long-term debt as of December 31, 2018 by maturity: (€ million) Banks Ordinary bonds Convertible bonds Other financial institutions 2020 556 2,391 9 2,956 2021 345 921 10 1,276 2022 393 698 390 9 1,490 2023 829 1,858 11 2,698 After 587 11,055 20 11,662 Total 2,710 16,923 390 59 20,082 Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the maintenance of a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees could be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long and medium-term facilities subject to the maintenance of certain financial ratios based on the Consolidated Financial Statements of Eni with Citibank Europe Plc, whose non-compliance allows the bank to request an early repayment. At December 31, 2018, debts subjected to restrictive covenants amounted to €1,337 million (€1,664 million at December 31, 2017). Eni was in compliance with those covenants. Ordinary bonds consisted of bonds issued within the Euro Medium Term Notes Program for a total of €16,904 million and other bonds for a total of €2,800 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 182 The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2018: (€ million) Issuing entity Euro Medium Term Notes Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni SpA Eni Finance International SA Eni Finance International SA Eni Finance International SA Eni Finance International SA Other bonds Eni SpA Eni SpA Eni SpA Eni SpA Eni USA Inc n o t n u o c s i D e u s s i d n o b d e u r c c a d n a e s n e p x e t n u o m A l a t o T y c n e r r u C 1,500 1,200 1,000 1,000 1,000 1,000 1,000 900 800 800 750 750 750 700 650 600 335 295 167 1,528 16,725 873 873 393 305 349 2,793 19,518 17 16 38 27 19 9 8 (5) 2 (1) 14 8 5 1 2 (5) 15 4 5 179 2 1 4 1 (1) 7 186 1,517 1,216 1,038 1,027 1,019 1,009 1,008 895 802 799 764 758 755 701 652 595 350 299 167 1,533 16,904 875 874 397 306 348 2,800 19,704 EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR EUR GBP EUR YEN USD USD USD USD USD USD from 2019 2028 2019 2026 y t i r u t a M to 2019 2025 2020 2029 2020 2023 2026 2024 2021 2028 2019 2024 2027 2022 2025 2028 2021 2043 2037 2027 2023 2028 2020 2040 2027 % e t a R to from 4.125 3.750 4.250 3.625 4.000 3.250 1.500 0.625 2.625 1.625 3.750 1.750 1.500 0.750 1.000 1.125 5.000 5.441 2.810 variable 4.000 4.750 4.150 5.700 7.300 4.750 3.875 1.955 As of December 31, 2018, ordinary bonds maturing within 18 months amounted to €4,596 million. During 2018, new bonds issued amounted to €2,844 million. The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, 2018: (€ million) Eni SpA n o t n u o c s i D e u s s i d n o b d e u r c c a d n a e s n e p x e t n u o m A 400 (10) l a t o T 390 y c n e r r u C EUR y t i r u t a M 2022 % e t a R 0.000 The non-dilutive equity-linked bond issued provides for by a redemption value linked to the market price of Eni’s shares. The bondholders have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, to hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 183 Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.7 billion were drawn as of December 31, 2018. The following table provides a breakdown by currency of long-term debt, its current portion and the related weighted average interest rates: December 31, 2018 December 31, 2017 t b e d m r e t t r o h S ) n o i l l i m € ( 680 1,007 495 2,182 d n a t b e d m r e t g n o L t b e d m r e t - g n o l f o n o i t r o p t n e r r u c ) n o i l l i m € ( 18,635 4,530 518 23,683 e t a r e g a r e v A ) % ( 1.9 2.5 1.0 e t a r e g a r e v A ) % ( 2.3 4.3 4.2 t b e d m r e t t r o h S ) n o i l l i m € ( 904 1,329 9 2,242 f o n o i t r o p m r e t - t r o h S d n a t b e d m r e t g n o L t b e d m r e t - g n o l ) n o i l l i m € ( 20,094 1,694 677 22,465 e t a r e g a r e v A ) % ( 0.5 1.8 (0.7) e t a r e g a r e v A ) % ( 2.4 4.8 4.7 Euro US dollar Other currencies Total As of December 31, 2018, Eni retained undrawn uncommitted borrowing facilities amounting to €12,484 million (€11,584 million at December 31, 2017) and undrawn long-term committed borrowing facilities of €5,214 million (€5,802 million at December 31, 2017). Those facilities bore interest rates reflecting prevailing conditions on the marketplace. Fair value of long-term debt, including the current portion of long- term debt is described below: (€ million) Ordinary bonds Convertible bonds Banks Other financial institutions December 31, 2018 20,257 399 3,445 111 24,212 December 31, 2017 19,219 410 4,021 114 23,764 Fair value of financial debt was calculated by discounting the expected future cash flows at discount rates ranging from -0.2% to 2.9% (-0.2% and 2.5% at December 31, 2017). Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount. Changes in borrowings are provided below: (€ million) Carrying amount at December 31, 2017 Cash flows Currency translation differences Changes in the scope of consolidation Other non-monetary changes Carrying amount at December 31, 2018 Transactions with related parties are described in note 36 – Transactions with related parties. t b e d m r e t - g n o L t n e r r u c d n a n o i t r o p t b e d m r e t - g n o l f o 22,465 1,033 126 59 23,683 t b e d m r e t - t r o h S 2,242 (713) 188 494 (29) 2,182 l a t o T 24,707 320 314 494 30 25,865 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 184 19 | Information on net borrowings The analysis of net borrowings, as defined in the “Financial Review”, was as follows: (€ million) A. Cash and cash equivalents B. Held-for-trading financial assets C. Available-for-sale financial assets D. Liquidity (A+B+C) E. Financing receivables F. Short-term debt towards banks G. Long-term debt towards banks H. Bonds I. Short-term debt towards related parties L. Other short-term liabilities M. Other long-term liabilities N. Total borrowings (F+G+H+I+L+M) O. Net borrowings (N-D-E) December 31, 2018 Non-current 2,710 17,313 59 20,082 20,082 Current 10,836 6,552 17,388 188 383 768 2,781 661 1,138 52 5,783 (11,793) Total 10,836 6,552 17,388 188 383 3,478 20,094 661 1,138 111 25,865 8,289 Current 7,363 6,012 207 13,582 209 201 801 1,445 164 1,877 40 4,528 (9,263) December 31, 2017 Non-current 3,200 16,907 72 20,179 20,179 Total 7,363 6,012 207 13,582 209 201 4,001 18,352 164 1,877 112 24,707 10,916 Financial assets held for trading are disclosed in note 6 – Financial assets held for trading. Current financing receivables are disclosed in note 15 – Other financial assets. 20 | Provisions for contingencies t n e m n o d n a b a , n o i t a r o t s e r s t c e j o r p l a i c o s d n a e t i s r o f n o i s i v o r P 8,126 (502) 259 (190) (1,024) 153 (45) 6,777 s n o i t a g i t i l r o f n o i s i v o r P s n o i s i v o r p l a i r a u t c a d n a e c n a r u s n i s ’ i n E r o f s t n e m t s u j d a s s o L s e i n a p m o c s e x a t r o f n o i s i v o r P l a t n e m n o r i v n E n o i s i v o r p 2,653 1,107 148 299 527 73 205 493 (12) (287) (33) (11) (14) 2,595 2 (214) (289) (1) 34 37 824 (118) (31) (8) 17 (20) 440 (481) 110 327 s e s s o l r o f n o i s i v o r P s t n e m t s e v n i n o 182 48 (1) 2 (27) 204 L I O r o f n o i s i v o r P r e v o c e c n a r u s n i 76 51 s u o r e n o r o f n o i s i v o r P s t c a r t n o c 60 l a s o p s i d r o f n o i s i v o r P g n i r u t c u r t s e r d n a 65 19 (14) (22) s e v i t n e c n i y c n a d n u d e r r o f n o i s i v o r P 140 9 (17) (17) (5) 3 130 (2) 108 (4) 66 38 ) * ( r e h t O l a t o T 306 13,447 1,363 223 (502) 249 (1,443) (100) (18) (389) (2) (1,051) 210 4 (36) 2 377 11,886 (€ million) Carrying amount at December 31, 2017 New or increased provisions Initial recognition and changes in estimates Accretion discount Reversal of utilized provisions Reversal of unutilized provisions Changes in the scope of consolidation Currency translation differences Other changes Carrying amount at December 31, 2018 (*) Each individual amount included herein was lower than €50 million. The Group makes full provision for the future costs of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions, included the discounted estimated costs that the Company expects to incur for decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration of the Exploration & Production segment for €6,266 million. Estimate revisions of €502 million were driven by an increase in the discount rate curve in particular for the US dollar. Such increase was partially offset by the recognition of new decommissioning obligations due to the activity of the year and upward revisions of cost estimates. The unwinding of discount recognized through profit and loss for €259 million was determined based on discount rates ranging from -0.2% to 6.1% (from -0.01% to 5.98% at December 31, 2017). Main expenditures associated with CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 185 decommissioning operations are expected to be incurred over a 45-year period. Provisions for environmental risks included the estimated costs for environmental clean-up and remediation of soil and groundwater in areas owned or under concession where the Group performed in the past industrial operations that were progressively divested, shut down, dismantled or restructured. The provision was accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out environmental clean-up and remediation and the expected costs can be estimated reliably. The provision included the expected charges associated with strict liability related to obligations of cleaning up and remediating polluted areas that met the parameters set by the law at the time when the pollution occurred, or because Eni assumed the liability borne by other operators when the Company acquired or otherwise took over site operations. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to performing certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, 2018, environmental provision primarily related to Syndial SpA for €2,009 million and to the Refining & Marketing business line for €348 million. The litigation provision comprised the expected liabilities associated with legal proceedings and other matters arising from contractual claims, contract renegotiations, including arbitration, fines and penalties due to antitrust proceedings and administrative matters. These provisions represented the Company’s best estimate of the expected, probable liabilities associated with pending litigation and commercial disputes and primarily related to the Exploration & Production segment for €653 million. Utilizations of €503 million mainly related to the definition of a price revision relating to a gas sale contract with a long-term buyer, the effect of which was compensated by the reduction of the receivable due by the gas supplier recognized in other non-current assets. Provisions for taxes included the estimated charges that the Company expects to incur to settle uncertain tax matters and tax claims from authorities in connection the application of current tax rules at certain Italian and non-Italian subsidiaries in the Exploration & Production segment (€397 million). Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC represented the estimated liabilities accrued on the basis for third parties claims. Against such liability was recorded receivables of €236 million recognized towards insurance companies for reinsurance contracts. Provisions for losses on investments included provisions relating to investments whose loss exceeds the equity and primarily related to Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) for €114 million. Provisions for the OIL mutual insurance scheme included the estimated future increase of insurance premiums which will be charged to Eni in the next five years and that accrued at the reporting date because of the effective accident rate occurred in past reporting periods. Provisions for redundancy incentives were recognized due to a restructuring program involving the Italian personnel related to past reporting periods. 21 | Provisions for employee benefits (€ million) Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Defined benefit plans Other benefit plans Provision for employee benefits December 31, 2018 275 385 148 808 309 1,117 December 31, 2017 284 409 135 828 194 1,022 The liability relating to Eni’s commitment to cover the healthcare costs of personnel is determined on the basis of the contributions paid by the Company. Other employee benefit plans related to deferred monetary incentive plans for €136 million, the isopensione plans of Eni gas e luce SpA for €132 million, jubilee awards for €22 million, long-term incentive plan still outstanding for €8 million and other long-term plans for €11 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018186 Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following: December 31, 2018 December 31, 2017 d e n fi e d n a i l a t I l s n a p t fi e n e b d e n fi e d n g i e r o F l s n a p t fi e n e b n g i e r o f , E D S I F s n a p l l a c i d e m r e h t o d n a l s n a p t fi e n e b d e n fi e D t fi e n e b r e h t O s n a p l d e n fi e d n a i l a t I l s n a p t fi e n e b l a t o T d e n fi e d n g e r o F i l s n a p t fi e n e b i n g e r o f , E D S I F s n a p l l a c i d e m r e h t o d n a t fi e n e b d e n fi e D s n a p l l s n a p t fi e n e b r e h t O l a t o T 284 997 135 1,416 194 1,610 298 895 136 1,329 158 1,487 4 1 1 (15) 27 31 (25) (31) 6 2 1 (35) (8) (90) 2 2 13 1 12 1 (9) 29 37 (11) (30) 19 3 1 (59) (8) (90) 1 26 4 31 42 1 30 29 1 71 38 19 3 (6) (1) (5) 20 (1) 115 118 1 (133) (10) (8) (92) 34 (1) (74) (2) 3 24 29 54 (14) 71 (3) (1) 1 1 (37) (12) (15) 59 2 2 (1) (1) 2 (6) (1) 26 34 47 (14) 66 (5) 1 1 1 (53) (12) (17) 54 1 3 3 28 (36) (2) (3) 80 35 50 (14) 69 (5) 29 1 1 (89) (14) (20) 1 60 (9) 51 275 925 148 1,348 309 1,657 284 997 135 1,416 194 1,610 588 17 (21) 25 1 24 (26) (64) 26 545 5 5 385 588 17 (21) 25 1 24 (26) (64) 26 545 5 5 808 148 588 17 (21) 25 1 24 (26) (64) 26 545 5 5 1,117 309 619 20 12 24 1 23 (25) (15) (47) 588 619 20 12 24 1 23 (25) (15) (47) 588 619 20 12 24 1 23 (25) (15) (47) 588 284 409 135 828 194 1,022 (€ million) Present value of benefit liabilities at beginning of year Current cost Interest cost Remeasurements: - actuarial (gains) losses due to changes in demographic assumptions - actuarial (gains) losses due to changes in financial assumptions - experience (gains) losses Past service cost and (gains) losses settlements Plan contributions: - employee contributions Benefits paid Reclassification to asset held for sale Changes in the scope of consolidation Currency translation differences and other changes Present value of benefit liabilities at end of year (a) Plan assets at beginning of year Interest income Return on plan assets Plan contributions: - employee contributions - employer contributions Benefits paid Changes in the scope of consolidation Currency translation differences and other changes Plan assets at end of year (b) Asset ceiling at beginning of year Change in asset ceiling Asset ceiling at end of year (c) Net liability recognized at end of year (a-b+c) 275 Employee benefit plans included the liability attributable to partners operating in exploration and production activities of €181 million (€177 million at December 31, 2017). Eni recorded a receivable for an amount equivalent to such liability. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 187 Costs charged to the profit and loss account consisted of the following: (€ million) 2018 Current cost Past service cost and (gains) losses on settlements Interest cost (income), net: - interest cost on liabilities - interest income on plan assets Total interest cost (income), net - of which recognized in “Payroll and related cost” - of which recognized in “Financial income (expense)” Remeasurements for long-term plans Total - of which recognized in “Payroll and related cost” - of which recognized in “Financial income (expense)” 2017 Current cost Past service cost and (gains) losses on settlements Interest cost (income), net: - interest cost on liabilities - interest income on plan assets Total interest cost (income), net - of which recognized in “Payroll and related cost” - of which recognized in “Financial income (expense)” Remeasurements for long-term plans Total - of which recognized in “Payroll and related cost” - of which recognized in “Financial income (expense)” Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Defined benefit plans Other benefit plans 27 2 31 (17) 14 14 43 29 14 24 (1) 29 (20) 9 9 32 23 9 4 4 4 4 4 3 3 3 3 3 2 1 2 2 2 5 3 2 2 2 2 2 2 6 4 2 29 3 37 (17) 20 20 52 32 20 26 1 34 (20) 14 14 41 27 14 42 115 1 1 1 30 188 188 54 28 1 1 1 3 86 86 Total 71 118 38 (17) 21 1 20 30 240 220 20 80 29 35 (20) 15 1 14 3 127 113 14 Costs of defined benefit plans recognized in other comprehensive income consisted of the following: (€ million) Remeasurements Actuarial (gains)/losses due to changes in demographic assumptions Actuarial (gains)/losses due to changes in financial assumptions Experience (gains) losses Return on plan assets Change in asset ceiling 2018 2017 Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other (31) 6 21 5 1 1 1 1 12 13 Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other (5) (1) (14) 71 (3) (12) (1) Total (14) 66 (5) (12) (6) 42 (1) 35 Total (30) 19 21 5 15 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 188 Plan assets consisted of the following: (€ million) December 31, 2018 Plan assets with a quoted market price Plan assets without a quoted market price December 31, 2017 Plan assets with a quoted market price Plan assets without a quoted market price Cash and cash equivalents Equity securities Debt securities Real estate Derivatives Investment funds Assets held by insurance company Other Total 115 37 238 6 6 37 48 238 329 10 48 329 10 115 16 16 2 2 9 9 56 56 60 60 18 3 21 13 3 16 70 542 3 70 545 100 585 3 100 588 The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2019 consisted of the following: (%) 2018 Discount rate Rate of compensation increase Rate of price inflation Life expectations on retirement at age 65 2017 Discount rate Rate of compensation increase Rate of price inflation Life expectations on retirement at age 65 Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Other long-term benefit plans 1.5 2.5 1.5 1.5 2.5 1.5 0.8-18.0 1.5-16.5 0.8-16.0 13-25 0.6-15.5 1.5-13.5 0.6-14.8 13-24 1.5 1.5 24 1.5 1.5 24 0.2-1.5 1.5 0.0-1.5 1.5 (years) (years) The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans: (%) 2018 Discount rate Rate of compensation increase Rate of price inflation Life expectations on retirement at age 65 2017 Discount rate Rate of compensation increase Rate of price inflation Life expectations on retirement at age 65 Euro area Rest of Europe 1.5-1.9 1.5-3.0 1.5-2.0 21-22 1.5-1.8 1.5-3.0 1.5-1.9 21-24 0.8-2.9 2.5-3.8 0.8-3.3 23-25 0.6-2.5 2.5-3.7 0.6-3.4 22-24 Africa 3.7-18.0 5.0-16.5 3.7-16.0 13-17 3.7-15.5 5.0-13.5 3.7-14.8 13-17 Other areas Foreign defined benefit plans 8.0-13.3 10.0-13.3 3.5-5.0 4.1-8.0 1.5-10.0 1.5-4.8 0.8-18.0 1.5-16.5 0.8-16.0 13-25 0.6-15.5 1.5-13.5 0.6-14.8 13-24 (years) (years) CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 189 The effects of a possible change in the main actuarial assumptions at the end of the year are listed below: (€ million) December 31, 2018 Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Other benefit plans December 31, 2017 Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Other benefit plans Discount rate 0.5% Increase 0.5% Decrease Rate of price inflation 0.5% Increase Rate of increases in pensionable salaries 0.5% Increase Healthcare cost trend rate 0.5% Increase Rate of increases to pensions in payment 0.5% Increase (12) (58) (7) (5) (13) (72) (7) (3) 13 65 8 3 14 79 7 1 8 23 1 9 24 1 15 20 18 13 6 7 The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters. The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €129 million, of which €48 million related to defined benefit plans. The following is an analysis by maturity date of the liabilities for employee benefit plans and their relative weighted average duration: (€ million) December 31, 2018 2019 2020 2021 2022 2023 2024 and thereafter Weighted average duration (years) December 31, 2017 2018 2019 2020 2021 2022 2023 and thereafter Weighted average duration (years) Italian defined benefit plans Foreign defined benefit plans FISDE, foreign medical plans and other Other benefit plans 15 16 18 14 11 201 10.1 16 17 18 17 14 202 10.1 54 56 63 64 74 74 17.4 47 65 70 79 84 64 17.5 9 7 6 6 6 114 12.8 7 7 6 6 6 103 12.8 81 72 67 20 17 57 2.6 64 58 45 7 5 25 2.8 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 190 22 | Deferred tax assets and liabilities (€ million) Deferred tax liabilities, gross Deferred tax assets available for offset Deferred tax liabilities Deferred tax assets, gross (net of accumulated write-down provisions) Deferred tax liabilities available for offset Deferred tax assets The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below: (€ million) Deferred tax liabilities Accelerated tax depreciation Difference between the fair value and the carrying amount of assets acquired Site restoration and abandonment (tangible assets) Application of the weighted average cost method in evaluation of inventories Other Deferred tax assets, gross Carry-forward tax losses Site restoration and abandonment (provisions for contingencies) Timing differences on depreciation and amortization Accruals for impairment losses and provisions for contingencies Impairment losses Over/Under lifting Employee benefits Unrealized intercompany profits Other Accumulated write-downs of deferred tax assets Deferred tax assets, net The following table summarizes the changes in deferred tax liabilities and assets: December 31, 2018 7,956 (3,684) 4,272 7,615 (3,684) 3,931 December 31, 2017 10,169 (4,269) 5,900 8,347 (4,269) 4,078 Carrying amount at December 31, 2018 Carrying amount at December 31, 2017 6,612 849 85 44 366 7,956 (5,528) (1,986) (2,104) (1,460) (792) (604) (212) (124) (546) (13,356) 5,741 (7,615) 8,323 1,106 305 70 365 10,169 (5,240) (2,747) (2,164) (1,404) (801) (395) (194) (130) (534) (13,609) 5,262 (8,347) (€ million) 2018 Carrying amount - beginning of the year Changes in accounting principles (IFRS 15) Carrying amount restated - beginning of the year Additions Deductions Currency translation differences Decrease through loss of control of subsidiary Other changes Carrying amount at the end of the year 2017 Carrying amount at the beginning of the year Additions Deductions Currency translation differences Other changes Carrying amount at the end of the year Deferred tax liabilities Deferred tax assets, gross Accumulated write-downs of deferred tax assets Deferred tax assets, net of impairments 10,169 37 10,206 1,147 (802) 283 (2,778) (100) 7,956 10,953 1,171 (835) (1,123) 3 10,169 (13,609) (237) (13,846) (1,478) 1,523 (278) 813 (90) (13,356) (13,698) (2,341) 1,588 862 (20) (13,609) 5,262 5,262 253 (43) 71 198 5,741 5,622 212 (349) (202) (21) 5,262 (8,347) (237) (8,584) (1,225) 1,480 (207) 813 108 (7,615) (8,076) (2,129) 1,239 660 (41) (8,347) CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 191 Carry-forward tax losses amounted to €19,108 million out of which €13,753 million can be used indefinitely. Carry-forward tax losses regarded Italian companies for €10,786 million and foreign companies for €8,322 million. Deferred tax assets recognized on these losses amounted to €2,615 million and €2,913 million, respectively. Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. An average tax rate of 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses, which will be utilized in future years to offset expected taxable profit. The corresponding rate for foreign subsidiaries was 35%. Accumulated write-down provisions of deferred tax assets related to Italian companies for €4,133 million and foreign companies for €1,608 million. 23 | Derivative financial instruments (€ million) Non-hedging derivatives Derivatives on exchange rate - Currency swap - Interest currency swap - Outright Derivatives on interest rate - Interest rate swap Derivatives on commodities - Future - Over the counter - Other Trading derivatives Derivatives on commodities - Over the counter - Future - Options Cash flow hedge derivatives Derivatives on commodities - Over the counter - Future Option embedded in convertible bonds Gross amount Offsetting Net amount Of which: - current - non-current December 31, 2018 December 31, 2017 Fair value asset Fair value liability Level of Fair value Fair value asset Fair value liability Level of Fair value 99 14 3 116 18 18 1,060 306 1 1,367 1,501 992 367 80 1,439 311 26 337 21 3,298 (1,636) 1,662 1,594 68 46 71 5 122 6 6 1,107 284 5 1,396 1,524 1,031 263 71 1,365 196 15 211 21 3,121 (1,636) 1,485 1,445 40 2 2 2 2 1 2 2 2 1 2 2 1 2 170 41 3 214 9 9 796 81 1 878 1,101 683 395 133 1,211 227 35 262 16 2,590 (1,279) 1,311 1,231 80 86 45 5 136 5 5 771 97 2 870 1,011 829 390 114 1,333 21 21 16 2,381 (1,279) 1,102 1,011 91 2 2 2 2 1 2 2 2 1 2 2 1 2 Derivative fair values were estimated on the basis of market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace. Fair values of non-hedging derivatives consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS. Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading. Fair value of cash flow hedge derivatives related to commodity hedges entered by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanism of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 25 – Shareholders’ equity and in note 29 – Operating expenses. Information on hedged risks and hedging policies is disclosed in note 27 – Guarantees, commitments and risks - Risk factors. Options embedded in convertible bonds of €21 million related to equity-linked cash settled. More information is disclosed in note 18 – Financial liabilities. The offsetting of financial derivatives related to the Gas & Power segment. During the 2018, there were no transfers between the different hierarchy levels of fair value. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 192 Hedging derivative instruments are disclosed below: (€ million) Cash flow hedge derivatives Derivatives on commodity - Over the counter - Future Nominal amount of the hedging instrument December 31, 2018 Change in fair value (effective hedge) Change in fair value (ineffective hedge) 3,528 71 3,599 404 (6) 398 2 (2) In 2018, the exposure to the exchange rate risk deriving from securities denominated in US dollars included in the strategic liquidity portfolio amounting to €1,154 million was hedged by using, in a fair value hedge relationship, negative exchange differences for €35 million resulting on a portion of bonds denominated in US dollars amounting to €1,140 million. The breakdown of the underlying asset or liability by type of risk hedged under cash flow hedge is provided below: (€ million) Cash flow hedge Commodity price risk - Forecast sales December 31, 2018 Change of the underlying asset used for the calculation of hedging ineffectiveness CFH reserve Reclassification adjustments (389) (389) (13) (13) 642 642 Eni’s results of operations are affected by fluctuations in the price of commodities. In order to manage commodity price risk, Eni uses derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, electricity or emission certificates that are not settled through physical delivery of the underlying asset but are designated as hedging instruments in a cash flow hedge relation. The existence of a relationship between hedged item and hedging instrument aimed to compensate its changes in value and the relating hedging capability not affected by the level of credit risk of the counterparty are verified for qualifying the operation as hedge. The definition of the relationship between the quantity of the hedged item and the quantity of the hedging instrument (the so-called hedge ratio) is defined consistently with the entity’s risk management objectives, under a defined risk management strategy. The hedging relationship is discontinued when it ceases to meet the qualifying criteria and the risk management objectives on the basis of which it was qualified as for hedge accounting. More information is reported in note 27 – Guarantees, Commitments and Risks - Risk factors. Effects recognized in other operating profit (loss) Other operating profit (loss) related to derivative financial instruments on commodity was as follows: (€ million) Net income (loss) on cash flow hedging derivatives Net income (loss) on other derivatives 2018 129 129 2017 12 (44) (32) 2016 (1) 17 16 Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives was recognized through profit and loss in the Gas & Power segment. Net income (loss) on other derivatives included: (i) the fair value measurement and settlement of commodity derivatives which do not meet the formal criteria to be treated in accordance with hedge accounting under IFRS as they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading amounting to a net income of €129 million (net loss of €44 million in 2017 and net income of €36 million in 2016); and (ii) the fair value valuation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of €19 million in 2016. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 193 Effects recognized in finance income (loss) Finance income (loss) on derivative financial instruments consisted of the following: (€ million) Derivatives on exchange rate Derivatives on interest rate Options 2018 (329) 22 (307) 2017 809 28 837 2016 (494) (12) 24 (482) Net income from derivatives was recognized in connection with fair value valuation of certain derivatives which do not meet the formal criteria to be treated in accordance with hedge accounting under IFRS as they are entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. Finance income (expense) with related parties is disclosed in note 36 – Transactions with related parties. 24 | Assets held for sale and liabilities directly associated with assets held for sale As of December 31, 2018, assets held for sale and the related directly associated liabilities of €295 million and €59 million, respectively, related to: (i) Agip Oil Ecuador BV, holder of the service contract for the Villano oil field, for which a binding transfer agreement was signed. The carrying amounts of assets held for sale and directly associated liabilities amounted to €274 million (of which current assets for €81 million) and €59 million respectively (of which current liabilities for €33 million); (ii) the sale of tangible assets and minority interests for a total carrying amount of €21 million. In the course of 2018, Eni finalized the sale of: (i) the 98.99% (entire stake owned) of Tigáz Zrt and Tigáz DSO (100% Tigáz Zrt) to the group MET Holding AG, including Eni’s gas distribution operations in Hungary; (ii) the business relating to a 26.25% stake of Lasmo Sanga Sanga Ltd (entire stake owned) of the PSA in the Sanga Sanga gas and condensates field; (iii) the sale of a 50% (entire stake owned) interest in the joint venture Unimar Llc. 25 | Shareholders’ equity As of January 1, 2018, the effects of the application of IFRS 9 and IFRS 15 are the following: (€ million) Carrying amount at December 31, 2017 Changes in accounting principles (IFRS 9) Changes in accounting principles (IFRS 15) Carrying amount at January 1, 2018 Share capital 4,005 4,005 Retained Earnings 35,966 294 (49) 36,211 Other reserves 4,685 Net profit (loss) 3,374 4,685 3,374 Total 48,030 294 (49) 48,275 More information about the application of IFRS 9 and IFRS 15 is disclosed in note 3 – Changes in accounting policies. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 194 (€ million) Share capital Retained earnings Cumulative currency translation differences Legal reserve Reserve for treasury shares Reserve related to the fair value of cash flow hedging derivatives net of the tax effect Reserve related to the defined benefit plans net of tax effect Other comprehensive income on equity-accounted investments Other comprehensive income on other investments Other reserves Treasury shares Interim dividend Net profit (loss) for the year December 31, 2018 4,005 36,702 6,605 959 581 (9) (130) 66 15 190 (581) (1,513) 4.126 51.016 December 31, 2017 4,005 35,966 4,818 959 581 183 (114) 90 190 (581) (1,441) 3.374 48.030 More information about the application of IFRS 9 and IFRS 15 is disclosed in note 3 – Changes in accounting policies. 2018, to shareholders on the register on 21 May 2018, record date on 22 May 2018. Total dividend per share in 2017 was €0.80. Share capital As of December 31, 2018, the parent company’s issued share capital consisted of €4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, 2017). On May 10, 2018, Eni’s Shareholders’ Meeting resolved the distribution of a dividend of €0.40 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 2017 dividend of €0.40 per share, of which €0.40 per share paid as interim dividend in September 2017. The balance was paid on 23 May Legal reserve This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law. Reserve for treasury shares The reserve for treasury shares represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings. Other Comprehensive Income reserves (€ million) Reserve as of December 31, 2017 Changes of the year Foreign currency translation differences Change in scope of consolidation Reversal to inventories adjustments Reclassification adjustments Reserve as of December 31, 2018 Reserve as of December 31, 2016 Changes of the year Foreign currency translation differences Reclassification adjustments Reserve as of December 31, 2017 Cash flow hedge derivatives Defined benefit plans e v r e s e r s s o r G 240 399 d e r r e f e D x a t s e i t i l i b a i l (57) (116) e v r e s e r t e N 183 283 (10) (642) (13) 246 (59) 53 240 3 174 4 (7) (468) (9) (57) 14 (14) (57) 189 (45) 39 183 e v r e s e r s s o r G (133) (15) 1 4 d e r r e f e D x a t s e i t i l i b a i l 19 (2) (1) (3) e v r e s e r t e N (114) (17) 1 (143) 13 (130) (99) (33) (1) (13) 29 3 (112) (4) 2 (133) 19 (114) Other comprehensive income on equity-accounted investments 90 (24) 66 21 69 90 Investments valued at fair value 15 15 Reserve related to investments valued at fair value does not include the effects of first application of IFRS 9 of €681 million recognized in retained earnings. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 195 Other reserves Other reserves related to: (i) a reserve of €127 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiaries; (ii) a reserve of €63 million deriving from Eni SpA’s equity. Cumulative foreign currency translation differences The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro. 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017-2019 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the Plan. Interim dividend The interim dividend for the year 2018 amounted to €1,513 million corresponding to €0.42 per share, as resolved by the Board of Directors on September 13, 2018, in accordance with Article 2433- bis, paragraph 5 of the Italian Civil Code; the dividend was paid on September 26, 2018. Treasury shares A total of 33,045,197 Eni’s ordinary shares (same amount as of December 31, 2017) were held in treasury for a total cost of €581 million (same amount as of December 31, 2017). On April 13, Distributable reserves As of December 31, 2018, Eni shareholders’ equity included distributable reserves of approximately €46 billion. Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity (€ million) As recorded in Eni SpA’s Financial Statements Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company Consolidation adjustments: - difference between purchase cost and underlying carrying amounts of net equity - adjustments to comply with Group account policies - elimination of unrealized intercompany profits - deferred taxation Non-controlling interest As recorded in Consolidated Financial Statements Net profit Shareholders’ equity 2018 3,173 2017 December 31, 2018 42,615 3,586 December 31, 2017 42,529 (134) (466) 7,183 6,110 862 177 59 4,137 (11) 4,126 (1) 202 (88) 144 3,377 (3) 3,374 153 2,000 (519) (359) 51,073 (57) 51,016 145 719 (807) (617) 48,079 (49) 48,030 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 196 26 | Other information Supplemental cash flow information (€ million) Investment in consolidated subsidiaries and businesses Current assets Non-current assets Net borrowings Current and non-current liabilities Net effect of investments Fair value of investments held before the acquisition of control Gain on a bargain purchase Purchase price less: Cash and cash equivalents Investment in consolidated subsidiaries and businesses net of cash and cash equivalent acquired Disposal of consolidated subsidiaries and businesses Current assets Non-current assets Net borrowings Current and non-current liabilities Net effect of disposals Reclassification of foreign currency translation differences among other items of OCI Fair value of share capital held after the sale of control Fair value valuation for business combination Gain (loss) on disposal Non-controlling interest Selling price less: Cash and cash equivalents Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent divested 2018 2017 2016 44 198 11 (47) 206 (50) (8) 148 (29) 119 328 5,079 785 (3,470) 2,722 113 (3,498) 889 13 166 814 (252) (205) 523 2,148 239 2,671 6,526 8,615 (5,415) (6,334) 3,392 7 (1,006) 11 (1,872) 532 (286) (47) (9) 2,662 (894) (362) Investments in 2018 concerned: (i) the acquisition of the business by Versalis Spa of the “bio” activities of Mossi & Ghisolfi Group, related to development, industrialization, licensing of bio-chemical technologies and processes based on use of renewable sources for €75 million; (ii) the acquisition of the remaining 51% stake in the Gas Supply Company Thessaloniki-Thessalia SA which distributes and sells gas in Greece for €24 million, net of cash acquired of €28 million; (iii) the acquisition of the company Mestni Plinovodi distribucija plina doo, which distributes and sells gas in Slovenia for €15 million, net of cash acquired for €1 million. The gain from bargain purchase, recognized in Other income and revenues, was due to the obtainable synergies from the greater ability to recover the investments made by the acquired company due to the combination of customer portfolios. Disposals in 2018 concerned: (i) the loss of control of Eni Norge AS resulting from the business combination with Point Resources AS, with the establishment of the equity-accounted joint venture Vår Energi AS (Eni interest 69.60%), that will develop the project portfolio of the combined entities. The operation entailed the exclusion from the consolidation area of €2,486 million of net assets, of which cash and cash equivalents for €258 million, the recognition of the investment in Vår Energi AS for €3,498 million and a fair value gain of €889 million, net of negative exchange rate differences of €123 million; (ii) the sale of 98.99% (entire stake owned) of Tigáz Zrt and Tigáz Dso (100% Tigáz Zrt) operating in the gas distribution business in Hungary to the MET Holding AG group for €145 million net of cash divested of €13 million; (iii) the sale by Lasmo Sanga Sanga of the business relating to a 26.25% stake (entire stake owned) in the PSA of the Sanga Sanga gas and condensates field for €33 million; (iv) the sale of 100% of Eni Croatia BV, which owns shares of gas projects in Croatia to INA- Industrija Nafte dd for €20 million, net of cash divested of €15 million; (v) the sale of 100% of Eni Trinidad and Tobago Ltd, which holds a share of a gas project in Trinidad & Tobago for €10 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 27 | Guarantees, commitments and risks Guarantees Commitments and risks (€ million) Consolidated subsidiaries Unconsolidated subsidiaries Joint ventures and associates Others 197 December 31, 2018 5,082 196 4,056 163 9,497 December 31, 2017 5,595 181 10,046 352 16,174 The parent company of the Eni Group issued guarantees to cover the contractual obligations held by third parties towards Eni’s affiliates to build and finance the construction of an LNG Floating Production unit for the development of the Coral gas reserves discovered in Area 4 offshore Mozambique. The value of the contract is €4,586 million. Eni is operator of the project with a 25% indirect interest through a 35.71% stake in the joint operation Mozambique Rovuma Venture SpA. The final investment decision (FID) for the Coral project was made on June 1, 2017. The FLNG plant is designed to treat approximately 3.37 million tonnes per year of LNG. A special purpose entity was established, Coral FLNG SA (Eni interest 25%). This entity will operate the vessel in accordance to a service agreement for the liquefaction, storage and loading of the LNG on behalf of the Concessionaires of Area 4 and of the other two partners of Mozambique Rovuma Venture SpA, CNPC and ExxonMobil in proportion to their participating interest in the Exploration and Production Concession Contract (EPCC) of Area 4, equal to 20% and 25%, respectively. The LNG will be supplied to BP under a long-term LNG sale and purchase agreement with a take-or-pay clause and a twenty-year term, providing an option of extending the duration for up to ten consecutive years. Eni issued through a subsidiary a parent company guarantee, whereby it irrevocably and unconditionally guarantees the Technip – JGC – Samsung Heavy Industries (TJS) consortium (the beneficiaries) for the due and proper performance of the obligations of Coral FLNG SA in connection with execution of the Engineering Procurement Construction Installation and Commissioning contract (EPCIC), up to the maximum liability of €1,147 million equal to 25% of the value of the contract. The maximum liability will be automatically reduced by any amount paid to the beneficiaries in respect of the guaranteed obligations. The financing of the project is carried out partly through funds provided by the venturers and partly by a project financing with Export Credit Agencies and commercial banks for a total amount of €4,082 million. During the construction and the commissioning of the FLNG plant, the project financing agreement will be supported by a debt service undertaking, up to a maximum liability of €1,397 million in proportion to Eni’s participating interest equal to 25% in the industrial initiative. Subsequently, in the running phase of the plant, once the performance tests of the vessel have been validated by the lenders, that guarantee will be released and the financing facility will change into a non-recourse one, terminating the obligations of the venturers of Area 4. Once vessel operations start, the lenders will be guaranteed only by the vessel cash flows, excluding the gas reserves from the scope of the guarantee. The financing and any collateral costs will be reimbursed to the lenders through a “pay-when-paid” clause, whereby loan repayments will be made through the cash flows associated with the sale of the LNG arising from the project to the long-term buyer, without any obligations from Eni and Concessionaires to guarantee the performance of Coral FLNG SA towards the lenders. Furthermore, the Concessionaries opened a credit facility which committed each Concessionary to finance pro-quota: (i) the share of capital expenditures to be borne by the Mozambique State-owned company ENH up to a maximum liability of €121 million in Eni’s share; (ii) the share of the debt service undertaking by ENH up to a maximum liability of €155 million in Eni’s share. As a final point, as provided by the EPCC that regulates the petroleum activities in Area 4, Eni SpA in its capacity as parent company of the operator Mozambique Rovuma Venture SpA provided concurrently with the approval of the initial development plan of the Area reserves, an irrevocable and unconditional parent company guarantee in respect of any possible claims or any contractual breaches in connection with the petroleum activities to be carried out in the contractual area, including those activities in charge of the special purpose entities like Coral FLNG SA, to benefit of the Government of Mozambique and third parties. The obligations of the guarantor towards the Government of Mozambique are unlimited (non-quantifiable commitments), whereas they provide a maximum liability of €1,309 million in respect of third- parties claims. This guarantee will be effective until the completion of any decommissioning activity related to both the development plan of Coral as well as any development plan to be executed within Area 4 (particularly the Mamba project). This parent company guarantee issued by Eni covering 100% of the aforementioned obligations was taken over by the other concessionaires (Kogas, Galp and ENH) and by ExxonMobil and CNPC shareholders of the joint operation Mozambico Rovuma Venture SpA, in proportion to their respective participating interest in the EPCIC of Area 4. Other guarantees issued on behalf of consolidated subsidiaries primarily consisted of: (i) guarantees given to third parties relating to bid bonds and performance bonds for €2,576 million (€2,312 million at December 31, 2017); (ii) a bank guarantee of €1,010 million (same amount as of December 31, 2017) issued on behalf of GasTerra in order to obtain the renunciation to a temporary seizure order on Eni’s investment in Eni International BV, requested and obtained by a Netherlands Court in July 2016. At December 31, 2018, the underlying commitment covered by such guarantees was €5,000 million (€5,564 million at December 31, 2017). Unsecured guarantees and other guarantees issued on behalf of joint ventures and associates primarily consisted of: (i) an unsecured guarantee of €499 million (€6,122 million at December 31, 2017) given by Eni SpA to Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018198 to the Milan-Bologna fast track railway by CEPAV (Consorzio Eni per l’Alta Velocità) Uno (associated company of Saipem); the decrease of €5,623 million is due to the cancellation of the guarantees related to the completion of the main lots of the project; (ii) unsecured guarantees and other guarantees given to banks in relation to loans and lines of credit received for €1,664 million (€1,623 million at December 31, 2017), of which €1,397 million (€1,334 million at December 31, 2017) related to guarantees issued as part of the development project of the gas reserves at the Coral discovery in Area 4 offshore Mozambique on behalf of Coral South FLNG DMCC with respect to the financing agreements of the project with Export Credit Agencies and banks; and (iii) guarantees given to third parties relating to bid bonds and performance bonds for €1,644 million (€2,122 at December 31, 2017), of which €1,147 million (€1,094 million at December 31, 2017) related to guarantees issued for the construction of the FLNG as part of the development project of the gas reserves at the Coral project offshore Mozambique and €279 million given on behalf of Saipem Group (€1,008 million at December 31, 2017); (iv) a guarantee issued in favor of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni’s interest 13.60%) as security against payment commitments of fees in connection with the regasification activity for €177 million (€169 million at December 31, 2017). At December 31, 2018, the underlying commitment covered by such guarantees was €2,159 million (€2,594 million at December 31, 2017). Commitments and risks (€ million) Commitments Risks December 31, 2018 54,611 673 55,284 December 31, 2017 14,498 691 15,189 Commitments related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to €52,397 million (€11,289 million at December 31, 2017). The increase of €41,108 million essentially related to: (a) the issue of parent company guarantees, in relation to transactions with the Abu Dhabi State oil company, ADNOC, whereby Eni acquired participating interests in two offshore concessions in production of Lower Zakum (Eni’s interest 5%) and Umm Shaif and Nasr (Eni’s interest 10%) for a period of 40 years and for a maximum amount of €13,094 million and in the concession under development of Gasha (Eni’s interest 25%) for a period of 40 years and a maximum amount of €21,824 million. These guarantees were issued to cover the contractual obligations towards the State company, deriving from oil operations related to the Concession Agreements including, in particular, the achievement of some production targets and recovery factors of reserves in the medium and long term, an asset integrity plan and optimization and maintenance of the production after reaching the plateau, the transfer of technologies and the adoption of best-in-class operating standards in HSE. The guarantees do not cover any loss of profit or production deriving from failure to achieve the targets; (b) the issue of parent company guarantees for €6,831 million following the awarding of new exploration licenses in the offshore of Mexico and the final investment decision for the development of the offshore reserves in Area 1; (ii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service Llc for the purchase of volumes of re-gasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031). The expected commitments were estimated at €2,079 million (€2,113 million at December 31, 2017) and included in off- balance sheet contractual commitments in the table “Future payments under contractual obligations” in the paragraph Liquidity risk. In 2018, the contractual commitment signed in December 2007 between Eni USA Gas Marketing Llc and Gulf LNG Energy Llc (GLE) and Gulf LNG Pipeline Llc (GLP) for the supply of long-term regasification and import services (until 2031) amounting at the opening balance to €948 million (undiscounted) ceased due to an arbitration award, ruling that the commitment was resolved by March 1, 2016 and recognizing to the counterparties an equitable compensation of €324 million, accounted as expense in the income statement. Despite the ruling of the arbitration Court invalidating the contract, GLE and GLP filed a claim with the Supreme Court of New York against Eni SpA demanding the enforcement of the parent company guarantee issued by Eni for the payment of the regasification fees until to the original due date of the contract (2031) for a maximum amount of €757 million. Eni believes that the claims by GLE and GLP have no merit and is defending the action. At the moment, the risk of losing the proceeding is considered unlikely; (iii) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest €116 million (€128 million at December 31, 2017) in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oilfields in Val d’Agri. The commitment has been included in the off-balance sheet contractual commitments in the following paragraph “Liquidity risk”. Risks concerned potential risks associated with contractual assurances given to acquirers of certain investments and businesses of Eni for €244 million (€235 million at December 31, 2017) and the value of assets of third parties under the custody of Eni for €429 million (€456 million at December 31, 2017). Non-quantifiable commitments A parent company guarantee was issued on behalf of Cardón IV SA (Eni’s interest 50%), a joint venture that is currently operating the Perla gas field located in Venezuela, for the supplying to PDVSA GAS of the volumes of gas produced by the field until end of the concession agreement (2036). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the claim under the guarantee will be determined by applying the local legislation. Eni share (50%) of the contractual volumes CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS199 of gas to be delivered to PDVSA GAS amounted to a total of €13 billion. Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued by PDVSA on behalf of Eni for the fulfillment of the purchase commitments of the gas volumes by PDVSA GAS. Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain Eni assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity. Risk factors FINANCIAL RISKS Financial risks are managed in respect of guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting of the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the aim of the risk management, the valuation methodology, the structure of limits, the relation model and the hedging and mitigation instruments. MARKET RISK Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International SA, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni’s finance department and Eni Finance International SA manage subsidiaries’ financing requirements in and outside Italy, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non- European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these operations through Eni Trading & Shipping and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As the proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre- defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account of the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes them on the marketplace. According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni has decided to retain a cash reserve to face any extraordinary requirement. Eni’s finance department, with the aim of optimizing the efficiency and ensuring maximum protection of the capital, manages such reserve and its CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018200 immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity. The four different market risks, whose management and control have been summarized above, are described below. MARKET RISK - EXCHANGE RATE Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the US dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange rates fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the US dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance department, which pools Group companies’ positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period. MARKET RISK - INTEREST RATE Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. The Group’s central finance department pools borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account, as they do not meet the formal criteria to be accounted for under the hedge accounting method. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period. MARKET RISK - COMMODITY Eni’s results of operations are affected by changes in the prices of commodities. A decrease in Oil & Gas prices generally has a negative impact on Eni’s results of operations and vice versa and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved Oil & Gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors as of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not finalized to the delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). In the proprietary trading exposures are included the origination activities, if not connected to contractual or physical assets. Strategic risk is not subject to systematic activity of management/ coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. Eni manages the commodity risk and the exposure to commodity prices through the trading unit of Eni Trading & Shipping by using derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, electricity or emission certificates. Such derivatives are evaluated at fair value based on market prices provided from specialized sources or, CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS201 absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a one-day holding period. MARKET RISK - STRATEGIC LIQUIDITY Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual funds) would affect the value of these instruments when evaluated at fair value. The setting up and maintenance of the liquidity reserve is mainly aimed to guarantee a proper financial flexibility. Liquidity should allow Eni Group to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions) and must be dimensioned to provide a coverage of short-term debts and a coverage of medium and long-term financial debts due within a time horizon of 24 months. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of financial activities and operational boundaries, as well as Governance guidelines regulating management and control systems. In particular, strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, issuing entity, business segment, Country of emission, duration, ratings and type of investing instruments in portfolio, aimed to minimize market and liquidity risks. Financial leverage or short selling is not allowed. Activities in terms of strategic liquidity management started in the second half of the year 2013 (Euro portfolio) and throughout the course of the year 2017 (USD portfolio). In 2018, the investment portfolio Euro has maintained an average credit rating of A-/BBB+, the investment portfolio USD has maintained an average credit rating of A+/A, both in line with the year 2017. The following table shows amounts in terms of VaR, recorded in 2018 (compared with 2017) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to changes of interest rate is expressed by values of “Dollar value per Basis Point” (DVBP). (Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%) (€ million) Interest rate(a) Exchange rate(a) High 3.65 0.57 2018 Low 1.80 0.09 Average 2.73 0.28 At year end 2.99 0.25 High 3.76 0.57 2017 Low Average 2.38 1.72 0.22 0.08 At year end 2.58 0.26 (a) Value at risk deriving from interest and exchange rates exposures include the following finance department: Eni Corporate Treasury Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc. (Value at risk - Historic simulation weighted method; holding period: 1 day; confidence level: 95%) (€ million) Commercial exposures - Management Portfolio(a) Trading(b) High 18.60 2.28 2018 Low 6.79 0.26 Average 11.04 0.73 At year end 7.50 0.27 High 21.14 2.29 2017 Low Average 12.24 5.15 0.79 0.21 At year end 5.15 0.66 (a) Refers to the Gas & LNG Marketing Power business line (risk exposure from Refining & Marketing business line and Gas & Power Division), Eni Trading & Shipping commercial portfolio, operating branches outside Italy pertaining to the Divisions and from October 2016 the Gas and Luce Business line. For the Gas & Power business lines, following the approval of the Eni’s Board of Directors on December 12, 2013, VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, in the year the VaR pertaining to GLP and EGL presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon. (b) Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston). (Sensitivity - Dollar value of 1 basis point - DVBP) (€ million) Strategic liquidity(a) (a) Management of strategic liquidity portfolio starting from July 2013. (Sensitivity - Dollar value of 1 basis point - DVBP) 2018 High 0.35 Low 0.25 Average 0.29 At year end 0.25 High 0.41 2017 Low Average 0.35 0.27 At year end 0.27 ($ million) Strategic liquidity(a) 2018 High 0.04 Low 0.01 Average 0.02 At year end 0.02 High 0.04 2017 Low Average 0.03 0.02 At year end 0.03 (a) Management of strategic liquidity portfolio in $ currency starting from August 2017. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 202 CREDIT RISK Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. Eni defined credit risk management policies consistent with the nature and characteristics of the counterparties of commercial and financial transactions and with regard to the latter, among of the others, of the centralized finance model adopted. The Company adopted a model to quantify and control the credit risk based on the evaluation of the expected loss for which the probability of default and the capacity to recover credits in default is estimated through the so-called Loss Given Default. In the credit risk management and control model, credit exposures are distinguished by commercial nature, substantially in relation to the structured contracts on commodities related to Eni’s core business, and by financial nature, substantially in relation to the financial instruments used by Eni, such as deposits, derivatives and securities. Credit risk for commercial exposures Credit risk arising from commercial counterparties is managed by the business units and by the specialized corporate finance and administration departments, and is operated on the basis of formal procedures for the assessment and assignment of commercial counterparties, the monitoring of credit exposures, credit recovery activities and disputes. At corporate level, the general guidelines and methods for quantifying and controlling customer risk, in particular for commercial counterparties, are assessed through an internal rating model that combines different default factors deriving from economic variables, financial indicators, payment experiences and information from primary info providers. The probability of default related to State Entities or their closely related counterparties (e.g. National Oil Company), essentially represented by the probability of late payments, is determined by using the country risk premiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Furthermore, for retail positions without specific ratings, the risk is determined by distinguishing customers in homogeneous risk clusters based on historical series of data relating to payments made, periodically updated. Credit risk for financial exposures With regard to credit risk arising from financial counterparties deriving from current and strategic use of liquidity, derivative contracts and transactions with underlying financial assets valued at fair value, Eni has established internal policies providing exposure control and concentration through maximum credit risk limits corresponding to different classes of financial counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the Group operating finance department, including Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and Divisions, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by group of belonging to check exposures against the limits assigned on a daily basis and the expected loss analysis and the concentration periodically. 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 finance requirements and to settle obligations. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. Eni’s risk management targets include the maintaining of an adequate level of liquidity readily available to deal with external shocks (drastic changes in the scenario, restrictions on access to capital markets, etc.) or to ensure an adequate level of operational flexibility for the development programs of the Company. The strategic liquidity reserve is employed in short-term marketable financial instruments, favouring investments with very low risk profile. At present, the Group believes to have access to sufficient funding to meet the current foreseeable borrowing requirements as a consequence of the availability of financial assets and lines of credit and the access to a wide range of funding at competitive costs through the credit system and capital markets. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.7 billion were drawn as of December 31, 2018. The Group has credit ratings of A- outlook stable and A-2, respectively for long and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. During 2018, Moody’s reduced the rating of Eni by one notch (from A3 to Baa1) following the reduction in the rating assigned to Italy (from Baa2 to Baa3, outlook stable). In the course of the 2018, Eni issued bonds amounting to €2.8 billion, of which €1.1 billion were issued under the Euro Medium Term Notes program and €1.7 billion through a dual-tranche issue on the US market and on international markets. As of December 31, 2018, Eni maintained short-term unused borrowing facilities of €12,484 million. Long-term committed unused borrowing facilities amounted to €5,214 million due beyond 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Finance debt repayments including expected payments for interest charges and derivatives The table below summarizes the Group main contractual obligations for finance liability repayments, including expected payments for interest charges and derivatives. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS203 (€ million) December 31, 2018 Non-current financial liabilities (including the current portion) Current financial liabilities Fair value of derivative instruments Interest on finance debt Financial guarantees December 31, 2017 Non-current financial liabilities (including the current portion) Current financial liabilities Fair value of derivative instruments Interest on finance debt Financial guarantees 2019 2020 2021 Maturity year 2022 2023 2024 and thereafter Total 3,301 2,182 1,445 6,928 655 668 2,958 1,541 1,253 2,714 13 2,971 545 1 1,542 436 21 1,274 330 2,714 320 11,723 5 11,728 1,677 23,490 2,182 1,485 27,157 3,963 668 2018 2019 2020 Maturity year 2021 2022 2023 and thereafter Total 2,000 2,242 1,011 5,253 582 473 4,084 2,857 1,279 1,246 10,810 64 4,148 511 10 2,867 411 1 1,280 304 16 1,262 250 10,810 1,455 22,276 2,242 1,102 25,620 3,513 473 Trade and other payables The table below summarizes the Group trade and other payables by maturity. (€ million) December 31, 2018 Trade payables Other payables and advances December 31, 2017 Trade payables Other payables and advances Maturity year 2019 2020-2023 2024 and thereafter Total 11,645 5,102 16,747 59 59 Maturity year 11,645 5,257 16,902 96 96 2018 2019-2022 2023 and thereafter Total 10,890 5,858 16,748 19 19 10,890 5,903 16,793 26 26 Expected payments by period under contractual obligations In addition to trade and financial liabilities represented in the balance sheet, the Company is subject to non-cancellable contractual obligations or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in future reporting periods. These liabilities are valued based on the net cost for the Company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligation and the contractual compensation/penalty in the event of the non-performance. The Company’s main contractual obligations at the balance sheet date comprise: (i) take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four- year business plan approved by the Company’s Board of Directors; (ii) operating leases for tangible assets, of which primarily for FPSO units of the E&P segment, in particular FPSOs operating in the offshore projects at Cape Three Points in Ghana and at the 15/06 block in Angola, with a duration of between 11 and 14 years. The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018204 (€ million) Operating lease obligations(a) Decommissioning liabilities(b) Environmental liabilities Purchase obligations(c) - Gas take-or-pay contracts ship-or-pay contracts - Other purchase obligations Other obligations - Memorandum of intent - Val d’Agri 2019 776 335 349 14,674 11,886 1,164 1,624 8 8 16,142 2020 601 294 321 11,258 10,470 558 230 1 1 12,475 2021 481 407 254 10,649 9,995 482 172 1 1 11,792 Maturity year 2022 303 260 239 9,683 2023 268 124 188 9,546 9,276 382 25 1 1 10,486 9,210 324 12 1 1 10,127 2024 and thereafter 1,524 12,394 1,245 76,014 Total 3,953 13,814 2,596 131,824 75,035 941 38 125,872 3,851 2,101 104 104 91,281 116 116 152,303 (a) There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings. (b) Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration. (c) Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Capital investment and capital expenditure commitments In the next four years, Eni expects capital investments and capital expenditures of €32.7 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties. The amounts shown in the table below include committed expenditures to execute certain environmental projects. (€ million) Committed projects 2019 6,492 2020 4,917 Maturity year 2022 1,910 2021 3,458 2023 and thereafter 3,629 Total 20,406 Other information about financial instruments The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following: 2018 2017 Finance income (expense) recognized in Finance income (expense) recognized in Carrying amount Profit and loss account Other comprehensive income Carrying amount Profit and loss account Other comprehensive income 73 231 919 207 6,012 209 32 (178) 6,552 177 (111) 793 (€ million) Held-for-trading financial instruments Financial assets held for trading(a) Non-hedging and trading derivatives(b) Non-current financial instruments Held-to-maturity securities(a) Available-for-sale financial instruments Securities(a) Other investments valued at fair value(c) Receivables and payables and other assets/liabilities valued at amortized cost Trade receivables and other(d) Financing receivables(e) Securities(a) Trade payables and other(a) Financing payables(f) Net assets (liabilities) for hedging derivatives(g) (a) Income or expense were recognized in the profit and loss account within “Finance income (expense)”. (b) In the profit and loss account, economic effects were recognized as income within “Other operating income (loss)” for €129 million (loss for €44 million in 2017) and as loss within “Finance income (expense)” for €307 million (income for €837 million in 2017). (c) Income or expense were recognized in the profit and loss account within “Income (expense) from investments - Dividends”. (d) Income or expense were recognized in the profit and loss account as net impairment losses within “Net (impairment losses) reversal of trade and other receivables” for €415 million (net impairment losses for €913 million in 2017) and as income within “Finance income (expense)” for €69 million (expenses for €45 million in 2017), including interest income calculated on the basis of the effective interest rate of € 38 million. (e) In the profit and loss account, income or expense were recognized as expense within “Finance income (expense)” for €139 million (€116 million in 2017), including interest income calculated on the basis of the effective interest rate of €129 million (€128 million in 2017) and net impairment losses for €275 million. (f) In the profit and loss account, income or expense were recognized as expense within “Finance income (expense)” for €615 million (€1,137 million in 2017), including interest income calculated on the basis of the effective interest rate of €605 million (€654 million in 2017). (g) In the profit and loss account, income or expense were recognized within “Net sales from operations” and “Purchase, services and other” as income for €642 million (expense for €54 million in 2017), and as income within “Other operating income (expense)” for €12 million in 2017. 14,145 1,489 64 16,902 25,865 (51) (1,137) (42) (28) (615) 642 15,583 1,918 16,793 24,707 (958) (116) (343) (139) (243) (4) (6) 15 9 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS205 Disclosures about the offsetting of financial instruments The table below summarizes the disclosures about the offsetting of financial instruments. (€ million) December 31, 2018 Financial assets Trade and other receivables Other current assets Financial liabilities Trade and other liabilities Other current liabilities December 31, 2017 Financial assets Trade and other receivables Other current assets Financial liabilities Trade and other liabilities Other current liabilities Gross amount of financial assets and liabilities Gross amount of financial assets and liabilities subject to offsetting Net amount of financial assets and liabilities 15,634 3,894 18,280 5,616 16,636 2,852 17,963 2,794 1,533 1,636 1,533 1,636 1,215 1,279 1,215 1,279 14,101 2,258 16,747 3,980 15,421 1,573 16,748 1,515 The offsetting of financial assets and liabilities related to the offsetting of: (i) assets and liabilities for current financial derivatives for €1,636 million (€1,279 million at December 31, 2017); and (ii) receivables and payables pertaining to the Exploration & Production segment towards state entities for €1,347 million (€1,041 million at December 31, 2017); (iii) trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €186 million (€174 million at December 31, 2017). Legal Proceedings Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions disclosed in note 20 – Provisions for contingencies and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements. A description of the most significant proceedings currently pending is provided in the following paragraph. Unless otherwise indicated, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably. (ii) 1. Environment, health and safety 1.1. Criminal proceedings in the matters of environment, health and safety (i) Syndial SpA (company incorporating EniChem Agricoltura SpA – Agricoltura SpA in liquidation – EniChem Augusta Industriale Srl – Fosfotec Srl) – Proceeding about the industrial site of Crotone. In 2010 a criminal proceeding started before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted clean-up due to the activity at a landfill site which was taken over by Eni’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrial waste from Montedison activities until 1989 and then no additional waste was discharged there. Eni’s subsidiary carried out the clean-up of the landfill in 1999 through 2000. The defendants are certain managers at Eni’s subsidiaries that have owned and managed the landfill since 1991. Independent consultants performed an assessment during the 2014. Once the consultants completed their work, the acts returned to the Public Prosecutor of Crotone for the next step and possible indictment. The proceeding continues with the examination of the dismissal request submitted by the defense. The Municipality of Crotone will act as plaintiff. The Prosecutor of Crotone notified the conclusion of the preliminary investigations. In March 2019, the Public Prosecutor requested the acquittal of all defendants. In April 2017, the Public Prosecutor of Crotone had started another criminal proceeding concerning the clean-up of the area called “Farina Trappeto”. The Company presented a new clean-up project already deemed approvable by the Ministry of the Environment. Final authorizations for this project are pending. The Company requested to dismiss also this second proceeding. Syndial SpA and Versalis SpA – Porto Torres – Prosecuting body: Public Prosecutor of Sassari. In July 2011, the Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemical operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above-mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine fauna of the industrial port of Porto Torres. In February 2013, the Prosecutor of Sassari notified the conclusion of preliminary investigations and requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the preliminary hearing, the Court of Sassari dismissed the accusation CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018206 because of the statute of limitations. The Public Prosecutor filed an appeal before the Third Instance Court. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court. The Constitutional Court declared the question unfounded, considering that the statute of limitations for fraudulent hypothesis and the corresponding culpable hypothesis is an expression of a non-unreasonable legislative discretion, assuming that, in relation to certain culpable offenses causing social alarm, the complexity of the necessary investigations justifies a lengthening of the limitation periods. The Third Instance Court returned the documents to the Public Prosecutor of Sassari who proceeded to resubmit the request for indictment. The preliminary hearing is underway. (iii) Syndial SpA and Versalis SpA – Porto Torres dock. In July 2012, the Judge for the Preliminary Hearing, following a request of the Public Prosecutor of Sassari, requested the performance of a probationary evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by Syndial SpA) and its capacity to avoid the dispersion of contamination released by the site in the near portion of sea. Syndial SpA and Versalis SpA have been notified that its chief executive officers and other managers are being investigated. The Public Prosecutor of the Municipality of Sassari requested that the above-mentioned individuals would stand trial. The plaintiffs, the Ministry of Environment and the Sardinia Region claimed environmental damage in an amount of €1.5 billion. On the hearing dated July 2016, the Judge pronounced an acquittal sentence for all defendants of Syndial and Versalis with respect to the crimes of environmental disaster. Three Syndial managers were found guilty of environmental disaster which took place in the area in the period limited to August 2010-January 2011 and condemned to one-year prison, with a suspended sentence. The Judge did not mention any possible malfunctioning of the hydraulic barrier of Porto Torres site or ineffective implementation of any emergency safety measure, as claimed by the Public Prosecutor. Syndial filed an appeal against this decision. (iv) Syndial SpA – The illegal landfill in Minciaredda area, Porto Torres site. In July 2015, the Judge for the Preliminary Hearing of the Court of Sassari, on request of the Public Prosecutor, seized of the Minciaredda landfill area, near the western border of the Porto Torres site (Minciaredda area). All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure provision involved as well Syndial in accordance with the Legislative Degree No. 231/01. With reference to the clean-up activities in the Minciaredda area, on January 27, 2016 the relevant administrative body approved the project for the soil clean-up in the Minciaredda area. Syndial obtained all the necessary ministerial and judicial authorizations to start the remediation project. Following the preliminary investigations, the Public Prosecutor requested a referral to trial. Some environmental associations joined the proceeding as plaintiffs. The proceeding is still pending. Syndial SpA – The Phosphate deposit at Porto Torres site (1). In 2015, the Judge for the Preliminary Hearing of the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, seized – as a preventive measure – the area of “Palte Fosfatiche” (v) (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, carrying out of unauthorized disposal of hazardous wastes and other environmental crimes. Subsequent to a specific request, both the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized to implement better delimitations of the landfill area, to provide the area with devices for monitoring the level of environmental pollutants and meteoric waters. The investigations are underway. (vi) Syndial SpA – Phosphate deposit at Porto Torres site (2). In 2015, the Public Prosecutor at the Court of Sassari seized — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit). These waters are being collected by Syndial following authorizations of the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up and management of radioactive waste. The Public Prosecutor decided to suspend the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. The request filed for the removal of the phosphates deposit was authorized by the Public Prosecutor in October 2018. The investigations are underway. (vii) Syndial SpA – Proceeding on the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna about the crimes of culpable manslaughter, injuries and environmental disaster, which would have been allegedly committed by former Syndial employees at the site of Ravenna. The site was taken over by Syndial following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. The advocacy of Syndial claimed the statute of limitation about the instance of environmental disaster for certain instances of diseases and deaths. The Judge for the Preliminary Hearing at Ravenna decided that all defendants would stand trial and ascertained the statute of limitation only with reference to certain instances of crime of culpable injury. Syndial signed some settlements. In November 2016, the Judge acquitted the defendants for all the contested cases except for one for which ruled a decision of conviction. The defendants, the Prosecutor and the plaintiffs appealed the decision. The proceeding was suspended following the filing of an appeal before the Third Instance Court. (viii) Raffineria di Gela SpA – Eni Mediterranea Idrocarburi SpA – Alleged environmental disaster. A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and EniMed SpA relating environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. The Gela Refinery has been sued for administrative offence in accordance with the Legislative Decree No. 231/01. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, and pollution of the sea water near the coastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. At the closing of the preliminary investigation, the Public Prosecutor of Gela CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS207 merged into this proceeding the other investigations related to the pollution occurred at the other sites of the Gela refinery as well as hydrocarbon spills at facilities of EniMed. The proceeding is pending at the preliminary hearings. (ix) Eni SpA – Proceeding Val d’Agri. On March 2016, the Italian Public Prosecutor’s Office of Potenza started a criminal investigation in order to ascertain the existence of an illegal handling of waste material produced at the Viggiano oil center (COVA), part of the Eni-operated Val d’Agri oil complex. After a two-year investigation, the Prosecutors decided for the domiciliary detention of 5 Eni employees and to put under seizure certain plants functional to the production activity of the Val d’Agri complex which, consequently, was shut down (60 KBOE/d net to Eni). From the commencement of the investigation, Eni has carried out several technical and environmental surveys, with support of independent experts of international reach, who recognized a full compliance of the plant and the industrial process with requirements of the applicable laws, as well as with best available technologies and international best practices. The Company studied certain corrective measures to upgrade plants which, although being not a structural solution, were intended to address the claims made by the Public Prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those measures comprised building a gathering system of inherent liquid associated with the extraction of hydrocarbons at the gas lines. Those corrective measures were favourably reviewed by the Public Prosecutor. The Company restarted the plant through reinjections into the Costa Molina 2 well on August 2016. Simultaneously, a local administrative agency (the Region) requested a new administrative procedure to grant Eni a comprehensive environmental authorization to operate the facilities. In relation to the criminal proceeding, the Public Prosecutor’s Office requested the indictment for all the defendants and the Company. At the preliminary hearing held in April 2017, prosecutor reiterated its request of indictment. The trial started in November 2017 and is in the hearings stage. Eni SpA – Health investigation related to the COVA center. Beside the criminal proceeding for illegal trafficking of waste, the Public Prosecutor started another investigation in relation to alleged health violations. The Public Prosecutor requested the formal opening of an investigation with respect to nine people in relation to alleged violations of the rules providing for the preparation of a Risk Assessment Document of the working conditions at the Val d’Agri Oil Center (COVA). In March 2017, following the request of the Consultant of the Prosecutor, the Labor Inspectorate of Potenza issued a fine against the employers of the COVA for omitted and incomplete assessment of the chemical risks for the COVA center. In October 2017, following the request of the Consultant of the Prosecutor, the National Mining Office for Hydrocarbons and Geo- resources (UNMIG) requested the transfer to a different task of 25 employees of the COVA center for improper assessment of their suitability to the current tasks expressed by the Eni personnel in charge of assessing the health risk profile of employees. Against this decision, the Company filed a formal objection and the UNMIG repealed the resolution issued. Furthermore, in October 2017, the Prosecutor’s Office changed the crime allegations to disaster, murder and negligent personal injury, also alleging breaches of health and safety regulations. Given the level of risk, in December (x) 2017, Eni filed a request for pre-trial hearing for gathering evidence on the matter that was rejected by the Judge. (xi) Eni SpA – Proceeding Val d’Agri – Tank spill. On February 2017, the Italian police department of Potenza ascertained a stream of water contaminated by hydrocarbon traces of unknown origin, flowing inside a little shaft located outside the Val d’Agri Oil Center (COVA). The activities carried out by Eni at the COVA aimed at reconstructing the origin of the contamination and have identified the cause in a failure of a tank, while outside of the COVA, following the environmental monitoring implemented, emerged a risk — currently averted — of extension of the contamination in the downstream area of the plant. In executing these activities, Eni performed all the communications provided for by the Legislative Decree 152/06 and started certain emergency safe-keeping operations at the areas subject to contamination outside the COVA. Furthermore, the Company completed the arrangement plan for the internal and external areas of the COVA, whose final report was examined by the relevant authorities. Following this event, a criminal investigation was initiated in order to ascertain the existence of illicit environmental pollution against the former COVA officers, the Operation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident, and also against Eni in relation to the same offense pursuant to the Legislative Decree 231/01 as communicated in December 2018 following the notification of the extension of the terms for preliminary investigations and of some public officials belonging to local administrations for official misconduct, false and fraudulent public statements committed in 2014 and of crime for environmental disaster and of culpable conduct committed in February 2017. Investigations are ongoing. In April 2017, Eni, on its own initiative, suspended the industrial activity at the COVA, anticipating the provisions of the Regional Council Resolution. In July 2017, Eni restarted the plant’s operational activities. The resumption follows the approval from the Basilicata Region confirming the functionality of the plant and the presence of all necessary safety conditions. During the temporary closure, Eni performed all the requirements provided for by the relevant authorities, including the provision of a double bottom to the tank where the spillage occurred. The Company compensated the damage to certain landlords of areas close to the COVA, which were affected by the spillover. Discussions are ongoing with other claimants. In February 2018, Eni contested the reports presented in October and in December 2017 by the Italian Fire Department stating that it does not consider itself obliged to carry out the integration required, considering that the data acquired in the area affected by the event indicate that the loss was promptly and efficiently controlled and there were no situations of serious danger to human health and the environment. (xii) Raffineria di Gela SpA – Eni Mediterranea Idrocarburi SpA – Waste management of the landfill Camastra. In June 2018, Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA were notified by the Public Prosecutor of Palermo (Sicily) of a notice of conclusion of preliminary investigations relating allegations of unlawful disposal of industrial waste deriving from the reclaiming activities of soil, which were discharged at a landfill owned by a third party. The Prosecutor charged the alleged crime against the then chief executive officers of the two subsidiaries, whereas the legal entities have been charged with the liability pursuant by Legislative Decree No. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018208 231/01. The alleged wrongdoing related to the willful falsification of the waste certification for purpose of discharging at the landfill. (xiii) Syndial SpA – Environmental disaster at Ferrandina. In January 2018, the Public Prosecutor of Matera commenced a criminal proceeding against a manager of the Eni subsidiary Syndial based on allegations of unlawful handling of waste and environmental disaster as part of the reclaiming activities performed at an industrial site (Ferrandina/Pisticci in the south of Italy). The charge related to an alleged spillover of effluent in the subsoil and then in a nearby river due to a damaged pipe dedicated to the transportation of effluent to a disposal plant owned by a third party. Following an interrogation of the investigated manager, the prosecutor resolved to request his indictment. (xiv) Versalis SpA – Preventive seizure at the Priolo Gargallo plant. In February 2019, the Court of Syracuse on request of the Public Prosecutor ordered the precautionary seizure of the Priolo/ Gargallo plant as part of an ongoing investigation about air emissions at the industrial complex. However, the Eni subsidiary has been given permission to continue running the industrial activity at the plant. A preliminary review, performed by technical consultants appointed by the Public Prosecutor, found that the spots of the plant designed to channel and release emissions compliance failed to comply with best available techniques (BAT). The Tribunal measure comprised certain interrelations between BATs and the obtained Environmental Integrated Authorizations, which according to the consultants would not be legitimate because they have been found to be inconsistent with applicable regulations. Few years ago Versalis implemented certain plant upgradings designed to comply with measures requested by the Public Prosecutor and his consultants. Based on this, management filed an appeal against the measure of precautionary seizure of the plant before a Review Court. On March 26, 2019, the Review Court annulled the decree and ordered the release of seizure of the plant. (xv) Eni SpA – Fatal accident Ancona offshore platform. On March 5, 2019, a fatal accident occurred at the Barbara F platform in the offshore of Ancona. On the basis of the first investigations, part of the structure on which a crane and the relative control cabin was installed fell into the sea striking a supply vessel and causing injuries to two contract workers and the death of an Eni employee who was inside the control cabin of the crane. The Public Prosecutor of Ancona opened an investigation against unknown persons and ordered further technical appraisals relating the crane. 1.2. Civil and administrative proceedings in the matters of environment, health and safety (i) Syndial SpA – Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore – Prosecuting body: Ministry for the Environment. In May 2003, the Ministry for the Environment summoned Syndial requesting the compensation of an alleged environmental damage caused by the activity at the Pieve Vergonte plant in the years 1990 through 1996. With a temporarily executive sentence dated July 2008, the District Court of Turin sentenced the subsidiary Syndial SpA to compensate environmental damages amounting to €1,833.5 million, plus legal interests accrued from the filing of the decision. Eni and its subsidiary deemed the amount of the environmental damage to be absolutely groundless as the sentence lacked sufficient elements to support such a material amount of the liability charged with respect to the volume of pollutants ascertained by the Italian Environmental Minister. In July 2009, Syndial filed an appeal against the above-mentioned sentence, and consequently the proceeding continued before a Second Degree Court of Turin that requested a technical appraisal on the matter. The consultants validated the technical appraisal and the other technical assessments that were carried out by the Company together with local and national technical entities. The consultants concluded that: (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment of the ecosystem, therefore no restoration or damage compensation should be claimed. The only impact which could be recorded concerned the fishing activity, with an estimated damage of €7 million which could be already restored through the measures proposed by Syndial; (iii) the necessity and convenience of dredging should be definitely excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Syndial’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. In March 2017, the Second Degree Court: (i) excluded the application of compensation for monetary equivalent (Article 18 of Law 349/1986); (ii) annulled the monetary compensation of €1.8 billion requesting Syndial to perform the already approved cleanup project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The value of these compensatory works required by the Court, in case of Syndial failure or misperformance, is estimated at €9.5 million. The cleanup project filed by Syndial was ratified by local and governmental authorities and is currently being executed. Expenditures expected to be incurred have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected (including compensation for non- material damage). In April 2018, the Ministry for the Environment filed an appeal to the Third Instance Court. In accordance with the law, the Company and its managers filed an appeal and a counter-appeal. (ii) Syndial SpA – Versalis SpA – Eni SpA (R&M) – Augusta harbor. The Italian Ministry for the Environment with various administrative acts required companies that were running plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Versalis, Syndial and Eni Refining & Marketing Division. Pollution has been detected in this area primarily due to a high mercury concentration that is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above-mentioned companies contested these administrative actions, objecting in particular the nature of the remediation works decided and the methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings started on this matter were subsequently merged before the Regional Administrative Court of Catania. In October 2012, the Court ruled in favor of Eni’s subsidiaries against the Ministry prescriptions about the removal of the pollutants and the construction of a physical barrier. In September 2017, the Ministry notified all the companies involved of a formal notice for the start of remediation and environmental restoration of the Augusta harbor within 90 days. The act, contested by the co-owner companies in December 2017, constitutes a formal notice for environmental damage. The Administrative Council of the Sicilian Region ruled on CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS209 the appeals pending against various sentences of the Regional Administrative Court and essentially confirmed the cancellation of all administrative provisions subject to the dispute. The prescriptive framework for the companies thus becomes clear and definitive. The annulment of the provisions has, inter alia, retroactive effect at the time of their adoption and therefore allows to exclude the risk of claims against any possible breach of administrative provisions. (iii) Eni SpA – Syndial SpA – Raffineria di Gela – Claim for preventive technical inquiry. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and Syndial SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by the parents of children born malformed in the Municipality of Gela between 1992 and 2007. The claim for preventive technical inquiry aimed at verifying the relation of causality between the malformation pathologies suffered by the children of the plaintiffs and the environmental pollution caused by the Gela site (pollution deriving from activities conducted at the industrial plant by Raffineria di Gela SpA and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. In any case, the same issue was the subject of previous criminal proceedings, of which one closed without ascertainment of any illicit behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal on the matter, reaching very different outcomes. Thus, parties failed to reach a settlement of the matter. On December 2015, the three companies involved were sued in relation to a total of 30 cases of compensation for damages in civil proceedings. The proceedings are still pending. In May 2018, the Court issued a first instance judgment concerning one case. The Judge rejected the claim for damages, acknowledging the goodness and reasonableness of the arguments of the defendant companies in relation to the absence of evidences concerning the existence of a causal link between the pathologies and the alleged industrial pollution. The first-degree sentence was appealed before the Court of Caltanissetta. (iv) Syndial – Environmental claim relating to the Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio summoned Syndial before a Civil Court and sentenced Eni’s subsidiary to compensate the environmental damage relating to the site of Cengio. The request for environmental damage amounted to €250 million to which add health damage to be quantified during the proceeding. The plaintiffs accused Syndial of negligence in performing the clean-up and remediation of the site. In February 2013, the Court ruled a technical appraisal to verify the existence of the environmental damage. Following failed attempts to define a settlement agreement on the matter among the parties involved, the Judge resumed the trial and requested an independent appraisal on the matter. A first stage of the trial was filed in September 2018. The proceeding is still at the preliminary stage. (v) Syndial SpA and Versalis SpA – Summon for alleged environmental damage caused by illegal waste disposal in the Municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries Syndial and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff claimed the responsibilities of Syndial and Versalis for the production of waste and because they commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001-2003 which would have allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above-mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party (located about 2 kilometers away from the town of Melilli). Two subsidiaries of Eni and a third-party waste company were claimed to be jointly and severally liable of damage amounting to €500 million. The third-party company executed waste disposal at the site. In June 2017, the Judge accepted all the defensive instances of Syndial and Versalis, judging the requests of the Municipality to be inadmissible for lack of locus standi and considering the requests as unfounded or unproved, and sentenced the Municipality to the reimbursement of the expenses of the proceeding. In September 2017, the Municipality appealed the ruling requesting a new investigation and the admission of a technical appraisal, as well as the suspension of the enforcement of the sentence of first instance. The Court of Appeal rejected the counterclaim filed by the Municipality, which then filed an appeal before a third-degree Court to obtain the repeal of the part of the sentence about the expenses of the judgement, where Eni’s subsidiaries are part. Furthermore, the Municipality filed an appeal to overturn the first-degree sentence before another Court in Sicily, where the Eni’s subsidiaries are planning to take part. 2. Court inquiries (i) Eni SpA – Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. On January 2013, the Italian airline company Alitalia, which was undergoing a reorganization procedure, summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a compensation for alleged damages caused by a presumed anti- competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a deliberation filed by the Italian Antitrust Authority in June 2006. The antitrust deliberation accused Eni and other five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. The antitrust findings were substantially endorsed by an administrative Court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to €908 million. This was based on the presumption that the anti-competitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anti-competitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserted the incurrence of higher supply costs of jet fuel of €777 million excluding interest accrued and other items that add to lower profitability caused by a reduced competitive position in the marketplace estimated at €131 million. Another assessment of the overall damage made by Alitalia stand at €395 million of which €334 million of higher purchase costs CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018210 for jet fuel and €61 million of lower profitability due to the reduced competitive position on the marketplace. With a decision dated May 2014, the Court of Rome declared the connection with a judgment previously proposed by Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel agreement. The case was thus summed up by Alitalia before the Court of Milan. In September 2017, the Court of Milan ruled that: (i) the requests of Alitalia for the period 1998-2004 were prescribed; (ii) for the period subsequent to June 2006, no further assessment should be carried out, since Alitalia has failed to meet its burden of allegation; (iii) for the period between December 2004 and June 2006, a specific technical appraisal will be carried out. The judgment is pending in the first instance at the preliminary stage awaiting the fulfillment of the technical appraisal. Eni accrued a provision with respect to this proceeding. (ii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012-2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. The arbitration award dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considered that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, does not agree with GasTerra’s interpretation and considers GasTerra’s claim groundless. However, GasTerra, based on its own interpretation, commenced an arbitration and obtained from a Dutch Court the provisional seizure of Eni’s investment in its subsidiary Eni International BV (which at the time of the seizure i.e. at the reporting date June 30, 2016, stated consolidated net assets of €34.7 billion) for the alleged receivable due by Eni (equal to €1.01 billion). With respect to the interim seizure measure obtained by GasTerra, Eni offered to GasTerra, who in turn accepted, a bank guarantee of the same amount of the GasTerra claim. This guarantee is expected to remain effective until a final award by the arbitration procedure. The measure, which was granted after a summary review only and without Eni being heard, does not prejudice the outcome on the merits of the claims. The correct interpretation of the arbitration award and the 2012-2015 price revision will be subject to a new arbitration procedure. 3. Proceedings concerning criminal/administrative corporate responsibility (i) EniPower SpA. In June 2004, the Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower and on supplies from other companies to EniPower. It emerged that illicit payments were made by EniPower suppliers to a manager of EniPower who was immediately fired. The Court served EniPower (the commissioning entity) and Snamprogetti (now Saipem SpA) (contractor of engineering and procurement services) with notices of investigation in accordance with Legislative Decree No. 231/01 that establishes that the companies are liable for the crimes committed by their employees who acted on behalf of the employer. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions of Legislative Decree No. 231/01. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a specific proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations, while the trial ended with an acquittal of 15 individuals. In relation to the companies involved in the proceeding, the Court found that 7 companies are liable based on the provisions of Legislative Decree No. 231/01, imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem, which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni Group companies, reversing the prior decision made by the Court. This decision may have been made based on a pronouncement made by a Supreme Court that stated the illegitimacy of the constitution as plaintiffs against any legal entity, as indicted under the provisions of Legislative Decree No. 231/01. The condemned parties filed appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. In 2015, the Supreme Court annulled the judgment of the Second Degree Court ascribing the judgment to another section that, once more, confirmed the sentence of first instance, excepting the rulings of the previous appeal sentence not subject to annulment, including the statute of limitation. The grounds of the sentence have been filed confirming the motivations provided by the previous instance Courts. An appeal was filed at the Third Instance Court solely for the purposes of the civil proceeding. (ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to Eni’s former subsidiary Saipem in Algeria. In February 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem and Technip relating to the engineering of the ground section of a gas pipeline). The crime of international corruption is among the offenses contemplated by the Italian Legislative Decree No. 231/01 which provides for corporate liability for crimes committed by employees and prescribes punishments including fines and the disgorgement of profit. Eni also voluntarily provided to the Public Prosecutor documentation relating to the MLE project (in which Eni’s Exploration & Production Division participates), with respect to which investigations in Algeria are ongoing. In November 2012, the Public Prosecutor served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption in CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS211 accordance with Legislative Decree No. 231/01. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. Subsequently, the Public Prosecutor’s Office notified further measures and requests to Saipem, aimed at acquiring further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, the employment of whom was terminated at the beginning of 2013. In February 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Legislative Decree No. 231/01 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO, including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Following receipt of this notice, Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a team dedicated to the Algerian matters. During 2013, the external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department did not find any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on the MLE project, the only project that Eni understands to be under the prosecutors’ investigation where the client is an Eni Group company did not find evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal, accounting and administrative issues. The findings of that review confirmed the autonomy of Saipem from the parent company during the relevant periods. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. In January 2015, the Public Prosecutor notified the conclusion of preliminary investigations relating to Eni, Saipem and eight persons (including, the former CEO and CFO of Eni and the Chief Upstream Officer of Eni who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor issued a notice of alleged international corruption against all such persons (including Eni and Saipem on the basis of the provisions of Legislative Decree No. 231/01) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offenses for alleged fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. After receiving (i) the evidence collected in connection with the Public Prosecutor’s request to take testimony of two individuals under investigation in late 2014, and (ii) the minutes of the preliminary hearing and the documents filed in connection with the conclusion of the preliminary investigation, Eni requested that its consultants perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor requested the indictment of all the investigated persons for international corruption as well as the tax offenses mentioned above. In 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni, former Chief Executive Officer and Chief Upstream Officer for all the alleged offenses. In February 2016, the Court of Third Instance, upholding an appeal presented by the Public Prosecutor, reversed the dismissal, annulled the verdict, and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of the new preliminary hearing in July 2016, the Judge ordered the trial for all defendants, including Eni. Trial began in February 2017. At a hearing ion February 26, 2018, the Public Prosecutor, concluding his indictment, requested — among other things — the imposition on Eni of a pecuniary sanction. In September 2018, the Court of Milan rejected the requests of the Public Prosecutor and issued an acquittal verdict for Eni, for the former CEO and for the Company’s Chief Upstream Officer in relation to all charges. The former CFO of Eni was also acquitted of charges relating to Eni’s involvement in the MLE Project. In December 2018 the Court filed a written opinion setting forth the basis for its rulings. The Public Prosecutor and the other parties who were convicted in the first trial have appealed under the terms of the law. A hearing on those appeals is pending. At the end of 2012, Eni contacted the US Department of Justice (DoJ) and the US SEC in order to voluntarily inform them about this matter, and has kept them informed about the developments in the Italian prosecutors’ investigations. Following Eni’s notification in 2012, both the US SEC and the DoJ started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests. (iii) Block OPL 245 – Nigeria. In July 2014, the Public Prosecutor of Milan served Eni with a notice of investigation relating to potential liability on the part of Eni arising from alleged international corruption, pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. As part of the investigation, Eni was also subpoenaed for documents and other evidence. According to the subpoena, the proceeding was commenced following a claim filed by NGO ReCommon relating to alleged corruptive practices that according to the Public Prosecutor allegedly involved the Resolution Agreement made on April 29, 2011 relating to the Oil Prospecting License of the offshore oilfield that was discovered in Block 245 in Nigeria. Eni fully cooperated with the Public Prosecutor and promptly filed the requested documentation. Furthermore, Eni voluntarily reported the matter to the US Department of Justice and the US SEC. In July 2014, Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the US lawyers concluded in summary that they detected no evidence of CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 212 wrongdoing by Eni side in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. The outcome of this review was transmitted to the Judicial Authorities. In September 2014, the Public Prosecutor notified Eni of a restraining order issued by a British judge who ordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Public Prosecutor. During a hearing before a Court in London in September 2014, Eni and its current executive officers stated their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court reaffirmed the seizure. In December 2016, the Public Prosecutor of Milan notified Eni of the conclusion of the preliminary investigation and requested the indictment of Eni’s CEO, the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations, as well as Eni’s former CEO and Eni based on Italian law 231/2001 on corporate entity responsibility. Upon the notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, the independent US-based law firm was requested to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the prior review. The US law firm was also provided with the documentation filed in the Nigerian proceeding mentioned below. The independent US law firm concluded that the reappraisal of the matter in light of the new documentations available did not alter the outcome of the prior review. In December 2017, the Judge for Preliminary Investigation ordered the indictment of all the parties mentioned above, and other parties under investigation by the Public Prosecutor, before the Court of Milan. During the first trial hearing in March 2018, the the Federal Republic of Nigeria requested permission to join the case as a civil party. Several NGOs, which had made the same request before the Judge of the Preliminary Hearing and been denied, also asked to join as civil parties. At a hearing in May 2018, a Non-Governmental Organization, Asso Consum, also requested to be recognized as a civil claimant in the proceeding. At the subsequent hearing in June 2018, counsel for the Federal Government of Nigeria (“FGN”) reiterated the request for the admission as civil claimants in the proceedings of all the parties that sought leave to join the action as civil claimants in March 2018. At the same time, the attorney requested that Eni and Shell be recognized as defendants with respect to those parties’ civil claims. Furthermore, a shareholder of Eni asked to be recognized as a civil claimant. At the hearing of July 20, 2018, the Judge (i) granted the FGN’s request to join the proceeding as a civil claimant and (ii) rejected that request with respect to the NGOs, Asso Consum and the shareholder of Eni. Therefore, the FGN is the only civil party admitted by the Court. The first instance trial of the Milan Prosecutor’s OPL 245 charges began before the Court of Milan on June 20, 2018 and is currently ongoing. In a separate criminal proceeding, two defendants, neither of whom is a current or former employee of the Company, chose to have their liability determined by the Judge for the Preliminary Hearing on the basis of the evidence presented by the Milan Prosecutor at the preliminary hearing. In September 2018, the Judge convicted these defendants and sentenced them both to four-year detention terms and the disgorgement of profits amounting to approximately €100 million. In December 2018, the Judge for the Preliminary Hearing filed a written opinion setting forth the basis for these rulings. The defendants filed an appeal against this sentence. In January 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd (“NAE”) became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court upon request from the Nigerian Economic and Financial Crimes Commission (EFCC), attaching OPL 245 temporarily pending a proceeding in Nigeria relating to alleged corruption and money laundering. After making this application, Eni became aware of a formal filing of charges by the EFCC against NAE and other parties. In March 2017, the Nigerian Court revoked the Order. To NAE’s knowledge EFCC charges have not been dropped but none of the defendants were served nor arraigned. Eni has provided a copy of the Order and the attached documents, including the charges filed by the EFCC, to the US-based law firm engaged to review the OPL 245 transaction, who upon review of such documents, did not modify their conclusion that they did not detect evidence of wrongdoing by Eni in relation to the acquisition of the OPL 245 from the Nigerian government. In November 2018, Eni SpA and its subsidiaries NAE, NAOC and AENR (as well as some companies of the Shell Group) were notified of the intention of the FGN to bring a civil claim before an English Court to obtain compensation for the damages allegedly deriving from the transaction that resulted in assignment of the OPL 245 to NAE and SNEPCO (Shell subsidiary). Subsequently, Eni obtained a copy of the documentation reflecting the commencement of the case, but neither Eni nor other companies of the Group received any notification regarding this proceeding. (iv) Congo. In March 2017, the Italian Finance Police served on Eni an information request pursuant to the Italian Code of Criminal Procedure connection with an investigative file opened by the Public Prosecutor of Milan against unknown persons. The request related in particular to the agreements signed by Eni Congo SA with the Ministry of Hydrocarbons of the Republic of Congo in 2013, 2014 and 2015 in relation to exploration, development and production activities concerning certain permits held by Eni Congo SA for Congolese projects and Eni’s relationships with Congolese companies that hold stakes in those projects. In July 2017, the Italian Financial Police, on behalf of the Public Prosecutor of Milan, served Eni with another information request and a notice of investigation pursuant to Italian Legislative Decree No. 231/01 for alleged international corruption. The request expressly stated that it was based in part on the March 2017 information request and concerned the relationship of Eni and its subsidiaries with certain third-party companies from 2012 to the present. Eni produced all of the documentation requested in March and July 2017 and voluntarily disclosed this matter to the relevant US authorities (SEC and DoJ). On January 26, 2018, the Public Prosecutor’s Office requested a six-months extension of the deadline for conducting its preliminary investigation into this matter, from January 31, 2018 until July 30, 2018. Subsequently in July 2018, the Public Prosecutor requested a second extension until February 28, 2019. In April 2018, the Public Prosecutor of Milan served on Eni SpA a further request for documentation and notified an Eni employee, who was the then Chief Development, Operation & Technology Officer, of a search order stating that he and another Eni manager had been placed under investigation. In October 2018, Public Prosecutor ordered the seizure of an e-mail account of another Eni manager, who was formerly the general director of Eni in Congo during the period 2010-2013. In December 2018, the Public Prosecutor of Milan issued a request to the Company for documents pursuant to article 248 of the Code of Criminal Procedure, concerning some economic transactions CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 213 between Eni Group companies and certain companies. In February 2019, Eni received an informative note that the preliminary investigations would extend until October 2019. In April 2018, the Board of Statutory Auditors, the Watch Structure and the Control and Risk Committee of Eni jointly appointed an independent law firm and a professional consulting company, knowleadgeable in the matter of anti-corruption, to carry out a forensic review of facts relating to Eni’s work in Congo. Based on the preliminary results of such review, that is still on-going, there were no factual evidence about the involvement of Eni, nor of any Eni’s employees and key managers in the alleged crimes. On June 4, 2018, the Italian market regulator, Consob, requested information about the above mentioned proceeding from Eni and its Board of Statutory Auditors. Specifically, Eni was asked to provide information about the Congo investigations and the action implemented by the Company and any eventual outcome, including specific audit activities performed by the Company’s staff and any task assigned to external parties to review the ongoing investigations. The Company was also asked to transmit supporting evidence and documentation. The Eni Board of Statutory Auditors was asked to report about the monitoring activity performed on the investigations. The Company and its Board of Statutory Auditors answered these requests for information on June 11 and 13, 2018, respectively. 4. Other proceedings concerning criminal matters (i) Eni SpA (R&M) – Criminal proceedings on fuel excise tax. A criminal proceeding is currently pending, relating to alleged evasion of excise taxes in the context of the retail sales in the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. This proceeding (No. 7320/2014 RGNR) concerns the reunification of three distinct investigations: (i) a first proceeding, opened by the Public Prosecutor’s Office of Frosinone involved a company (Turrizziani Petroli) purchaser of Eni’s fuel. This investigation was subsequently extended to Eni. The Company fully cooperated and provided all data and information concerning the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Eni collaborated fully providing all the required documentation. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. After the end of the investigation, the financial police of Frosinone, along with the local Customs Agency, in November 2013 issued a claim related to the missing payment of excise taxes in the 2007-2012 period for €1.55 million. In May 2014, the Customs Agency of Rome issued a payment notice relating to the abovementioned claim that was filed by the financial police and Customs Agency of Frosinone. The Company appealed to the Tributary Commission. In March 2018, the Commission filed the ruling of the sentence which accepted Eni’s appeal against the claim of the Custom Agency and required the latter to refund the proceeding expenses; (ii) a second proceeding, concerning a line of investigation of the Public Prosecutor’s Office of Prato, commenced in regard to the deposit of Calenzano and relates to subtraction of fuel through manipulation of the fuel dispensers, subsequently extended also to the Refinery of Stagno (Livorno); (iii) a third proceeding, opened by the Public Prosecutor’s Office of Rome, regarded alleged missing payment of excise tax on the surplus of the unloading products, as the quantity of such products was larger than the quantity reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above and substantially concerns similar facts presenting, however, some differences with regard to the nature of the alleged crimes and the responsibility subjected to verification. The second and the third proceeding were merged in the proceeding commenced by Public Prosecutor’s Office of Rome. In fact, the Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at habitual subtraction of oil products at all of the 22 storage sites which are operated by Eni over the national territory. Eni is cooperating with the Prosecutor in order to defend the correctness of its operation. On September 2014, a search was conducted at the office of the former chief of the R&M Division in Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relates to a period of time when the officer was in charge at Eni’s R&M Division. On March 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer at the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. The proceeding was then extended to a large number of employees and former employees of the Company. In November 2017, the Court of Rome, following the request of the Public Prosecutor, ordered a preventive seizure of the oil products meters at Eni’s refineries and depots in Italy. The Company, considering the consequences connected to a complete shutdown of the refining and fueling activities, requested the Public Prosecutor to minimize, as much as possible, the impact on customers, companies and service stations. The preventive seizure was revoked, due to the commitments undertaken by the Company which is a third party not subject to investigation. Eni continues to provide full cooperation to the authorities. In December 2017, technical consultants were designed by Eni to verify the integrity of the sites. The results will be provided to the judicial authorities. In March 2018, the Public Prosecutor of Rome notified the conclusion of the preliminary investigations in relation to the criminal proceeding No. 7320/2014 concerning the Calenzano, Livorno, Sannazzaro, Pomezia, Naples, Gaeta and Ortona sites. Based on the outcome of the investigations, as far as Eni is concerned, the proceeding involves former managers and directors of the refineries indicated above concerning alleged aggravated and continuous non-payment of excise duties, alteration and removal of seals, use and possession of false measures and weights. In addition for Calenzano, three employees and their manager of the storage site were indicted on charges of alleged procedural fraud. The attorneys of the defendants delivered documentations and requested the Public Prosecutor to dismiss the case. In September 2018, Eni received, as offended party, the notification of the schedule of hearing issued by the Court of Rome, in relation to criminal association and other minor claims, against numerous persons under investigation – including over forty Eni employees – CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 214 subject of a separated proceeding (No. 22066/17 RGNR), for which, in May 2017, the Public Prosecutor’s Office had requested the filing. At the end of the hearing in December 2018, the Judge accepted the request for dismissal for several persons under investigation, including thirteen Eni’s employees, while he rejected the request, requiring the Public Prosecutor to pronounce the charge in terms and forms of law for twenty-eight Eni employees (including the former managers of the R&M Division) for criminal association. In October 2018, as regards the main criminal proceeding, the Public Prosecutor notified the date for the preliminary hearing and the related request for indictment. In April 2018 as part of the administrative proceeding intended to collect taxes allegedly not paid by Eni, the tax police of Rome based on the findings of the investigations performed by the prosecutors of Frosinone, Prato and Rome issued a statement of objection against the Company claiming the missed payment of excise taxes due for the years 2008 up to 2017 for €34 million, as well as the related higher corporate profits before income taxes leading to the claim of additional taxes for €22 million related to income taxes and VAT. The Custom Agency that is in charge of issuing the notice of payment may also impose a fine and the recognition of interest expense. A part of the litigation, for which omitted payment is disputed, relates to the same transactions successfully challenged by the Company against the Tax Commission of Rome. The Company will appeal at the appropriate forum. Eni accrued a provision with respect to this proceeding. (ii) Eni SpA – Public Prosecutor of Milan – Criminal proceeding No. 12333/2017. In February 2018, Eni was notified of a search and seizure decree in relation to allegations of associative crime aimed at slander and at reporting false information to a Public Prosecutor. In the decree, the Prosecutor of Milan included, among the other persons under investigation, the former Chief Legal and Regulatory Affairs Officer of Eni, currently the Chief Gas & LNG Marketing and Power Officer of the Company. Eni is not under investigation. According to the decree, the association would be allegedly aimed at interfering with the judicial activity in certain criminal proceedings that are involving, among others, Eni and some of its directors and managers. Afterwards, the Control and Risks Committee, having consulted the Board of Statutory Auditors, and together with the Watch Structure, agreed to engage auditing firm to perform an internal audit of all relevant facts and circumstances and all records and documentation on the matter with respect to the events of the aforementioned proceeding, including a forensic review. The final report, submitted to the Control and Risk Committee, the Watch Structure and the Board of Statutory Auditors on September 12, 2018, concluded that following the review carried out with respect to the allegations made by the Public Prosecutor of Milan, there would be no sufficient factual evidence about the involvement of the former Chief Legal manager and Regulatory Affairs manager of Eni in the alleged crimes. In April 19, 2018, the Board of Directors appointed two external consultants, a criminal lawyer and a civil lawyer to provide independent legal advice in relation to the facts under investigation. The outcomes illustrated in two reports, dated November 22, 2018 and February 14, 2019, did not highlight circumstances in fact suitable any direct involvement of any Eni’s employees in the crimes alleged by the Public Prosecutor. Both reports were presented to the Board of Directors, to the Board of Statutory Auditors and to the Watch Structure of Eni. On June 4, 2018 Consob, the Italian market regulator, requested to be informed about the above mentioned proceeding. The request was addressed to the Company and to its Board of Statutory Auditors. Specifically, Consob asked for the outcome of the forensic review and to be updated about any other audit action taken in relation to the matter by the Company and by its board of Statutory Auditors. The Board of Statutory Auditors was also requested to report about the findings of the additional audit program agreed with the external auditor regarding the matter and to keep Consob updated about any further initiative adopted. The Company and its Board of Statutory Auditors answered the request of information on June 11 and June 13, 2018, respectively. Subsequently, the Company finalized its response by sending further documentation including the final report of the audit firm and the reports of the consultants.The Board of Statutory Auditors has periodically updated Consob of the initiatives taken as part of the Board’s monitoring responsibilities with communications transmitted on September 21, December 3 and 20, 2018 and on February 19, 2019. On June 13, 2018, Eni was notified of a request from the Prosecutor Office to transmitting certain documentation in accordance with the provision of the Italian penal code. The request targeted evidence and documents relating to the internal audit performed by the Company and any possible external review concerning certain tasks that were assigned to an external lawyer with respect to Eni. This lawyer appears to be investigated as part of this proceeding. The reports of the consultants of the Board of Directors and of the independent third party were sent to the Judicial Authority. (iii) Eni SpA – Public Prosecutor of Milan – Insider trading. In March 2019, a request for extending certain investigations was notified to Eni’s Chief Upstream Officer by the Public Prosecutor Office of Milan. The commencement of those investigation was otherwise not notified. The investigations related to an alleged breach of Italian provisions that regulate insider trading and access to market-sensitive information. The breach was allegedly made from November 1 to December 1, 2016. There were no more informative details about the alleged breach in the notified document. 5. Settled Proceedings (i) Syndial SpA – Clorosoda. The proceeding, involving 17 former managers of the Eni Group, regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases that those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced operations, until 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested a medical appraisal on over 100 people who had been employed at the plant. This appraisal was performed by independent consultants designated by the Judge for preliminary investigation and did not find any evidence that the various diseases identified from the medical appraisal could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. Following the outcome of the assessment, the Public Prosecutor of Gela issued a notice of conclusion of preliminary investigations in relation to 4 cases, contesting personal injuries and claimed the CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 215 indictment only in one case concerning a worker who died in the meantime. Therefore, compared to the initial claim that concerned several (more than one hundred) cases of personal injury and manslaughter, the proceeding was narrowed. In June 2017, the Judge issued a ruling of nonsuit because the case was judged groundless. The Public Prosecutor appealed the first-degree sentence. In September 2018, the Second Instance Court in its final decision did not accept the appeal presented by the Public Prosecutor. Also for the proceeding concerning the four cases that are part of a separate proceeding, the Judge issued a ruling of nonsuit, which became irrevocable in February 2018. (ii) Eni SpA – Raffineria di Gela SpA – Eni Mediterranea Idrocarburi SpA - Syndial SpA. In December 2015, 273 Gela residents filed an appeal to the Court of Gela requesting to halt all the production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to alleged environmental pollution affecting the health of the local population. The claimants also requested the appointment of commissioners in charge of carrying out the plant shutdown and of continuing implementing of clean-up activities in the area. They also requested the Court to order the Municipality of Gela – as a competent body in the field of health protection – to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was carried out by certain technical assessments performed by consultants appointed by the Court in the preliminary stage. The aim of these assessments was to establish cause-and-effect relationships between the industrial contamination and congenital anomalies reported in the town of Gela. Following the outcome of the investigation, in December 2017 the Court of Gela rejected all the claims of the plaintiffs and ordered them to pay the expenses of the proceeding. The plaintiffs appealed the decision. In September 2018, the Court rejected the appeal presented by the appellants, confirming the order issued by the First Instance Court. The precautionary procedure promoted is therefore definitively concluded. Assets under concession arrangements Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each Country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and, in some legal contexts, private owners. Pursuant to the assignment of mineral concession, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. In production sharing agreement and service contracts, realized productions are defined based on contractual agreements with State oil companies, which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). In the Refining & Marketing business line, several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration. Environmental regulations Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the “Financial Review”, paragraph “Risk factors and uncertainties”. In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries. Emission trading From 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no- consideration scheme based on historical emissions to allocation through auctioning. For the period 2013-2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric sector that is not eligible for allocations for no consideration. This regulatory scheme implies for Eni’s plants subjected to emission trading a lower assignment of emission permits respect to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2018, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately 19.93 million tonnes, Eni was awarded free emission allowances of 7.25 million tonnes, determining a deficit of 12.68 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018216 28 | Revenues NET SALES FROM OPERATIONS (€ million) 2018 Revenues from customers Products sales and service revenues Sales of: - crude oil - oil products - natural gas and LNG - chemical products - other products Services Total Transfer of goods and/or services Goods/Services transferred in a specific moment Goods/Services transferred over a period of time Exploration & Production Gas & Power Refining & Marketing and Chemicals Corporate and other activities Total 9,943 43,109 22,594 176 75,822 3,982 1,133 4,554 27 247 9,943 9,676 267 18,471 4,053 15,088 762 2,363 2,372 43,109 17,213 4,777 20 584 22,594 42,979 130 22,535 59 35 11 130 176 106 70 22,453 22,399 19,642 5,574 2,421 3,333 75,822 75,296 526 2018 342 11 (€ million) Revenues associated with liabilities from customer contracts at the beginning of the period Revenues associated with performance obligations totally or partially satisfied in previous years Sales from operations by industry segment and geographical area of destination are disclosed in note 35 – Segment information and information by geographical area. Sales from operations with related parties are disclosed in note 36 – Transactions with related parties. OTHER INCOME AND REVENUES (€ million) Gains from sale of assets and businesses Other proceeds 2018 454 662 1,116 2017 3.288 770 4,058 2016 14 917 931 Gains from the sale of assets and businesses related to the divestment of a 10% stake in the Zohr project for €428 million. In 2017, the amount related million to the divestment of a 25% stake in natural gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40% stake in the Zohr project (€1,281 million). Other income and revenues with related parties are disclosed in note 36 – Transactions with related parties. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS29 | Costs PURCHASE, SERVICES AND OTHER (€ million) Production costs - raw, ancillary and consumable materials and goods Production costs - services Operating leases and other Net provisions for contingencies Expenses for price variation on overliftling and underlifting operations Other expenses less: - capitalized direct costs associated with self-constructed assets - tangible assets - capitalized direct costs associated with self-constructed assets - intangible assets 217 2018 41,125 10,625 1,820 1,120 1,130 55,820 (192) (6) 55,622 2017 35,907 12,228 1,684 886 145 931 51,781 (224) (9) 51,548 2016 27,783 12,727 1,672 505 240 666 43,593 (297) (18) 43,278 Purchase, services and other charges include costs of geological and geophysical studies for €287 million (€273 million and €204 million in 2017 and 2016, respectively) and operating leases for €872 million (€1,022 million and €566 million in 2017 and 2016, respectively). Costs incurred in connection with research and development activities expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €197 million (€185 million and €161 million in 2017 and 2016, respectively). Royalties on the extraction of hydrocarbons amounted to €1,043 million (€674 million and €572 million in 2017 and 2016, respectively). Future minimum lease payments expected to be paid under non- cancelable operating leases are provided below: (€ million) To be paid: - within 1 year - between 2 and 5 years - beyond 5 years 2018 2017 2016 776 1,653 1,524 3,953 883 1,710 1,939 4,532 593 1,040 785 2,418 Operating leases primarily comprised long-term rentals of FPSO vessels, offshore drilling rigs, time charter and land, service stations and office buildings. Such leases may not include renewal options. There are no significant restrictions provided by these operating leases that may limit the ability of Eni to pay dividends, use assets or take on new borrowing. Additions to provisions for contingencies net of reversal of unused provisions related to net additions for litigations amounting to €101 million (net additions of €375 million and €55 million in 2017 and 2016, respectively) and net additions for environmental liabilities amounting to €266 million (net additions of €200 million and €198 million in 2017 and 2016, respectively). More information is provided in note 20 – Provisions for contingencies. Provisions for contingencies by segment are disclosed in note 35 – Segment information and information by geographical area. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018218 PAYROLL AND RELATED COSTS (€ million) Wages and salaries Social security contributions Cost related to employee benefit plans Other costs less: - capitalized direct costs associated with self-constructed assets - tangible assets - capitalized direct costs associated with self-constructed assets - intangible assets 2018 2,409 448 220 170 3,247 (142) (12) 3,093 2017 2,447 441 113 162 3,163 (202) (10) 2,951 2016 2,491 445 81 202 3,219 (215) (10) 2,994 Other costs comprised provisions for redundancy incentives of €37 million (€18 million and €47 million in 2017 and 2016, respectively) and costs for defined contribution plans of €95 million (€90 million and €83 million in 2017 and 2016, respectively). Cost related to employee benefit plans are described in note 21 – Provisions for employee benefits. Costs with related parties are disclosed in note 36 – Transactions with related parties. Average number of employees The Group's average number and breakdown of employees by category is reported below: (number) Senior managers Junior managers Employees Workers 2018 2017 2016 Subsidiaries 999 9,095 16,220 5,259 31,573 Joint operations 17 84 361 283 745 Subsidiaries 995 9,089 16,721 5,659 32,464 Joint operations 17 98 371 285 771 Subsidiaries 1,018 9,160 17,180 5,703 33,061 Joint operations 18 109 384 294 805 The average number of employees was calculated as the average between the number of employees at the beginning and the end of the period. The average number of senior managers included managers employed in foreign Countries, whose position is comparable to a senior manager’s status. Long-term monetary incentive plan for the managers of Eni On April 13, 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017-2019 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the Plan. The Long-Term Monetary Incentive Plan 2017-2019 provides for three annual awards for the years 2017, 2018 and 2019 and is intended for the Chief Executive Officer of Eni and for the managers of Eni and its subsidiaries who qualify as “senior managers deemed critical for the business”, selected among those who are in charge of tasks directly linked to the Group results or of strategic interest to the business. The Plan provides the granting of Eni shares for no consideration to eligible managers after a three-year vesting period under the condition that they would remain in service until vesting. Considering that this incentive falls within the category of employee compensation, in accordance with IFRS, the cost of the plan is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that will be granted at the end of the vesting period; the cost is accruing along the vesting period. The number of shares that will be granted at the end of the vesting period is conditioned on a 50-50 basis to actual results of two performance parameters against preset targets: (i) a market condition in terms of Total Shareholder Return (TSR) of the Eni share compared to the TSR of the FTSE Mib index of the Italian Stock Exchange Market, and to a group of Eni’s competitors (“Peers Group”)29 and the TSR of their corresponding stock exchange market30; (ii) growth in the Net Present Value (NPV) of proved reserves benchmarked against the Peer Group. Depending on the performance of the parameters mentioned above, the number of shares that will vest after three years may range between 0% and 180% of the initial award. Furthermore, 50% of the shares that will eventually vest is subject to a lock-up clause of one year after the vesting date. At the grant date, the number of shares awarded was 1,517,975 and 1,719,061 respectively in 2018 and in 2017; the weighted average fair value of the shares at the same date was €11.73 and €7.99 per share. (29) The group consists of the following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and Total. (30) The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS219 The determination of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plan (the stochastic method for the market condition of the plan and the Black-Scholes model for the component related to the NPV of the reserves), taking into account the fair value of the Eni share at the grant date (€14.246 per share in 2018; €13.81 per share in 2017), reduced by dividends expected along the vesting period (5.8% of the share price at vesting date), the volatility of the stock (20% for attribution 2018; 25% for attribution 2017), the forecasts for the performance parameters, as well as the lower value attributable to the shares considering the lock-up period at the end of the vesting period. In 2018, the costs related to the long-term monetary incentive plan 2017-2019, recognized as a component of the payroll cost, amounted to €5.1 million (€0.4 million in 2017) with a contra-entry to equity reserves. Compensation of key management personnel Compensation (including contributions and ancillary costs) of personnel holding key positions in planning, directing and controlling Eni Group's subsidiaries, including executive and non- executive officers, general managers and managers with strategic responsibilities in service during the year consisted of the following: (€ million) Wages and salaries Post-employment benefits Other long-term benefits Indemnities upon termination of employment 2018 27 2 10 39 2017 25 2 9 7 43 2016 26 2 12 4 44 Compensation of Directors and Statutory Auditors Compensation of Directors amounted to €9.6 million, €14.5 million and €7.1 million for 2018, 2017 and 2016, respectively. Compensation of Statutory Auditors amounted to €0.604 million, €0.760 million and €0.738 million in 2018, 2017 and 2016, respectively. Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax. 30 | Finance income (expense) (€ million) Finance income (expense) Finance income Finance expense Net finance income (expense) from financial assets held for trading Income (expense) from derivative financial instruments The analysis of finance income (expense) was as follows: (€ million) Finance income (expense) related to net borrowings - Interest and other finance expense on ordinary bonds - Net finance income (expense) on financial assets held for trading - Interest due to banks and other financial institutions - Interest and other income on financial receivables and securities held for non-operating purposes - Interest from banks Exchange differences Income (expense) from derivative financial instruments Other finance income (expense) - Interest and other income on financing receivables and securities held for operating purposes - Capitalized finance expense - Finance expense due to the passage of time (accretion discount)(a) - Other finance income (expense) (a) The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities. 2018 2017 2016 3,967 (4,663) 32 (307) (971) 3,924 (5,886) (111) 837 (1,236) 5,850 (6,232) (21) (482) (885) 2018 2017 2016 (565) 32 (120) 8 18 (627) 341 (307) 132 52 (249) (313) (378) (971) (638) (111) (113) 16 12 (834) (905) 837 128 73 (264) (271) (334) (1,236) (639) (21) (118) 37 15 (726) 676 (482) 143 106 (312) (290) (353) (885) CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018220 The analisys of derivative financial income (expense) is disclosed in note 23 – Derivative financial instruments and hedge accounting. Finance income (expense) with related parties are disclosed in note 36 – Transactions with related parties. 31 | Income (expense) from investments SHARE OF PROFIT (LOSS) OF EQUITY-ACCOUNTED INVESTMENTS More information is provided in note 14 – Investments. Share of profit or loss of equity-accounted investments by segment is disclosed in note 35 – Segment information and information by geographical area. OTHER GAIN (LOSS) FROM INVESTMENTS (€ million) Dividends Net gain (loss) on disposals Other net income (expense) 2018 231 22 910 1,163 2017 205 163 (33) 335 2016 143 (14) (183) (54) Dividend income related to Nigeria LNG Ltd for €187 million and to Saudi European Petrochemical Co for €35 million (similarly in the comparative periods). Other net income included the gain of €889 million deriving from the business combination between Eni Norge AS and Point Resources AS, fully-owned respectively by Eni and HitecVision AS, with the establishment of the joint venture Vår Energi AS, jointly controlled by the two shareholders and was determined as difference between the carrying amount of the equity investment, corresponding to the fair value of the combined net assets, and the book value of the divested net assets. In the comparative periods the expenses referred to the impairments of joint ventures and associates. 32 | Income taxes (€ million) Current taxes: - Italian subsidiaries - subsidiaries of the Exploration & Production segment - outside Italy - other subsidiaries - outside Italy Net deferred taxes: - Italian subsidiaries - subsidiaries of the Exploration & Production segment - outside Italy - other subsidiaries - outside Italy 2018 2017 2016 301 4,906 163 5,370 130 497 (27) 600 5,970 712 3,167 142 4,021 (464) (162) 72 (554) 3,467 195 2,671 133 2,999 (243) (813) (7) (1.063) 1,936 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS221 Current income taxes payable by Italian subsidiaries referred to foreign taxes for €241 million. The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 24% (24% in 2017 and 27.5% in 2016) and the effective tax charge is the following: (€ million) Profit (loss) before taxation Tax rate (IRES) (%) Statutory corporation tax charge (credit) on profit or loss Increase (decrease) resulting from: - higher tax charges related to subsidiaries outside Italy - impact pursuant to the write-off of deferred tax assets and recalculation of tax rates - effect due to the tax regime provided for intercompany dividends - Italian regional income tax (IRAP) - effect due to non-taxable gains/losses on sales of investments - impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009 - other adjustments Effective tax charge 2018 10,107 24.0 2,426 3,096 252 47 50 (1) 100 3,544 5,970 2017 6,844 24.0 1,643 1,882 (96) 1 77 (177) 61 76 1,824 3,467 2016 892 27.5 245 1,152 397 87 42 8 5 1,691 1,936 The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €3,014 million (€1,811 million and €1,211 million in 2017 and in 2016, respectively). 33 | Earnings per share Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares. The average number of ordinary shares used for the calculation of the basic earnings per share in 2018 was 3,601,140,133 (same amount in 2017 and 2016). Diluted earnings per share is calculated by dividing the net profit of the period attributable to Eni’s shareholders by the weighted average number of shares fully-diluted including shares outstanding in the year and the number of potential shares to be issued in connection with stock-based compensation plans. As of December 31, 2018, the shares that could be potentially issued related the estimation of new share that will vest in connection with the long-term monetary incentive plan. The weighted average number of outstanding shares used for calculating the diluted earnings per share is 2,782,584 for 2018 (1,691,413 for 2017). In 2016, there were no potential shares with dilutive effects. Reconciliation of the weighted average number of shares used for the calculation for both basic and diluted earnings per share was as follows: Weighted average number of shares used for the calculation of the basic earnings per share Potential share to be issued for ILT incentive plan Weighted average number of shares used for the calculation of the diluted earnings per share Eni’s net profit Basic earning (loss) per share Diluted earning (loss) per share Eni’s net profit - Continuing operations Basic earning (loss) per share Diluted earning (loss) per share Eni’s net profit - Discontinued operations Basic earning (loss) per share Diluted earning (loss) per share 2018 2017 2016 3,601,140,133 3,601,140,133 3,601,140,133 2,782,584 1,691,413 3,603,922,717 3,602,831,546 3,601,140,133 4,126 1.15 1.15 4,126 1.15 1.15 3,374 0.94 0.94 3,374 0.94 0.94 (1,464) (0.41) (0.41) (1,051) (0.29) (0.29) (413) (0.12) (0.12) (€ million) (euro per share) (euro per share) (€ million) (euro per share) (euro per share) (€ million) (euro per share) (euro per share) CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 222 34 | Exploration for evaluation of Oil & Gas resources (€ million) Revenues related to exploration activity and evaluation Exploration activity and evaluation costs - write-off of exploration and evaluation costs - costs of geological and geophysical studies Exploration expense for the year Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs Tangible assets: capitalized exploration and evaluation costs Total tangible and intangible assets Provision for decommissioning related to exploration activity and evaluation Exploration expenditure (net cash used in investing activivties) Geological and geophysical costs (cash flow from operating activities) Total exploration effort 35 | Segment information and information by geographical area SEGMENT INFORMATION 2018 17 93 287 380 1,081 1,267 2,348 77 463 287 750 2017 9 252 273 525 995 1,371 2,366 81 442 273 715 2016 4 170 204 374 1,092 1,905 2,997 118 417 204 621 Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to make decisions about resources to be allocated to each segment and to assess segment performance. Segment performance is evaluated based on operating profit or loss. Other segment information presented to the CEO include segment revenues and directly attributable assets and liabilities. As of December 31, 2018, Eni had the following reportable segments: Exploration & Production: engages in the exploration, development and production of crude oil, LNG and natural gas, including projects to build and operate liquefaction plants of natural gas. Gas & Power: engages in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply, production and marketing of power at retail and wholesale markets. Gas & Power is engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the Group industrial and commercial margins according to an integrated view and to optimize margins. Refining & Marketing and Chemicals: engages in the manufacturing, supply and distribution and marketing activities of oil products and chemical products. The results of the Chemicals business have been aggregated to those of the Refining & Marketing business in a single reportable segment, because these two operating segments exhibit similar economic characteristics. Corporate and other activities: include the costs of the Group HQ functions which provide services to the operating subsidiaries, comprising holding, financing and treasury, IT, HR, real estate, legal assistance, captive insurance, planning and administration activities, as well as the results of the Group environmental cleanup and remediation activities performed by the subsidiary Syndial. The Energy Solutions Department, which engages in developing the business of renewable energy, is an operating segment, which is reported within Corporate and other activities because it does not meet the materiality threshold for separate segment reporting. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS223 n o i t c u d o r P & n o i t a r o l p x E 25,744 (15,801) 9,943 10,214 235 6,152 1,025 299 97 158 63,051 r e w o P & s a G 55,690 (12,581) 43,109 629 53 408 56 127 1 9 9,989 4,972 18,110 494 8,314 s l a c i m e h C d n a i & g n n fi e R g n i t e k r a M 25,216 (2,622) 22,594 (380) 274 399 193 2 (67) 11,692 275 4,319 s e i t i v i t c a r e h t o d n a e t a r o p r o C 1,589 (1,413) 176 (691) 579 59 18 (168) 1,171 1,303 4,072 s t n e m t s u d A j p u o r g a r t n i f o s t fi o r p 211 (21) (30) (420) (275) 7,901 215 877 143 (17) 19,525 (12,394) 7,131 7,651 479 6,747 650 808 260 (99) 66,661 50,623 (10,777) 39,846 75 (20) 345 56 202 2 (10) 11,058 22,107 (2,336) 19,771 981 182 360 131 77 1 (57) 11,599 1,234 17,273 509 8,851 321 4,005 1,462 (1,291) 171 (668) 245 60 25 (101) 1,108 1,447 4,053 (27) (29) (610) (306) 7,739 142 729 87 (16) 16,089 (9,711) 6,378 2,567 123 6,772 740 1,440 153 (198) 75,716 1,626 17,433 40,961 (8,898) 32,063 (391) 50 354 167 86 2 19 12,014 18,733 (1,605) 17,128 723 171 389 120 16 195 (3) 10,712 592 8,923 289 3,968 1,343 (1,150) 193 (681) 438 72 40 (144) 1,146 1,533 3,939 (61) (277) (28) (520) (332) 8,254 120 664 55 87 l a t o T 75,822 9,983 1,120 6,988 1,292 426 100 (68) 85,483 32,890 7,044 34,540 32,760 9,119 66,919 8,012 886 7,483 862 1,087 263 (267) 89,816 25,112 3,511 33,876 32,973 8,681 55,762 2,157 505 7,559 1,067 1,542 350 (326) 99,068 25,477 4,040 33,931 37,528 9,180 Information by segment is as follows: (€ million) 2018 Net sales from operations(a) Less: intersegment sales Net sales to customers Operating profit Net provisions for contingencies Depreciation and amortization Impairments of tangible and intangible assets Reversals of tangible and intangible assets Write-off Share of profit (loss) of equity-accounted investments Identifiable assets(b) Unallocated assets Equity-accounted investments Identifiable liabilities(c) Unallocated liabilities Capital expenditure in tangible and intangible assets 2017 Net sales from operations(a) Less: intersegment sales Net sales to customers Operating profit Net provisions for contingencies Depreciation and amortization Impairments of tangible and intangible assets Reversals of tangible and intangible assets Write-off Share of profit (loss) of equity-accounted investments Identifiable assets(b) Unallocated assets Equity-accounted investments Identifiable liabilities(c) Unallocated liabilities Capital expenditure in tangible and intangible assets 2016 Net sales from operations(a) Less: intersegment sales Net sales to customers Operating profit Net provisions for contingencies Depreciation and amortization Impairments of tangible and intangible assets Reversals of tangible and intangible assets Write-off Share of profit (loss) of equity-accounted investments Identifiable assets(b) Unallocated assets Equity-accounted investments Identifiable liabilities(c) Unallocated liabilities Capital expenditure in tangible and intangible assets (a) Before elimination of intersegment sales. (b) Includes assets directly associated with the generation of operating profit. (c) Includes liabilities directly associated with the generation of operating profit. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 224 FINANCIAL INFORMATION BY GEOGRAPHICAL AREA Identifiable assets and investments by geographical area of origin. (€ million) 2018 Identifiable assets(a) Capital expenditure in tangible and intangible assets 2017 Identifiable assets(a) Capital expenditure in tangible and intangible assets 2016 Identifiable assets(a) Capital expenditure in tangible and intangible assets (a) Includes assets directly associated with the generation of operating profit. Net sales from operations by geographical area of destination. (€ million) Italy Other European Union Rest of Europe Americas Asia Africa Other areas n a e p o r u E r e h t O n o i n U 7,086 267 7,706 316 7,370 331 e p o r u E f o t s e R 1,031 538 6,160 387 6,960 460 s a c i r e m A 4,546 534 4,406 278 5,397 233 l y a t I 18,646 1,424 18,449 1,090 18,769 1,163 a i s A a c i r f A 16,910 1,782 36,155 4,533 16,527 898 35,385 5,699 s a e r a r e h t O 1,109 41 1,183 13 l a t o T 85,483 9,119 89,816 8,681 19,471 1,978 39,812 5,004 1,289 11 99,068 9,180 2018 25,279 20,408 7,052 5,051 9,585 8,246 201 75,822 2017 21,925 19,791 5,911 5,154 7,523 6,428 187 66,919 2016 21,280 15,808 4,804 3,212 5,619 4,865 174 55,762 36 | Transactions with related parties In the ordinary course of its business, Eni enters into transactions with related parties regarding: (a) exchange of goods, provision of services and financing with joint ventures, associates and non-consolidated subsidiaries; (b) exchange of goods and provision of services with entities controlled by the Italian Government; (c) exchange of goods and provision of services with companies related to Eni SpA through members of the Board of Directors. Most of these transactions are exempt from the application of the Eni internal procedure of Eni “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or standard conditions, or because under the materiality threshold provided for by the procedure. The solely non- exempted transaction, that was positively examined and valued in application of the procedure, concerned the remote monitoring of cars in the “enjoy” initiative (for an amount of lower than €1 million) conducted with Vodafone Italia SpA related to Eni SpA through of a member of the Board of Directors; (d) contributions to non-profit entities correlated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as scientific and technological research; and (ii) Eni Enrico Mattei Foundation established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge in the fields of economics, energy and environment, both at the national and international level. Some low transactions with companies related to Eni SpA through some members of the Board of Directors were concluded at market or standard conditions, or in compliance with Eni’s internal procedure “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, pursuant the Consob regulation. Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business. Investments in subsidiaries, joint arrangements and associates as of December 31, 2018 are presented in the annex “List of companies owned by Eni SpA as of December 31, 2018”. This annex includes also the changes in the scope of consolidation. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 225 TRADE AND OTHER TRANSACTIONS WITH RELATED PARTIES 2018 Name Joint ventures and associates Agiba Petroleum Co Angola LNG Supply Services Llc Coral FLNG SA Gas Distribution Company of Thessaloniki-Thessaly SA Karachaganak Petroleum Operating BV Mellitah Oil & Gas BV Petrobel Belayim Petroleum Co Saipem Group Unión Fenosa Gas SA Vår Energi AS Other(*) Unconsolidated entities controlled by Eni Eni BTC Ltd Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) Other Entities controlled by the Government Enel Group GSE - Gestore Servizi Energetici Italgas Group Snam Group Terna Group Other Other related parties Groupement Sonatrach – Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» December 31, 2018 2018 Receivables and other assets Payables and other liabilities Guarantees (€ million) Costs Revenues Other operating (expense) income 1 14 1 27 1 56 75 4 13 44 236 87 6 93 329 134 67 5 237 26 25 494 1 40 96 18 134 268 2,029 171 7 100 25 2,848 1 23 24 2,872 151 85 146 289 47 18 736 2 140 177 1,147 793 57 218 2,392 177 5 14 196 2,588 156 51 998 502 2,282 420 104 4,513 13 13 4,526 514 588 667 1,184 231 34 3,218 32 62 1 1 7 30 123 111 335 11 7 18 353 118 555 23 109 150 45 1,000 4 229 34 37 (26) 11 11 227 74 (1) 8 308 Total 864 3,750 2,588 8,005 1,391 319 (*) Each individual amount included herein was lower than €50 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 226 2017 Name Joint ventures and associates Agiba Petroleum Co Coral FLNG SA Karachaganak Petroleum Operating BV Mellitah Oil & Gas BV Petrobel Belayim Petroleum Co Saipem Group Unión Fenosa Gas SA Other(*) Unconsolidated entities controlled by Eni Eni BTC Ltd Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) Other Entities controlled by the Government Enel Group GSE - Gestore Servizi Energetici Italgas Group Snam Group Terna Group Other(*) Other related parties December 31, 2017 2017 Receivables and other assets Payables and other liabilities Guarantees (€ million) Costs Revenues Other operating (expense) income 1 20 36 5 86 63 84 295 77 20 97 392 123 69 14 187 35 50 478 1 39 83 4 121 220 1,205 76 22 1,731 1 23 24 1,755 187 219 180 351 31 21 989 2 145 1,094 7,270 57 8,421 169 5 7 181 8,602 1 1 142 951 495 3,168 450 3 140 5,349 14 14 5,363 622 506 681 1,221 212 38 3,280 25 28 2 8 44 202 128 412 7 7 14 426 164 702 18 85 154 16 1,139 1 530 42 28 28 28 285 2 15 1 303 Groupement Sonatrach – Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» Total 910 2,891 8,603 9,198 1,608 331 (*) Each individual amount included herein was lower than €50 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 2016 Name Joint ventures and associates Agiba Petroleum Co Karachaganak Petroleum Operating BV Mellitah Oil & Gas BV Petrobel Belayim Petroleum Co Saipem Group Unión Fenosa Gas SA Other(*) Unconsolidated entities controlled by Eni Eni BTC Ltd Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) Other(*) Entities controlled by the Government Enel Group GSE - Gestore Servizi Energetici Italgas Group Snam Group Terna Group Other(*) Other related parties 227 December 31, 2016 2016 Receivables and other assets Payables and other liabilities Guarantees (€ million) Costs Revenues Other operating (expense) income 1 47 7 225 64 114 458 69 9 78 536 151 58 54 44 33 43 383 50 187 134 532 224 25 1,152 1 16 17 1,169 254 32 1 541 46 24 898 2 331 8,094 57 1 8,152 192 3 51 246 8,398 1 1 156 918 477 1,940 781 145 4,417 8 8 4,425 808 243 4 2,032 232 37 3,356 32 27 2 51 94 143 317 2 10 12 329 201 414 113 117 68 913 423 70 47 47 47 182 5 13 200 Groupement Sonatrach – Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» 176 Total 1,095 2,400 8,399 8,236 1,312 247 (*) Each individual amount included herein was lower than €50 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 228 The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned: - Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach - Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of oil products by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs; - guarantees issued on behalf of Angola LNG Supply Services Llc to cover the commitments relating to the payment of the regasification fees; - supply of upstream specialist services and guarantees issued on a pro- quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant (for more information see note 27 – Guarantees, commitments and risks); - the acquisition of transport and distribution services from Gas Distribution Company of Thessaloniki-Thessaly SA; - engineering, construction and drilling services by Saipem Group mainly for the Exploration & Production segment and the provision of services and residual guarantees issued by Eni SpA relating to bid bonds and performance bonds; - performance guarantees given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations, sales of LNG and fair value of derivative financial instruments; - services for environmental restoration to Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation). The most significant transactions with entities controlled by the Italian Government concerned: - sale of fuel, sale and purchase of gas, acquisition of power distribution services and fair value of derivative financial instruments with Enel Group; - acquisition of natural gas transportation, distribution and storage services with the Snam Group and the Italgas Group on the basis of tariffs set by the Italian Regulatory Authority for Energy, Networks and Environment and purchase and sale of natural gas for granting the balancing of the system on the basis of prices referred to the quotations of the main energy commodities; - sale and purchase of electricity, the acquisition of domestic electricity transmission service on the basis of prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with the Terna Group; - sale and purchase of electricity, gas, environmental certificates, fair value of derivative financial instruments and sale of oil products with GSE - Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012. - guarantees issued in compliance with contractual agreements in the interest of Vår Energi AS and trade and other receivables and payables; - a guarantee issued in relation to the construction of an oil pipeline Transactions with other related parties concerned: - provisions to pension funds of €24 million; and - contributions and service provisions to Eni Foundation of €3 million on behalf of Eni BTC Ltd; and and to Eni Enrico Mattei Foundation for €4 million. FINANCING TRANSACTIONS WITH RELATED PARTIES 2018 (€ million) Joint ventures and associates Angola LNG Ltd Cardón IV SA Coral FLNG SA Coral South FLNG DMCC Shatskmorneftegaz Sàrl Société Centrale Electrique du Congo SA Vår Energi AS Other Unconsolidated entities controlled by Eni Other Entities controlled by the Government Enel Group Other Total December 31, 2018 2018 Receivables Payables Guarantees Charges Gains 705 108 64 38 915 49 49 964 36 30 494 4 564 25 25 64 8 72 661 245 1,397 22 1,664 1,664 95 7 13 115 115 267 5 9 281 2 2 283 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 2017 (€ million) Joint ventures and associates Angola LNG Ltd Cardón IV SA Coral FLNG SA Coral South FLNG D MCC Saipem Group Shatskmorneftegaz Sarl Société Centrale Electrique du Congo SA Other Unconsolidated entities controlled by Eni Servizi Fondo Bombole Metano SpA Other(*) Entities controlled by the Government Other Total (*) Each individual amount included herein was lower than €50 million. 2016 (€ million) Joint ventures and associates Cardón IV SA Matrìca SpA Shatskmorneftegaz Sarl Société Centrale Electrique du Congo SA Unión Fenosa Gas SA Saipem Group Other(*) Unconsolidated entities controlled by Eni Eni BTC Ltd Other(*) Entities controlled by the Government Other 229 December 31, 2017 2017 Receivables Payables Guarantees Charges Gains 955 56 101 66 48 1,226 60 1 61 1,287 233 1,334 56 2 1,625 1,625 3 43 49 95 9 52 61 8 8 164 86 71 13 6 14 190 1 1 191 1 1 3 3 4 December 31, 2016 2016 Receivables Payables Guarantees Charges Gains Derivative financial instruments 1,054 125 69 78 52 1,378 46 46 82 2 84 85 85 54 52 106 93 13 18 17 141 1 1 3 3 145 96 9 4 43 4 156 1 1 27 27 157 27 Total 1,424 191 84 (*) Each individual amount included herein was lower than €50 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 230 The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned: - bank debt guarantees issued on behalf of Angola LNG Ltd; - financing loans granted to Cardón IV SA for the exploration and development activities of the Perla offshore gas field in Venezuela; - a cash deposit held at Eni’s financial companies by Vår Energi AS. The most significant transactions with entities controlled by the Italian Government concerned: - restricted deposits in escrow of derivative financial instruments - financing loans granted to Coral FLNG SA for the construction with Enel Group. of a floating gas liquefaction plant in the Area 4 in Mozambique (for more information see note 27 – Guarantees, commitments and risks); - a bank debt guarantee issued on behalf of Coral South FLNG DMCC (for more information see note 27 – Guarantees, commitments and risks); - the impairment of financial receivables granted to Shatskmorneftegaz Sàrl; - the loan granted to Société Centrale Electrique du Congo SA for the construction of a power plant in Congo and a cash deposit at Eni’s financial companies; Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows The impact of transactions and positions with related parties on the balance sheet consisted of the following: (€ million) Other current financial assets Trade and other receivables Other current assets Other non-current financial assets Other non-current assets Short-term debt Trade and other payables Other current liabilities Other non-current liabilities December 31, 2018 December 31, 2017 s e i t r a p d e t a l e R 49 633 71 915 160 661 3,664 63 23 l a t o T 300 14,101 2,258 1,253 792 2,182 16,747 3,980 1,502 % t c a p m I 16.33 4.49 3.14 73.02 20.20 30.29 21.88 1.58 1.53 l a t o T 316 15,421 1,573 1,675 1,323 2,242 16,748 1,515 1,479 s e i t r a p d e t a e R l 73 834 30 1,214 46 164 2,808 60 23 The impact of transactions with related parties on the profit and loss accounts consisted of the following: 2018 2017 2016 s e i t r a p d e t a l e R l a t o T % t c a p m I l a t o T s e i t r a p d e t a e R l % t c a p m I l a t o T s e i t r a p d e t a e R l 75,822 1,116 (55,622) 1,383 8 (8,009) 1.82 0.72 14.40 66,919 4,058 (51,548) 1,567 41 (9,164) 2.34 1.01 17.78 55,762 931 (43,278) 1,238 74 (8,212) (415) (3,093) 129 3,967 (4,663) (307) 26 (22) 319 115 (283) .. (913) 0.71 .. 2.90 6.07 (2,951) (32) 3,924 (5,886) 837 (34) 331 191 (4) 1.15 .. 4.87 0.07 (846) (2,994) 16 5,850 (6,232) (482) (24) 247 157 (145) 27 (€ million) Net sales from operations Other income and revenues Purchases, services and other Net (impairment losses) reversals of trade and other receivables Payroll and related costs Other operating income (expense) Finance income Finance expense Derivative financial instruments % t c a p m I 23,10 5.41 1.91 72.48 3.48 7.31 16.77 3.96 1.56 % t c a p m I 2.22 7.95 18.97 0.80 .. 2.69 2.33 .. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS Main cash flows with related parties are provided below: (€ million) Revenues and other income Costs and other expenses Other operating income (loss) Net change in trade and other receivables and liabilities Net interests Net cash provided from operating activities Capital expenditure in tangible and intangible assets Disposal of investments Net change in accounts payable and receivable in relation to investments Change in financial receivables Net cash used in investing activities Change in financial liabilities Net cash used in financing activities Total financial flows to related parties The impact of cash flows with related parties consisted of the following: 231 2018 1,391 (5,210) 319 683 110 (2,707) (2,768) 20 (566) (3,314) 16 16 (6,005) 2017 1,608 (5,360) 331 391 187 (2,843) (3,838) 425 298 (3,115) (16) (16) (5,974) 2016 1,312 (5,623) 247 182 133 (3,749) (2,613) 463 252 5,650 3,752 (192) (192) (189) 2018 2017 2016 s e i t r a p d e t a l e R % t c a p m I l a t o T s e i t r a p d e t a e R l % t c a p m I l a t o T s e i t r a p d e t a e R l (2,707) (3,314) 16 .. 43.98 .. 10,117 (3,768) (4,595) (2,843) (3,115) (16) .. 82.67 0.35 7,673 (4,443) (3,651) (3,749) 3,752 (192) l a t o T 13,647 (7,536) (2,637) % t c a p m I .. .. 5.26 (€ million) Cash provided from operating activities Cash used in investing activities Cash used in financing activities 37 | Other information about investments31 Information on Eni’s consolidated subsidiaries with significant non-controlling interest Changes in the ownership interest without loss of control In 2018 and 2017, Eni did not own any consolidated subsidiaries with a significant non-controlling interest. Total shareholders’ equity pertaining to minority interests as of December 31, 2018, amounted to €57 million (€49 million December 31, 2017). In 2018 and 2017, Eni did not report any changes in ownership interest without loss or acquisition of control. (31) Investments in subsidiaries, joint arrangements and associates as of December 31, 2018 are presented in the annex “List of companies owned by Eni SpA as of December 31, 2018”. This annex includes also the changes in the scope of consolidation. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 232 Principal joint ventures, joint operations and associates as of December 31, 2018 Company name Joint Venture Gas Distribution Company of Thessaloniki-Thessaly SA Saipem SpA Unión Fenosa Gas SA Vår Energi AS Joint operation GreenStream BV Mozambique Rovuma Venture SpA Raffineria di Milazzo ScpA Associates Angola LNG Ltd Coral FLNG SA Registered office Country of operation Business segment % ownership interest % voting rights Ampelokipi-Menemeni (Greece) San Donato Milanese (MI) (Italy) Madrid (Spain) Forus (Norway) Amsterdam (Netherlands) San Donato Milanese (MI) (Italy) Milazzo (ME) (Italy) Hamilton (Bermuda) Maputo (Mozambique) Greece Italy Spain Gas & Power Other Activities Gas & Power Norway Exploration & Production Lybia Gas & Power Mozambique Exploration & Production Italy Refining & Marketing Angola Exploration & Production Mozambique Exploration & Production 49.00 30.54 50.00 69.60 50.00 35.71 50.00 13.60 25.00 49.00 30.99 50.00 69.60 50.00 35.71 50.00 13.60 25.00 The main line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below: 2018 (€ million) Current assets - of which cash and cash equivalent Non-current assets Total assets Current liabilities - current financial liabilities Non-current liabilities - non-current financial liabilities Total liabilities Net equity Eni’s ownership interest (%) Book value of the investment Revenues and other operating income Operating expense Depreciation, amortization and impairments Operating profit Finance (expense) income Income (expense) from investments Profit before income taxes Income taxes Net profit Other comprehensive income Total other comprehensive income Net profit attributable to Eni Dividends received from the joint venture Vår Energi AS 1,366 883 11,407 12,773 608 7,139 366 7,747 5,026 69.60 3,498 Saipem SpA 6,211 1,674 5,466 11,677 4,430 305 3,211 2,646 7,641 4,036 30.99 1,228 8,530 (7,682) (811) 37 (165) (88) (216) (194) (410) (46) (456) (146) Unión Fenosa Gas SA 664 107 832 1,496 260 22 581 510 841 655 50.00 335 1.521 (1,461) (70) (10) (31) 9 (32) (1) (33) 15 (18) (23) 2018 Gas Distribution Company of Thessaloniki- Thessaly SA 32 13 302 334 52 Cardón IV SA 191 40 2,433 2,624 232 2,196 1,410 2,428 196 50.00 98 610 (372) (137) 101 (208) (107) (35) (142) 6 (136) (71) 2 54 280 49.00 137 53 (16) (12) 25 25 (8) 17 17 8 8 Lotte Versalis Elastomers Co Ltd 56 8 502 558 111 78 297 289 408 150 50.00 75 22 (58) (30) (66) (12) (78) (78) (78) (39) PetroJunín SA 368 253 621 470 34 504 117 40.00 47 112 (100) (394) (382) 31 (351) (19) (370) 11 (359) (148) Other joint ventures 130 38 334 464 307 165 126 14 433 31 (2) 731 (697) (62) (28) (5) (33) (10) (43) (4) (47) (21) 11 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS233 2017 (€ million) Current assets - of which cash and cash equivalent Non-current assets Total assets Current liabilities - current financial liabilities Non-current liabilities - non-current financial liabilities Total liabilities Net equity Eni’s ownership interest (%) Book value of the investment Revenues and other operating income Operating expense Depreciation, amortization and impairments Operating profit Finance (expense) income Income (expense) from investments Profit before income taxes Income taxes Net profit Other comprehensive income Total other comprehensive income Net profit attributable to Eni Dividends received from the joint venture Saipem SpA 6,743 1,751 5,847 12,590 4,487 189 3,504 2,929 7,991 4,599 31.00 1,413 Unión Fenosa Gas SA 610 32 877 1,487 234 40 580 506 814 673 50.00 350 9,038 (8,172) (740) 126 (223) (9) (106) (201) (307) 49 (258) (101) 1,340 (1,308) (89) (57) (38) 3 (92) 1 (91) (41) (132) (63) Petro Junín SA 365 628 993 434 34 468 525 40.00 210 135 (66) (29) 40 47 87 (22) 65 (68) (3) 26 2017 Gas Distribution Company of Thessaloniki-Thessaly SA 86 15 289 375 94 2 96 279 49.00 137 54 (14) (15) 25 25 (7) 18 18 9 12 Lotte Versalis Elastomers Co Ltd 43 30 547 590 70 38 292 288 362 228 50.00 114 (4) (4) (4) (4) (6) (10) (2) Cardón IV SA 816 42 2,756 3,572 644 2,928 1,912 3,572 50.00 756 (608) (357) (209) (155) (364) (4) (368) 26 (394) (184) Other joint ventures 275 64 916 1,191 985 640 124 79 1,109 82 28 412 (433) (113) (134) (53) (4) (191) (11) (202) (202) (56) 29 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 234 The main line items of profit and loss and balance sheet related to the principal associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below: 2018 (€ million) Current assets - of which cash and cash equivalent Non-current assets Total assets Current liabilities - current financial liabilities Non-current liabilities - non-current financial liabilities Total liabilities Net equity Eni’s ownership interest (%) Book value of the investment Revenues and other operating income Operating expense Depreciation, amortization and impairments Operating profit Finance (expense) income Income (expense) from investments Profit before income taxes Income taxes Net profit Other comprehensive income Total other comprehensive income Net profit attributable to Eni Dividends received from the associate 2018 A S G N L F l a r o C 109 109 2,434 2,543 117 2,018 2,016 2,135 408 25.00 102 (1) (1) (11) (12) (12) 16 4 (3) d t L G N L a l o g n A 1,027 698 9,079 10,106 472 1,500 1,328 1,972 8,134 13.60 1,106 1,919 (872) 1,647 2,694 (97) 2,597 2,597 337 2,934 353 s e t a i c o s s a r e h t O 926 178 2,296 3,222 785 134 1,755 1,473 2,540 682 241 1,053 (887) (58) 108 (1) 16 123 (26) 97 17 114 25 25 CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 2017 (€ million) Current assets - of which cash and cash equivalent Non-current assets Total assets Current liabilities - current financial liabilities Non-current liabilities - non-current financial liabilities Total liabilities Net equity Eni’s ownership interest (%) Book value of the investment Revenues and other operating income Operating expense Depreciation, amortization and impairments Operating profit Finance (expense) income Income (expense) from investments Profit before income taxes Income taxes Net profit Other comprehensive income Total other comprehensive income Net profit attributable to Eni Dividends received from the associate 235 2017 A S G N L F l a r o C 36 19 1,261 1,297 155 926 926 1,081 216 25.00 54 4 4 4 (13) (9) 1 d t L G N L a o g n A l 662 370 7,048 7,710 203 1,610 1,418 1,813 5,897 13.60 802 1,374 (563) (399) 412 (80) 332 332 (817) (485) 45 s e t a i c o s s a r e h t O 338 89 528 866 220 42 124 71 344 522 205 574 (454) (40) 80 3 (30) 53 (19) 34 (39) (5) 8 13 38 | Public assistance - Italian Law No. 124/2017 and subsequent modifications Under art. 1, paragraphs 125 and 126, of the Italian Law No. 124/2017 and subsequent modifications, the disclosures about the assistance received from Italian public authorities and entities, as well as the assistance granted by Eni SpA and by its fully consolidated subsidiaries to companies, persons and public and private entities, are provided below. The consolidated disclosures include: (i) assistance received from Italian public authorities/entities; and (ii) assistance granted by Eni SpA and its subsidiaries32. The following disclosure requirements do not apply to: (i) incentives/ subventions granted to all those entitled in accordance with a general assistance aid scheme; (ii) consideration in exchange for supplied goods/services, including sponsorships; (iii) reimbursements and indemnities paid to persons engaged in professional and orientation trainings; (iv) continuous training contributions to companies granted by inter-professional funds established in the legal form of association; (v) membership fees for the participation to industry trade and territorial associations, as well as to foundations or similar organizations, which perform activities linked with the company’s business; (vi) costs incurred with reference to social projects linked to the investing activities of the Company. The assistance to be disclosed is identified on a cash basis. The disclosure includes assistance exceeding €10,000, even though they are granted through several payments. Under art. 3-quarter of the Italian Decree Law No. 135/2018, converted with amendments by Law 11 February 2019, n. 12, for the received assistance see the information included in the Italian State aid Register, prepared in accordance with the article 52 of the Italian Law 24 December 2012, No. 234. (32) The following disclosures do not include assistance granted by foreign subsidiaries to foreign beneficiaries. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 236 The granted assistance provided herein is mainly referred to foundations, associations and other entities for reputational purposes, donations and support for charitable and solidarity initiatives: Amount paid (€) 4,403,686 3,389,902 3,052,192 1,000,000 260,586 242,326 83,358 81,307 72,805 57,000 51,588 50,000 40,000 35,000 35,000 33,000 30,000 29,687 26,000 22,548 22,000 21,985 21,760 20,000 20,000 20,000 14,000 10,000 Assistance granted Granted subject Fondazione Eni Enrico Mattei Eni Foundation Fondazione Teatro alla Scala Fondazione Giorgio Cini WEF - World Economic Forum Comitato Sisma Centro Italia - Confindustria, CIGL, CISL e UIL - Fondo di solidarietà per le popolazioni Centro Italia Council on Foreign Relations Atlantic Council of the United States Inc World Business Council for Sustainable Development Associazione Pionieri e Veterani Eni EITI - Extractive Industries Transparency Initiative Bruegel Parrocchia di S. Barbara a San Donato Milanese Aspen Institute Italia Italiadecide Fondazione Camera Centro Italiano per la Fotografia Istituto Giannina Gaslini Center for Strategic & International Studies Politecnico di Milano - Dipartimento di “Scienze e Tecnologie Energetiche e Nucleari” Institute for Human Rights and Business (IHRB) Associazione Civita Foreign Policy Association - USA The Metropolitan Museum of Arts Associazione Amici della Luiss Centro Studi Americani Fondazione Human Foundation Giving and Innovating Onlus Global Reporting Initiative Lega Italiana Fibrosi Cistica Lazio Onlus 39 | Significant non-recurring events and operations In 2018, in 2017 and 2016, Eni did not report any non-recurring events and operations. 40 | Positions or transactions deriving from atypical and/or unusual operations In 2018, 2017 and 2016 no transactions deriving from atypical and/or unusual operations were reported. 41 | Subsequent events No significant events were reported after December 31, 2018. CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS237 Supplemental oil and gas information (unaudited) The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities - oil&gas (Topic 932). Amounts related to minority interests are not significant. CAPITALIZED COSTS Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following: (€ million) 2018 Consolidated subsidiaries Proved property Unproved property Support equipment and facilities Incomplete wells and other Gross Capitalized Costs Accumulated depreciation, depletion and amortization Net Capitalized Costs consolidated subsidiaries(a) Equity-accounted entities Proved property Unproved property Support equipment and facilities Incomplete wells and other Gross Capitalized Costs Accumulated depreciation, depletion and amortization Net Capitalized Costs equi- ty-accounted entities(a)(b) 2017 Consolidated subsidiaries Proved property Unproved property Support equipment and facilities Incomplete wells and other Gross Capitalized Costs Accumulated depreciation, depletion and amortization Net Capitalized Costs consolidated subsidiaries(a) Equity-accounted entities Proved property Unproved property Support equipment and facilities Incomplete wells and other Gross Capitalized Costs Accumulated depreciation, depletion and amortization Net Capitalized Costs equity-accounted entities(a) Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 16,569 18 369 653 17,609 6,236 332 21 103 6,692 14,140 456 1,516 1,554 17,666 17,474 56 208 1,504 19,242 40,607 2,311 1,281 2,307 46,506 11,240 3 108 1,382 12,733 12,711 1,530 38 562 14,841 15,347 861 52 595 16,855 1,967 193 12 127 2,299 136,291 5,760 3,605 8,787 154,443 (13,717) (5,355) (11,741) (11,722) (29,727) (2,175) (10,460) (13,443) (1,265) (99,605) 3,892 1,337 5,925 7,520 16,779 10,558 4,381 3,412 1,034 54,838 9,102 1,045 25 364 10,536 (4,543) 5,993 58 6 10 74 (54) 20 1,481 10 1,491 (266) 1,225 2 11 19 32 1,912 7 224 2,143 (19) (1,052) 13 1,091 12,555 1,056 38 627 14,276 (5,934) 8,342 16,277 18 359 681 17,335 17,600 356 39 345 18,340 12,514 471 1,436 2,050 16,471 15,211 32 191 1,297 16,731 36,976 2,157 1,212 2,679 43,024 10,547 3 101 1,417 12,068 12,493 1,023 34 421 13,971 14,840 785 46 280 15,951 1,950 185 14 124 2,273 138,408 5,030 3,432 9,294 156,164 (13,504) (12,014) (10,640) (10,413) (25,920) (1,690) (10,386) (12,534) (1,188) (98,289) 3,831 6,326 5,831 6,318 17,104 10,378 3,585 3,417 1,085 57,875 4 1 5 5 67 7 6 80 (61) 19 1,419 4 1,423 (475) 948 581 85 93 759 1,833 6 225 2,064 (611) (785) 148 1,279 3,900 89 13 329 4,331 (1,932) 2,399 (a) The amounts include net capitalized financial charges totalling €831 million in 2018 and €969 million in 2017 for the consolidated subsidiaries and €180 million in 2018 and €78 million in 2017 for equity-accounted entities. (b) Includes Vår Energi AS asset fair value. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 238 COSTS INCURRED Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following: Italy Rest of Europe North Africa Sub-Saharan Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania (€ million) 2018 Consolidated subsidiaries Proved property acquisitions Unproved property acquisitions Exploration Development(a) Total costs incurred consolidated subsidiaries Equity-accounted entities Proved property acquisitions Unproved property acquisitions Exploration Development(b) Total costs incurred equity-accounted entities 2017 Consolidated subsidiaries Proved property acquisitions Unproved property acquisitions Exploration Development(a) Total costs incurred consolidated subsidiaries Equity-accounted entities Proved property acquisitions Unproved property acquisitions Exploration Development(b) Total costs incurred equity-accounted entities 2016 Consolidated subsidiaries Proved property acquisitions Unproved property acquisitions Exploration Development(a) Total costs incurred consolidated subsidiaries Equity-accounted entities Proved property acquisitions Unproved property acquisitions Exploration Development(b) Total costs incurred equity-accounted entities 26 382 408 106 557 663 43 445 488 102 2,216 2,318 66 1,379 1,445 3 92 95 2 3 5 77 785 862 110 3,041 3,151 2 2 58 694 752 1 1 2 306 1,752 2,060 5 65 1,939 2,009 9 9 70 2,019 2,089 28 28 31 251 282 27 387 414 242 364 606 1 1 51 437 488 1 1 Total 382 487 750 6,036 7,655 105 (13) 92 5 715 7,646 8,366 91 63 154 2 621 7,168 7,791 14 136 150 7 36 43 5 14 19 3 1 4 215 340 555 (16) (16) 106 292 398 48 48 26 (5) 21 95 95 382 487 182 589 1,640 103 103 76 714 790 90 4 94 3 246 249 80 1,232 1,312 651 651 13 12 25 (a) Includes the abandonment costs of the assets negative for €517 million in 2018, assets for €355 million in 2017, negative for €665 million in 2016. (b) Includes the abandonment costs of the assets negative for €22 million in 2018, negative €23 million in 2017, negative for €15 million in 2016. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION239 RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to meet Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production. Results of operations from oil and gas producing activities by geographical area consist of the following: Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 2,120 2,120 (410) (402) (8) (171) (25) (281) (442) 791 (170) 2,740 494 3,234 (630) (488) (142) (85) (664) (193) 1,277 3,741 5,018 (413) (363) (50) (243) (48) (582) (101) 1,662 (1,070) 3,631 (2,494) 3,207 3,207 (354) (343) (11) (22) (795) (239) 1,797 (542) 4,701 830 5,531 (1,016) (974) (42) (435) (44) (2,490) (1,126) 420 (264) 1,140 769 1,909 (405) (269) (136) (3) (387) (67) 1,047 (308) 1,902 493 2,395 (227) (220) (7) (191) (79) (941) (135) 822 (678) 621 592 1,137 1,255 156 739 144 (€ million) 2018 Consolidated subsidiaries Revenues: - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment(a) Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of consolidated subsidiaries Equity-accounted entities Revenues: - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of equity-accounted entities 15 15 (8) (7) (1) (3) (1) 2 5 (3) 2 (6) (1) (7) (7) 257 257 (62) (34) (28) (26) 224 (27) 366 366 (a) Includes asset net impairment amounting to €726 million. 934 50 984 (250) (234) (16) (69) (594) (54) 17 7 24 420 420 (38) (36) (2) (114) (222) (122) (76) (35) 6 6 (2) (2) (235) (3) (25) (259) (2) (261) (111) 4 190 194 (48) (48) (6) (5) (67) 14,818 9,774 24,592 (3,753) (3,341) (412) (1,046) (380) (6,801) (2,357) 68 (26) 10,255 (5,545) 42 4,710 698 698 (110) (79) (31) (143) (241) (2) (173) 29 (40) (11) CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018240 (€ million) 2017 Consolidated subsidiaries Revenues: - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment(a) Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of consolidated subsidiaries Equity-accounted entities Revenues - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of equity-accounted entities Italy Rest of Europe North Africa Egypt Africa Kazakhstan Sub-Saharan Rest of Asia America Australia and Oceania Total 1,619 1,619 (337) (332) (5) (130) (26) (465) 1,563 2,224 (299) 1,897 481 2,378 (687) (523) (164) (122) (838) (141) 590 (216) 1,056 3,184 4,240 (504) (455) (49) (200) (22) (679) (162) 2,673 (1,978) 2,128 2,128 (314) (303) (11) (191) (767) 690 1,546 (214) 3,888 547 4,435 (986) (952) (34) (331) (60) (2,063) (716) 279 (38) 681 713 1,394 (396) (271) (125) (289) (221) 488 (223) 911 291 1,202 (206) (202) (4) (11) (61) (765) (84) 75 (67) 932 96 1,028 (312) (258) (54) (39) (577) (342) (242) (38) 3 168 171 (48) (48) (5) (4) (59) 2 57 (23) 10,987 7,608 18,595 (3,790) (3,344) (446) (677) (525) (6,502) 589 7,690 (3,096) 1,925 374 695 1,332 241 265 8 (280) 34 4,594 14 14 (8) (6) (2) (2) (1) (2) 1 (1) (1) (2) (3) (3) 129 129 (37) (19) (18) (8) (54) 26 56 56 22 22 (9) (9) (13) (13) 3 (10) (4) 517 517 (40) (39) (1) (146) (271) (199) (139) (20) (14) (159) 682 682 (94) (73) (21) (156) (14) (339) (174) (95) (25) (120) (a) Includes asset net reversal amounting to €158 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 241 (€ million) 2016 Consolidated subsidiaries Revenues: - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment(a) Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of consolidated subsidiaries Equity-accounted entities Revenues: - sales to consolidated entities - sales to third parties Total revenues Operations costs - of which production costs - of which transportation costs Production taxes Exploration expenses D.D. & A. and Provision for abandonment Other income (expenses) Pretax income from producing activities Income taxes Results of operations from E&P activities of equity-accounted entities Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 1,217 1,217 (311) (307) (4) (96) (35) (923) (342) (490) 159 1,673 432 2,105 (599) (436) (163) (40) (943) (232) 291 (1) 932 2,841 3,773 (451) (404) (47) (176) (45) (675) (201) 2,225 (1,618) 9 1,471 1,480 (356) (343) (13) (42) (691) (265) 126 (89) (331) 290 607 37 15 15 (9) (7) (2) (3) (1) (1) 1 (2) (1) (3) (3) (3) 3,178 485 3,663 (968) (929) (39) (282) (142) (1,093) (917) 261 97 358 (26) (26) (52) (52) 252 606 858 (269) (177) (92) (129) (57) 403 (139) 1,027 114 1,141 (215) (212) (3) (17) (39) (952) (130) (212) 32 833 102 935 (325) (262) (63) (28) (480) (120) (18) (9) 4 165 169 (49) (49) (5) (3) (67) (8) 37 (9) 9,125 6,216 15,341 (3,543) (3,119) (424) (576) (374) (5,953) (2,272) 2,623 (1,577) 264 (180) (27) 28 1,046 36 36 (10) (10) (13) (32) (16) (35) (6) 493 493 (54) (51) (3) (121) (240) (25) 53 (162) (41) (109) 544 544 (73) (68) (5) (124) (13) (299) (71) (36) (170) (206) (a) Includes asset net reversal amounting to €700 million. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 242 OIL AND NATURAL GAS RESERVES Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the US Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities - Oil and Gas (Topic 932). Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. In 2018, the average price for the marker Brent crude oil was $71 per barrel. Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Eni has its proved reserves audited on a rotational basis by independent oil engineering companies33. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report34. In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements, and other pertinent information are provided. In 2018, Ryder Scott Company, DeGolyer and MacNaughton and Societé Generale de Surveillance (SGS)34 provided an independent evaluation of about 26% of Eni’s total proved reserves as of December 31, 201835, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three years period from 2016 to 2018, 95% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2018, the principal property not subjected to independent evaluation in the last three years was M’Boundi (Congo). Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni’s economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni’s share of production and Eni’s net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 61%, 60% and 59% of total proved reserves as of December 31, 2018, 2017 and 2016, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service contracts; proved reserves associated with such contracts represented 3%, 4% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2018, 2017 and 2016, respectively. Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the Company has an obligation to purchase under certain PSAs with governments or authorities, whereby the Company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 4%, 1.6% and 1.8% of total proved reserves as of December 31, 2018, 2017 and 2016, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant. Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced. The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2018, 2017 and 2016. (33) From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018, Societé Generale de Surveillance (SGS) also provided an independent certification. (34) The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2018. (35) Including reserves of equity-accounted entities. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION243 CRUDE OIL (INCLUDING CONDENSATE AND NATURAL GAS LIQUIDS) (million barrels) 2018 Consolidated subsidiaries Reserves at December 31, 2017 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2018 Equity-accounted entities Reserves at December 31, 2017 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2018 Reserves at December 31, 2018 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities Rest of Europe Italy North Africa Egypt Africa Kazakhstan Sub-Saharan Rest of Asia America Australia and Oceania 215 169 46 15 (22) 208 208 156 156 52 52 360 219 141 6 (40) (278) 48 297 297 345 198 44 154 147 4 143 476 306 170 73 (56) 493 12 12 (1) 11 504 328 317 11 176 176 280 203 77 21 7 (28) (1) 279 279 153 153 126 126 764 546 218 30 13 (89) 718 12 6 6 1 (1) 12 730 559 551 8 171 167 4 766 547 219 (27) (35) 232 81 151 319 (54) 6 1 (28) 704 476 704 587 587 117 117 476 252 252 224 224 162 144 18 23 86 (19) 252 136 25 111 (96) (3) 37 289 175 143 32 114 109 5 7 5 2 (1) (1) 5 5 5 5 Total 3,262 2,220 1,042 319 86 13 100 (318) (279) 3,183 160 43 117 297 (95) (5) 357 3,540 2,413 2,208 205 1,127 975 152 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 24 4 (million barrels) 2017 Consolidated subsidiaries Reserves at December 31, 2016 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2017 Equity-accounted entities Reserves at December 31, 2016 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2017 Reserves at December 31, 2017 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 176 132 44 59 (20) 215 264 228 36 29 1 103 (37) 360 215 169 169 46 46 360 219 219 141 141 454 287 167 73 6 1 (58) 476 13 13 (1) 12 488 318 306 12 170 170 281 205 76 21 7 (26) (3) 280 280 203 203 77 77 809 507 302 2 31 18 (90) (6) 764 15 8 7 (2) (1) 12 776 552 546 6 224 218 6 767 556 211 29 (30) 307 124 183 (69) 9 4 (19) 766 232 766 547 547 219 219 232 81 81 151 151 163 143 20 19 3 (23) 162 140 22 118 1 (5) 136 298 169 144 25 129 18 111 9 8 1 (1) (1) 7 7 5 5 2 2 3,230 2,190 1,040 2 191 23 129 (304) (9) 3,262 168 43 125 (1) (7) 160 3,422 2,263 2,220 43 1,159 1,042 117 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION245 (million barrels) 2016 Consolidated subsidiaries Reserves at December 31, 2015 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2016 Equity-accounted entities Reserves at December 31, 2015 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2016 Reserves at December 31, 2016 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities Rest of Europe Italy North Africa Egypt Africa Kazakhstan Sub-Saharan Rest of Asia America Australia and Oceania Total 228 171 57 (35) (17) 176 305 237 68 (4) 1 2 (40) 264 494 312 182 19 1 1 (61) 327 230 97 (26) 8 (28) 454 281 13 13 1 (1) 13 467 300 287 13 167 167 281 205 205 76 76 176 132 132 44 44 264 228 228 36 36 787 511 276 113 (91) 809 16 6 10 (1) 15 824 515 507 8 309 302 7 771 355 416 262 126 136 189 149 40 20 73 (1) 9 9 1 (24) (28) (25) (1) 3,372 2,100 1,272 160 2 11 (315) 767 307 767 556 556 211 211 307 124 124 183 183 163 158 29 129 (13) (5) 140 303 165 143 22 138 20 118 9 3,230 187 48 139 (13) (6) 168 3,398 2,233 2,190 43 1,165 1,040 125 9 8 8 1 1 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 246 NATURAL GAS(a) (billion cubic feet) 2018 Consolidated subsidiaries Reserves at December 31, 2017 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2018 Equity-accounted entities Reserves at December 31, 2017 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2018 Reserves at December 31, 2018 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities Italy Rest of Europe North Africa Egypt Africa Kazakhstan Sub-Saharan Rest of Asia America Australia and Oceania Total 1,131 987 144 138 86 (156) 1,199 1,199 980 980 219 219 896 771 125 50 (162) (464) 320 360 360 680 576 300 276 104 20 84 3,145 1,233 1,912 4,351 1,421 2,930 3,660 1,693 1,967 2,108 1,878 230 219 2,238 23 (22) (474) 2,890 (445) (869) 5,275 7 (184) (97) 3,506 1,989 1,065 862 203 69 81 205 (201) (2) 1,217 14 14 2 (2) 14 2,904 1,461 1,447 14 1,443 1,443 5,275 3,331 3,331 1,944 1,944 349 83 266 (6) (33) 310 3,816 1,928 1,871 57 1,888 1,635 253 (19) 1,217 822 822 395 395 1,989 1,846 1,846 143 143 225 171 54 45 76 (43) (26) 277 1,819 1,819 (22) (81) 1,716 1,993 1,870 154 1,716 123 123 709 519 190 (16) (42) 651 651 452 452 199 199 17,290 9,535 7,755 69 2,756 374 (1,804) (1,361) 17,324 2,182 1,916 266 360 (26) (116) (19) 2,400 19,724 13,266 11,203 2,063 6,458 6,121 337 (a) Values lower than 1 BCF are not disclosed in this table. CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 247 Rest of Europe Italy North Africa Egypt Africa Kazakhstan Sub-Saharan Rest of Asia America Australia and Oceania Total (billion cubic feet) 2017 Consolidated subsidiaries Reserves at December 31, 2016 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2017 Equity-accounted entities Reserves at December 31, 2016 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2017 Reserves at December 31, 2017 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities 1,131 987 987 144 144 896 771 771 125 125 977 845 132 315 (161) 878 801 77 163 29 (174) 3,738 1,732 2,006 66 (19) (640) 1,131 896 3,145 5,520 799 4,721 969 64 (315) (1,887) 4,351 15 15 (1) 14 3,159 1,247 1,233 14 1,912 1,912 4,351 1,421 1,421 2,930 2,930 2,767 1,651 1,116 1 134 1,839 (162) (919) 3,660 368 104 264 13 (32) 349 4,009 1,776 1,693 83 2,233 1,967 266 2,485 2,239 246 1,003 280 723 353 338 15 (281) 188 (61) (96) (126) 4 (71) 2,108 1,065 225 4 4 3,484 1,782 1,702 (1,565) (4) (100) 2,108 1,878 1,878 230 230 1,065 862 862 203 203 1,819 2,044 1,990 171 1,819 54 54 741 559 182 6 (38) 709 709 519 519 190 190 18,462 9,244 9,218 1 1,499 (19) 1,936 (1,783) (2,806) 17,290 3,871 1,905 1,966 (1,552) (137) 2,182 19,472 11,451 9,535 1,916 8,021 7,755 266 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 248 (billion cubic feet) 2016 Consolidated subsidiaries Reserves at December 31, 2015 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2016 Equity-accounted entities Reserves at December 31, 2015 of which: developed undeveloped Purchase of Minerals in Place Revisions of Previous Estimates Improved Recovery Extensions and Discoveries Production Sales of Minerals in Place Reserves at December 31, 2016 Reserves at December 31, 2016 Developed consolidated subsidiaries equity-accounted entities Undeveloped consolidated subsidiaries equity-accounted entities Rest of Europe Italy North Africa Egypt Africa Kazakhstan of Asia America Sub-Saharan Rest Australia and Oceania Total 1,304 1,051 253 1,044 919 125 3,851 1,744 2,107 947 822 125 2,714 1,390 1,324 2,354 1,830 524 878 185 693 439 373 66 771 585 186 14,302 8,899 5,403 (155) 18 471 25 223 224 200 8 12 1,026 (172) (184) (584) 4,767 (219) (170) (93) 15 (90) (94) (42) 4,782 (1,648) 977 878 3,738 5,520 2,767 2,485 1,003 353 741 18,462 13 13 4 (2) 977 845 845 132 132 878 801 801 77 77 15 3,753 1,747 1,732 15 2,006 2,006 5,520 799 799 4,721 4,721 387 85 302 (8) (11) 368 3,135 1,755 1,651 104 1,380 1,116 264 12 9 3 3,581 1,295 2,286 (1) (4) (7) (93) 4 1,007 284 280 4 723 723 2,485 2,239 2,239 246 246 3,484 3,837 2,120 338 1,782 1,717 15 1,702 741 559 559 182 182 3,993 1,402 2,591 (9) (113) 3,871 22,333 11,149 9,244 1,905 11,184 9,218 1,966 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 249 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year- end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the Countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities - Oil and Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni’s proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity. The standardized measure of discounted future net cash flows by geographical area consists of the following: (€ million) December 31, 2018 Consolidated subsidiaries Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Equity-accounted entities Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Total consolidated subsidiaries and equity-accounted entities Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 18,372 (5,659) 4,895 (1,438) 43,578 39,193 (6,653) (12,193) 53,534 (16,417) 40,698 (8,276) 33,384 (9,492) 14,192 (6,038) 2,319 (511) 250,165 (66,677) (4,670) (1,350) (4,700) (2,769) (6,778) (2,640) (5,755) (2,467) (291) (31,420) 8,043 (1,671) 6,372 (2,045) 2,107 (798) 1,309 (124) 32,225 (17,514) 14,711 (6,727) 24,231 (7,829) 16,402 (6,564) 30,339 (11,566) 18,773 (7,501) 29,782 (6,524) 23,258 (12,477) 18,137 (11,980) 6,157 (2,258) 5,687 (1,791) 3,896 (1,508) 1,517 (289) 1,228 (491) 152,068 (59,962) 92,106 (39,695) 4,327 1,185 7,984 9,838 11,272 10,781 3,899 2,388 737 52,411 18,608 (4,686) (3,633) 10,289 (6,822) 3,467 (1,104) 2,363 347 (138) (3) 206 (43) 163 (76) 87 2,675 (873) (75) 1,727 (204) 1,523 (793) 730 8,292 (2,192) (191) 5,909 (1,839) 4,070 (2,009) 2,061 29,922 (7,889) (3,902) 18,131 (8,908) 9,223 (3,982) 5,241 4,327 3,548 8,071 9,838 12,002 10,781 3,899 4,449 737 57,652 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 250 (€ million) December 31, 2017 Consolidated subsidiaries Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Equity-accounted entities Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Total consolidated subsidiaries and equity-accounted entities (€ million) December 31, 2016 Consolidated subsidiaries Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Equity-accounted entities Future cash inflows Future production costs Future development and abandonment costs Future net inflow before income tax Future income tax Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Total consolidated subsidiaries and equity-accounted entities Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 14,339 (5,091) 19,507 (5,711) 31,793 (6,677) 29,156 (6,153) 41,136 (14,790) 30,263 (6,992) 11,826 (3,653) 6,205 (2,351) 2,593 186,818 (52,008) (590) (3,943) (5,483) (4,350) (4,496) (6,522) (2,787) (3,694) (1,011) (318) (32,604) 5,305 (859) 4,446 (1,633) 8,313 (4,490) 3,823 (1,050) 20,766 (10,836) 9,930 (4,566) 18,507 (5,709) 12,798 (6,698) 19,824 (6,418) 13,406 (5,430) 20,484 (3,970) 16,514 (9,172) 4,479 (757) 3,722 (1,239) 2,843 (699) 2,144 (777) 1,685 102,206 (34,041) (303) 68,165 1,382 (31,172) (607) 2,813 2,773 5,364 6,100 245 (119) (1) 125 (21) 104 (50) 54 7,976 2,062 (930) (66) 1,066 (57) 1,009 (471) 538 7,342 2,483 1,367 775 36,993 11 (6) 10,797 (3,291) (535) 6,971 (2,459) 4,512 (2,475) 5 (1) 4 4 2,037 13,115 (4,346) (602) 8,167 (2,538) 5,629 (2,996) 2,633 2,813 2,773 5,418 6,100 8,514 7,342 2,487 3,404 775 39,626 Rest Sub-Saharan Italy of Europe North Africa Egypt Africa Kazakhstan Rest of Asia America Australia and Oceania Total 9,627 (4,136) 12,898 (5,240) 30,847 (7,481) 33,524 (7,927) 38,271 (13,913) 26,903 (9,247) 12,263 (3,498) 5,789 (2,935) 2,815 (658) 172,937 (55,035) (3,641) (3,575) (5,904) (6,981) (9,392) (3,268) (5,047) (1,313) (270) (39,391) 1,850 (237) 1,613 (241) 4,083 (1,308) 2,775 (365) 17,462 (9,253) 8,209 (4,060) 18,616 (5,941) 12,675 (8,055) 14,966 (4,525) 10,441 (4,594) 14,388 (2,596) 11,792 (6,536) 3,718 (953) 2,765 (1,266) 1,541 (298) 1,243 (501) 1,887 (341) 1,546 (724) 78,511 (25,452) 53,059 (26,342) 1,372 2,410 4,149 4,620 259 (143) (1) 115 (21) 94 (46) 48 5,847 2,429 (974) (64) 1,391 (115) 1,276 (734) 542 5,256 1,499 742 822 26,717 33 (20) 16,430 (4,614) (1,186) 10,630 (3,667) 6,963 (4,441) 13 (4) 9 9 2,522 19,151 (5,751) (1,251) 12,149 (3,807) 8,342 (5,221) 3,121 1,372 2,410 4,197 4,620 6,389 5,256 1,508 3,264 822 29,838 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 251 CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2018, 2017 and 2016, are as follows: Consolidated subsidiaries Equity-accounted entities (€ million) 2018 Standardized measure of discounted future net cash flows at December 31, 2017 Increase (Decrease): - sales, net of production costs - net changes in sales and transfer prices, net of production costs - extensions, discoveries and improved recovery, net of future production and development costs - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs - revisions of quantity estimates - accretion of discount - net change in income taxes - purchase of reserves in-place - sale of reserves in-place - changes in production rates (timing) and other Net increase (decrease) Standardized measure of discounted future net cash flows at December 31, 2018 2017 Standardized measure of discounted future net cash flows at December 31, 2016 Increase (Decrease): - sales, net of production costs - net changes in sales and transfer prices, net of production costs - extensions, discoveries and improved recovery, net of future production and development costs - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs - revisions of quantity estimates - accretion of discount - net change in income taxes - purchase of reserves in-place - sale of reserves in-place - changes in production rates (timing) and other Net increase (decrease) Standardized measure of discounted future net cash flows at December 31, 2017 2016 Standardized measure of discounted future net cash flows at December 31, 2015 Increase (Decrease): - sales, net of production costs - net changes in sales and transfer prices, net of production costs - extensions, discoveries and improved recovery, net of future production and development costs - changes in estimated future development and abandonment costs - development costs incurred during the period that reduced future development costs - revisions of quantity estimates - accretion of discount - net change in income taxes - purchase of reserves in-place - sale of reserves in-place - changes in production rates (timing) and other Net increase (decrease) Standardized measure of discounted future net cash flows at December 31, 2016 36,993 (19,793) 27,970 1,649 (2,525) 6,468 10,487 5,670 (16,566) 5,369 (8,363) 5,052 15,418 52,411 26,717 (14,125) 23,940 1,697 (2,817) 7,203 5,269 3,864 (6,498) 10 (2,995) (5,272) 10,276 36,993 34,469 (11,222) (24,727) 4,563 (2,357) 7,578 2,840 5,705 9,200 668 (7,752) 26,717 Total 39,626 (20,238) 28,641 1,649 (2,309) 6,482 9,684 6,054 (16,373) 12,069 (8,363) 730 18,026 57,652 2,633 (445) 671 216 14 (803) 384 193 6,700 (4,322) 2,608 5,241 3,121 29,838 (432) 1,482 495 45 (2,285) 438 238 (469) (488) 2,633 (14,557) 25,422 1,697 (2,322) 7,248 2,984 4,302 (6,260) 10 (2,995) (5,741) 9,788 39,626 3,321 37,790 (347) (1,586) 650 151 (131) 514 386 163 (200) 3,121 (11,569) (26,313) 4,563 (1,707) 7,729 2,709 6,219 9,586 831 (7,952) 29,838 CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 252 Certification pursuant to rule 154-bis, paragraph 5 of the Legislative Decree No. 58/1998 (Testo Unico della Finanza) 1. • • 2. The undersigned Claudio Descalzi and Massimo Mondazzi, in their quality as Chief Executive Officer and Officer responsible for the preparation of financial reports of Eni, also pursuant to article 154-bis, paragraphs 3 and 4 of Legislative Decree No. 58 of February 24, 1998, certify that internal controls over financial reporting in place for the preparation of the consolidated financial statements as of December 31, 2018 and during the period covered by the report, were: adequate to the Company structure, and effectively applied during the process of preparation of the report. Internal controls over financial reporting in place for the preparation of the 2018 consolidated financial statements have been defined and the evaluation of their effectiveness has been assessed based on principles and methodologies adopted by Eni in accordance with the Internal Control-Integrated Framework Model issued by the Committee of Sponsoring Organizations of the Treadway Commission, which represents an internationally-accepted framework for the internal control system. The undersigned officers also certify that: 3. 3.1 2018 consolidated financial statements: a) have been prepared in accordance with applicable international accounting standards adopted by the European Community pursuant to Regulation (CE) n. 1606/2002 of the European Parliament and European Council of July 19, 2002; b) correspond to the accounting books and entries; c) fairly and truly represent the financial position, the performance and the cash flows of the issuer and the companies included in the consolidation as of, and for, the period presented in this report. 3.2 The operating and financial review provides a reliable analysis of business trends and results, including trend analysis of the issuer and the companies included in the consolidation, as well as a description of the main risks and uncertainties to which they are exposed. March 14, 2019 /s/ Claudio Descalzi Claudio Descalzi Chief Executive Officer /s/ Massimo Mondazzi Massimo Mondazzi Chief Financial Officer and Officer responsible for the preparation of financial reports Report of Independent Auditors 253 254 255 256 257 258 Annex 2018 2 | M A N A G E M E N T R E P O R T 1 3 7 | C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S 2 5 9 | A N N E X List of companies owned by Eni SpA as of December 31, 2018 Investments owned by Eni as of December 31, 2018 Changes in the scope of consolidation for 2018 260 260 282 260 LIST OF COMPANIES OWNED BY ENI SPA AS OF DECEMBER 31, 2018 INVESTMENTS OWNED BY ENI AS OF DECEMBER 31, 2018 In accordance with the provisions of articles 38 and 39 of the Legislative Decree No. 127/1991 and Consob communication No. DEM/6064293 of July 28, 2006, the list of subsidiaries, associates and significant investments owned by Eni SpA as of December 31, 2018, is presented below. Companies are divided by business segment and, within each segment, they are ordered between Italy and outside Italy and alphabetically. For each company are indicated: company name, registered head office, operating office, share capital, shareholders and percentage of ownership; for consolidated subsidiaries is indicated the equity ratio attributable to Eni; for unconsolidated investments owned by consolidated companies is indicated the valuation method. In the footnotes are indicated which investments are quoted in the Italian regulated markets or in other regulated markets of the European Union and the percentage of the ordinary voting rights entitled to shareholders if different from the percentage of ownership. The currency codes indicated are reported in accordance with the International Standard ISO 4217. As of December 31, 2018, the breakdown of the companies owned by Eni is provided in the table below: Fully consolidated subsidiaries Consolidated joint operations Investments owned by consolidated companies(b) Equity-accounted investments Investments valued at cost Investments valued at fair value Investments owned by unconsolidated companies Owned by joint arrangements Subsidiaries Italy Outside Italy 28 147 Total 175 Joint arrangements and associates Other significant investments(a) Italy Outside Italy Total Italy Outside Italy Total 7 5 12 4 4 8 26 4 30 30 8 38 18 3 21 36 31 67 3 3 75 54 34 88 3 3 103 3 3 3 22 22 25 25 22 25 Total 36 177 213 28 (a) Relates to investments other than subsidiaries, joint arrangements and associates with an ownership interest greater than 2% for listed companies or 10% for unlisted companies. (b) Investments in subsidiaries accounted for using the equity method and valued at cost relate to non-significant companies. SUBSIDIARIES AND JOINT ARRANGEMENTS RESIDENT IN STATES OR TERRITORY WITH A PRIVILEGED TAX REGIME The Law of December 28, 2015, No. 208 (Stability Law 2016), effective from January 1, 2016, amended the article No. 167, paragraph 4, of the Presidential Decree of December 22, 1986 No. 917, identifying all the tax regimes, even special, of states or territories to be considered as privileged with reference, exclusively, to a nominal level of taxation lower than 50 percent of the one applicable in Italy. Furthermore, the regimes of states or territories that are part of the European Union, or of states that are part of the European Economic Area that have concluded agreements with Italy ensuring an effective exchange of information are not considered as privileged. At December 31, 2018, Eni controls 10 companies based in states with a privileged tax regime as identified by article No. 167, paragraph 4 of the Italian Income Tax Code. Of these 10 companies, 6 are subject to taxation in Italy because they are included in the tax return of Eni. The remaining 4 companies are not subject to Italian taxation, but to the specific local tax regimes, as a consequence of the exemption obtained by the Italian Revenue Agency by taking into account of the taxation level applied. Of these 10 companies, 8 come from the acquisitions of Lasmo Plc, the activities carried out in Congo by Maurel & Prom, Burren Energy Plc and Hess Indonesia. These subsidiaries, resident or located in states identified by the Decree, did not issued any financial instrument and all the financial statements for 2018 will be audited by Ernst & Young. ANNEX TO FINANCIAL STATEMENTS | INVESTMMENTS OWNED BY ENI AS OF DECEMBER 31, 2018 PARENT COMPANY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Eni SpA(#) Rome Italy EUR 4,005,358,876 Cassa Depositi e Prestiti SpA Ministero dell'Economia e delle Finanze Eni SpA Other shareholders 261 p i h s r e n w O % 25.76 4.34 0.91 68.99 SUBSIDIARIES Exploration & Production IN ITALY e m a n y n a p m o C Eni Angola SpA Eni Mediterranea Idrocarburi SpA Eni Mozambico SpA Eni Timor Leste SpA Eni West Africa SpA Eni Zubair SpA (in liquidation) EniProgetti SpA Floaters SpA Ieoc SpA Società Petrolifera Italiana SpA e c ffi o d e r e t s i g e R San Donato Milanese (MI) Gela (CL) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) Venezia Marghera (VE) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Angola EUR 20,200,000 Eni SpA 100.00 100.00 Italy Mozambique EUR EUR 5,200,000 Eni SpA 200,000 Eni SpA 100.00 100.00 100.00 100.00 East Timor EUR 6,841,517 Eni SpA 100.00 100.00 Angola EUR 10,000,000 Eni SpA 100.00 100.00 Italy Italy Italy EUR 120,000 Eni SpA 100.00 EUR 2,064,000 Eni SpA 100.00 100.00 EUR 200,120,000 Eni SpA 100.00 100.00 Egypt EUR 7,518,000 Eni SpA 100.00 100.00 Italy EUR 13,877,600 Eni SpA Third parties 99.96 0.04 99.96 F.C. F.C. F.C. F.C. F.C. Co. F.C. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (#) Company with shares quoted in the regulated market of Italy or of other EU Countries. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 262 OUTSIDE ITALY e m a n y n a p m o C Agip Caspian Sea BV Agip Energy and Natural Resources (Nigeria) Ltd Agip Karachaganak BV Agip Oil Ecuador BV Agip Oleoducto de Crudos Pesados BV Burren Energy (Bermuda) Ltd(9) Burren Energy (Egypt) Ltd Burren Energy Congo Ltd(9) Burren Energy India Ltd Burren Energy Plc Burren Shakti Ltd(8) Eni Abu Dhabi BV Eni AEP Ltd Eni Algeria Exploration BV Eni Algeria Ltd Sàrl Eni Algeria Production BV Eni Ambalat Ltd Eni America Ltd Eni Angola Exploration BV Eni Angola Production BV Eni Argentina Exploración y Explotación SA Eni Arguni I Ltd Eni Australia BV Eni Australia Ltd Eni Bahrain BV e c ffi o d e r e t s i g e R Amsterdam (Netherlands) Abuja (Nigeria) Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Hamilton (Bermuda) London (United Kingdom) Tortola (British Virgin Islands) London (United Kingdom) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % Kazakhstan EUR 20,005 Eni International BV 100.00 100.00 Nigeria NGN 5,000,000 Eni International BV Eni Oil Holdings BV 95.00 5.00 100.00 Kazakhstan EUR 20,005 Eni International BV 100.00 100.00 Ecuador Ecuador United Kingdom Egypt Republic of the Congo United Kingdom EUR EUR USD GBP USD GBP 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 12,002 Burren Energy Plc 100.00 100.00 2 Burren Energy Plc 100.00 50,000 Burren En. (Berm) Ltd 100.00 100.00 2 Burren Energy Plc 100.00 100.00 London (United Kingdom) United Kingdom Hamilton (Bermuda) United Kingdom Amsterdam (Netherlands) United Arab Emirates GBP 28,819,023 Eni UK Holding Plc Eni UK Ltd 99.99 (..) 100.00 USD 65,300,000 Burren En. India Ltd 100.00 100.00 EUR 20,000 Eni International BV 100.00 100.00 London (United Kingdom) Amsterdam (Netherlands) Luxembourg (Luxembourg) Amsterdam (Netherlands) London (United Kingdom) Pakistan GBP 73,471,000 Eni UK Ltd 100.00 100.00 Algeria Algeria Algeria EUR USD EUR 20,000 Eni International BV 100.00 100.00 20,000 Eni Oil Holdings BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 USD EUR EUR 72,000 Eni UHL Ltd 100.00 100.00 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Dover, Delaware (USA) USA Angola Angola Amsterdam (Netherlands) Amsterdam (Netherlands) Buenos Aires (Argentina) Argentina ARS 24,136,336 Eni International BV Eni Oil Holdings BV 95.00 5.00 London (United Kingdom) Indonesia Amsterdam (Netherlands) Australia GBP EUR 1 Eni Indonesia Ltd 100.00 100.00 20,000 Eni International BV 100.00 100.00 London (United Kingdom) Amsterdam (Netherlands) Australia GBP 20,000,000 Eni International BV 100.00 100.00 Netherlands EUR 20,000 Eni International BV 100.00 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. F.C. F.C. F.C. Eq. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is subject to the Italian taxation. (9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian taxation following the admission of the instance by the Italian Revenue Agency. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES e m a n y n a p m o C Eni BB Petroleum Inc Eni BTC Ltd Eni Bukat Ltd Eni Bulungan BV Eni Canada Holding Ltd Eni CBM Ltd Eni China BV Eni Congo SA Eni Côte d’Ivoire Ltd Eni Cyprus Ltd Eni Denmark BV Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda Eni East Ganal Ltd Eni East Sepinggan Ltd Eni Elgin/Franklin Ltd Eni Energy Russia BV Eni Exploration & Production Holding BV Eni Gabon SA Eni Ganal Ltd Eni Gas & Power LNG Australia BV Eni Ghana Exploration and Production Ltd Eni Hewett Ltd Eni Hydrocarbons Venezuela Ltd Eni India Ltd Eni Indonesia Ltd e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C Dover, Delaware (USA) USA London (United Kingdom) United Kingdom London (United Kingdom) Indonesia Indonesia y c n e r r u C USD l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % 1,000 Eni Petroleum Co Inc 100.00 100.00 GBP 23,214,400 Eni International BV 100.00 GBP EUR 1 Eni Indonesia Ltd 100.00 100.00 20,000 Eni International BV 100.00 Amsterdam (Netherlands) Calgary (Canada) London (United Kingdom) Amsterdam (Netherlands) Pointe-Noire (Republic of the Congo) London (United Kingdom) Nicosia (Cyprus) Amsterdam (Netherlands) Rio de Janeiro (Brazil) London (United Kingdom) London (United Kingdom) Canada USD 1,453,200,001 Eni International BV 100.00 100.00 Indonesia USD 2,210,728 Eni Lasmo Plc 100.00 100.00 China EUR 20,000 Eni International BV 100.00 100.00 Republic of the Congo USD 17,000,000 Ivory Coast GBP 1 Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV Eni UK Ltd 99.99 (..) (..) 100.00 100.00 100.00 Cyprus Greenland EUR EUR 2,006 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100,00 Brazil BRL 1,593,415,000 Eni International BV Eni Oil Holdings BV 99.99 (..) Indonesia GBP Indonesia GBP 1 1 Eni Indonesia Ltd 100.00 100.00 Eni Indonesia Ltd 100.00 100.00 London (United Kingdom) United Kingdom GBP 100 Eni UK Ltd 100.00 100.00 Amsterdam (Netherlands) Amsterdam (Netherlands) Libreville (Gabon) London (United Kingdom) Amsterdam (Netherlands) Accra (Ghana) Netherlands EUR 20,000 Eni International BV 100.00 100.00 Netherlands EUR 29,832,777.12 Eni International BV 100.00 100.00 Gabon XAF 13,132,000,000 Eni International BV 100.00 100.00 Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 Australia EUR 10,000,000 Eni International BV 100.00 100.00 Ghana GHS 21,412,500 Eni International BV 100.00 100.00 Aberdeen (United Kingdom) United Kingdom GBP 3,036,000 Eni UK Ltd 100.00 100.00 London (United Kingdom) London (United Kingdom) London (United Kingdom) Venezuela GBP 8,050,500 Eni Lasmo Plc 100.00 100.00 India GBP 44,000,000 Eni UK Ltd 100.00 100.00 Indonesia GBP 100 Eni ULX Ltd 100.00 100.00 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. 263 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. Eq. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 264 e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eni Indonesia Ots 1 Ltd(8) Eni International NA NV Sàrl Eni Investments Plc Grand Cayman (Cayman Islands) Indonesia USD 1.01 Eni Indonesia Ltd 100.00 100.00 Luxembourg (Luxembourg) United Kingdom London (United Kingdom) United Kingdom USD 25,000 Eni International BV 100.00 100.00 GBP 750,050,000 Eni SpA Eni UK Ltd 99.99 (..) 100.00 Eni Iran BV Eni Iraq BV(24) Eni Ireland BV Eni Isatay BV Eni JPDA 03-13 Ltd Eni JPDA 06-105 Pty Ltd Eni JPDA 11-106 BV Eni Kenya BV Eni Krueng Mane Ltd Eni Lasmo Plc Eni Lebanon BV Eni Liberia BV Eni Liverpool Bay Operating Co Ltd Eni LNS Ltd Eni Marketing Inc Eni Maroc BV Eni México S. de RL de CV Eni Middle East Ltd Eni MOG Ltd (in liquidation) Eni Montenegro BV Eni Mozambique Engineering Ltd Eni Mozambique LNG Holding BV Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) London (United Kingdom) Perth (Australia) Amsterdam (Netherlands) Amsterdam (Netherlands) London (United Kingdom) Iran Iraq Ireland EUR EUR EUR 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Kazakhstan EUR 20,000 Eni International BV 100.00 100.00 Australia GBP 250,000 Eni International BV 100.00 100.00 Australia AUD 80,830,576 Eni International BV 100.00 100.00 Australia Kenya EUR EUR 50,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 London (United Kingdom) United Kingdom GBP 337,638,724.25 Eni Investments Plc Eni UK Ltd 99.99 (..) 100.00 Amsterdam (Netherlands) Amsterdam (Netherlands) Lebanon Liberia London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom Dover, Delaware (USA) USA Amsterdam (Netherlands) Lomas De Chapultepec, Mexico City (Mexico) London (United Kingdom) Morocco Mexico United Kingdom EUR EUR GBP 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 1 Eni UK Ltd 100.00 GBP 80,400,000 Eni UK Ltd 100.00 100.00 USD EUR MXN 1,000 Eni Petroleum Co Inc 100.00 100.00 20,000 Eni International BV 100.00 100.00 3,000 Eni International BV Eni Oil Holdings BV 99.90 0.10 100.00 GBP 1 Eni ULT Ltd 100.00 100.00 London (United Kingdom) United Kingdom GBP 220,711,147.50 Eni Lasmo Plc Eni LNS Ltd 99.99 (..) 100.00 Amsterdam (Netherlands) London (United Kingdom) Amsterdam (Netherlands) Montenegro EUR 20,000 Eni International BV 100.00 100.00 United Kingdom Netherlands GBP EUR 1 Eni UK Ltd 100.00 100.00 20,000 Eni International BV 100.00 100.00 F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is subject to the Italian taxation. (24) The company has a branch in Iraq and in Dubai, United Arab Emirates, state or territory with a privileged tax regime as provided in article 167, paragraph 4 of Presidential Decree of December 22, 1986, No.917: the profit pertaining to the Group is subject to the Italian taxation. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES e m a n y n a p m o C Eni Muara Bakau BV Eni Myanmar BV Eni North Africa BV Eni North Ganal Ltd Eni Oil & Gas Inc Eni Oil Algeria Ltd Eni Oil Holdings BV Eni Oman BV Eni Pakistan Ltd Eni Pakistan (M) Ltd Sàrl Eni Petroleum Co Inc Eni Petroleum US Llc Eni Portugal BV Eni Rapak Ltd Eni RD Congo SA Eni Rovuma Basin BV Eni Sharjah BV Eni South Africa BV Eni South China Sea Ltd Sàrl Eni TNS Ltd Eni Tunisia BV Eni Turkmenistan Ltd(9) Eni UHL Ltd Eni UK Holding Plc Eni UK Ltd Eni UKCS Ltd e c ffi o d e r e t s i g e R Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) London (United Kingdom) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % Indonesia EUR 20,000 Eni International BV 100.00 100.00 Myanmar Libya EUR EUR 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 Dover, Delaware (USA) USA London (United Kingdom) Algeria USD GBP 100,800 Eni America Ltd 100.00 100.00 1,000 Eni Lasmo Plc 100.00 100.00 Amsterdam (Netherlands) Amsterdam (Netherlands) London (United Kingdom) Luxembourg (Luxembourg) Dover, Delaware (USA) Dover, Delaware (USA) Amsterdam (Netherlands) London (United Kingdom) Kinshasa (Democratic Republic of the Congo ) Amsterdam (Netherlands) Amsterdam (Netherlands) Amsterdam (Netherlands) Luxembourg (Luxembourg) Aberdeen (Regno Unito) Amsterdam (Netherlands) Hamilton (Bermuda) Netherlands EUR 450,000 Eni ULX Ltd 100.00 100.00 Oman EUR 20,000 Eni International BV 100.00 100.00 Pakistan GBP 90,087 Eni ULX Ltd 100.00 100.00 Pakistan USD 20,000 Eni Oil Holdings BV 100.00 100.00 USA USA Portugal USD 156,600,000 Eni SpA Eni International BV 63.86 36.14 100.00 USD EUR 1,000 Eni BB Petroleum Inc 100.00 100.00 20,000 Eni International BV 100.00 100.00 Indonesia GBP 2 Eni Indonesia Ltd 100.00 100.00 Democratic Republic of the Congo CDF 750,000,000 Eni International BV Eni Oil Holdings BV 99.99 (..) Mozambique EUR 20,000 Eni Mozambique LNG H. BV 100.00 100.00 Netherlands EUR 20,000 Eni International BV 100.00 100.00 Republic of South Africa China United Kingdom Tunisia EUR USD GBP EUR 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 1,000 Eni UK Ltd 100.00 100.00 20,000 Eni International BV 100.00 100.00 Turkmenistan USD 20,000 Burren En.(Berm)Ltd 100.00 100.00 London (United Kingdom) London (United Kingdom) United Kingdom United Kingdom London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom GBP 1 Eni ULT Ltd 100.00 100.00 GBP 424,050,000 Eni Lasmo Plc Eni UK Ltd 99.99 (..) 100.00 GBP 250,000,000 Eni International BV 100.00 100.00 GBP 100 Eni UK Ltd 100.00 100.00 265 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian taxation following the admission of the instance by the Italian Revenue Agency. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 266 e m a n y n a p m o C Eni Ukraine Holdings BV Eni Ukraine Llc Eni Ukraine Shallow Waters BV Eni ULT Ltd Eni ULX Ltd Eni US Operating Co Inc Eni USA Gas Marketing Llc Eni USA Inc Eni Venezuela BV Eni Venezuela E&P Holding SA Eni Ventures Plc (in liquidation) Eni Vietnam BV Eni West Timor Ltd Eni Yemen Ltd EniProgetti Egypt Ltd Eurl Eni Algérie First Calgary Petroleums LP First Calgary Petroleums Partner Co ULC Ieoc Exploration BV Ieoc Production BV Lasmo Sanga Sanga Ltd(9) Liverpool Bay Ltd Nigerian Agip CPFA Ltd Nigerian Agip Exploration Ltd Nigerian Agip Oil Co Ltd e c ffi o d e r e t s i g e R Amsterdam (Netherlands) Kiev (Ukraine) Amsterdam (Netherlands) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % Netherlands EUR 20,000 Eni International BV 100.00 100.00 Ukraine UAH 42,004,757.64 Eni Ukraine Hold. BV Eni International BV Ukraine EUR 20,000 Eni Ukraine Hold. BV 100.00 99.99 0.01 100.00 London (United Kingdom) United Kingdom London (United Kingdom) United Kingdom GBP 93,215,492.25 Eni Lasmo Plc 100.00 100.00 GBP 200,010,000 Eni ULT Ltd 100.00 100.00 USA USA USA USD USD USD 1,000 Eni Petroleum Co Inc 100.00 100.00 10,000 Eni Marketing Inc 100.00 100.00 1,000 Eni Oil & Gas Inc 100.00 100.00 Venezuela EUR 20,000 Eni Venezuela E&P H. 100.00 100.00 Belgium USD 254,057,680 London (United Kingdom) United Kingdom GBP 278,050,000 Eni International BV Eni Oil Holdings BV Eni International BV Eni Oil Holdings BV 100.00 99.99 (..) 99.99 (..) Amsterdam (Netherlands) London (United Kingdom) Vietnam EUR 20,000 Eni International BV 100.00 100.00 Indonesia GBP 1 Eni Indonesia Ltd 100.00 100.00 1,000 Burren Energy Plc 100.00 London (United Kingdom) United Kingdom Egypt GBP EGP Algeria DZD 1,000,000 Eni Algeria Ltd Sàrl 50,000 EniProgetti SpA Eni SpA 99.00 1.00 100.00 Algeria Canada Egypt Egypt USD CAD EUR EUR 1 Eni Canada Hold. Ltd FCP Partner Co ULC 99.99 0.01 100.00 10 Eni Canada Hold. Ltd 100.00 100.00 20,000 Eni International BV 100.00 100.00 20,000 Eni International BV 100.00 100.00 Indonesia USD 12,000 Eni Lasmo Plc 100.00 100.00 London (United Kingdom) United Kingdom USD 1 Eni ULX Ltd 100.00 Lagos (Nigeria) Abuja (Nigeria) Abuja (Nigeria) Nigeria NGN 1,262,500 Nigeria NGN 5,000,000 Nigeria NGN 1,800,000 NAOC Ltd Agip En Nat Res. Ltd Nigerian Agip E. Ltd Eni International BV Eni Oil Holdings BV Eni International BV Eni Oil Holdings BV 98.02 0.99 0.99 99.99 0.01 99.89 0.11 100.00 100.00 Dover, Delaware (USA) Dover, Delaware (USA) Dover, Delaware (USA) Amsterdam (Netherlands) Bruxelles (Belgium) Cairo (Egypt) Algiers (Algeria) Wilmington (USA) Calgary (Canada) Amsterdam (Netherlands) Amsterdam (Netherlands) Hamilton (Bermuda) n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. F.C. Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Co. F.C. F.C. Eq. Eq. Eq. F.C. F.C. F.C. F.C. F.C. Eq. Co. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian taxation following the admission of the instance by the Italian Revenue Agency. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES 267 e m a n y n a p m o C OOO “Eni Energhia” Zetah Congo Ltd(8) Zetah Kouilou Ltd(8) e c ffi o d e r e t s i g e R Moscow (Russia) Nassau (Bahamas) Nassau (Bahamas) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Russia RUB 2,000,000 Eni Energy Russia BV Eni Oil Holdings BV Republic of the Congo USD 300 Eni Congo SA Burren En. Congo Ltd Republic of the Congo USD 2,000 Eni Congo SA Burren En. Congo Ltd Third parties o i t a r y t i u q E % 100.00 p i h s r e n w O % 99.90 0.10 66.67 33.33 54.50 37.00 8.50 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. Co. Co. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is subject to the Italian taxation. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 268 Gas & Power IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Eni gas e luce SpA Eni Gas Transport Services Srl San Donato Milanese (MI) San Donato Milanese (MI) Eni Trading & Shipping SpA Rome EniPower Mantova SpA EniPower SpA LNG Shipping SpA Trans Tunisian Pipeline Co SpA San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) n o i t a r e p o f o y r t n u o C Italy Italy Italy Italy Italy Italy y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % EUR 750,000,000 Eni SpA 100.00 100.00 EUR 120,000 Eni SpA 100.00 EUR 60,036,650 Eni SpA 100.00 100.00 EUR 144,000,000 EniPower SpA Third parties EUR 944,947,849 Eni SpA 86.50 13.50 86.50 100.00 100.00 EUR 240,900,000 Eni SpA 100.00 100.00 Tunisia EUR 1,098,000 Eni SpA 100.00 100.00 OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana Ljubljana (Slovenia) Slovenia EUR 12,956,935 Eni gas e luce SpA Third parties 51.00 49.00 51.00 Turkey EUR 70,000 Eni International BV 100.00 100.00 Eni G&P Trading BV Eni Gas & Power France SA Eni Trading & Shipping Inc Amsterdam (Netherlands) Levallois Perret (France) France EUR 29,937,600 Eni gas e luce SpA Third parties Dover, Delaware (USA) USA USD 36,000,000 ETS SpA 99.87 0.13 99.87 100.00 100.00 Eni Transporte y Suministro México, S. de RL de CV Mexico City (Mexico) Gas Supply Company Thessaloniki-Thessalia SA Thessaloniki (Greece) Société de Service du Gazoduc Transtunisien SA - Sergaz SA Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA Tunisi (Tunisia) Tunisi (Tunisia) Mexico MXN 3,000 Eni International BV Eni Oil Holdings BV 99.90 0.10 Greece EUR 13,761,788 Eni gas e luce SpA 100.00 100.00 Tunisia Tunisia TND TND 99,000 Eni International BV Third parties 200,000 Eni International BV Eni SpA LNG Shipping SpA Trans Tunis. P. Co SpA 66.67 100.00 66.67 33.33 99.85 0.05 0.05 0.05 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. Co. F.C. F.C. F.C. F.C. F.C. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.C. F.C. F.C. F.C. Eq. F.C. F.C. F.C. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES 269 Refining & Marketing and Chemicals Refining & Marketing IN ITALY e m a n y n a p m o C Ecofuel SpA Eni Fuel SpA Raffineria di Gela SpA SeaPad SpA e c ffi o d e r e t s i g e R San Donato Milanese (MI) Rome Gela (CL) Genova Servizi Fondo Bombole Metano SpA Rome OUTSIDE ITALY e m a n y n a p m o C Eni Abu Dhabi Refining & Trading Bv Eni Austria GmbH Eni Benelux BV Eni Deutschland GmbH Eni Ecuador SA Eni France Sàrl Eni Iberia SLU Eni Lubricants Trading (Shangai) Co Ltd Eni Marketing Austria GmbH Eni Mineralölhandel GmbH Eni Schmiertechnik GmbH Eni Suisse SA Eni USA R&M Co Inc Esacontrol SA Esain SA Oléoduc du Rhône SA OOO “Eni-Nefto” Tecnoesa SA e c ffi o d e r e t s i g e R Amsterdam (Netherlands) Wien (Austria) Rotterdam (Netherlands) Munich (Germany) Quito (Ecuador) Lyon (France) Alcobendas (Spain) Shanghai (China) Wien (Austria) Wien (Austria) Wurzburg (Germany) Lausanne (Switzerland) Wilmington (USA) Quito (Ecuador) Quito (Ecuador) Valais (Switzerland) Moscow (Russia) Quito (Ecuador) n o i t a r e p o f o y r t n u o C Italy Italy Italy Italy Italy n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m EUR 52,000,000 Eni SpA 100.00 100.00 EUR 58,944,310 Eni SpA 100.00 100.00 EUR 15,000,000 Eni SpA 100.00 100.00 EUR 12,400,000 EUR 13,580,000.20 Ecofuel SpA Third parties Eni SpA 80.00 20.00 100.00 C.I. C.I. C.I. P.N. Co. y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Netherlands EUR 20,000 Eni International BV 100.00 Austria EUR 78,500,000 Netherlands EUR 1,934,040 Germany EUR 90,000,000 Ecuador USD 103,142.08 France EUR 56,800,000 Eni International BV Eni Deutsch. GmbH Eni International BV Eni International BV Eni Oil Holdings BV Eni International BV Esain SA Eni International BV 75.00 25.00 100.00 89.00 11.00 99.93 0.07 100.00 100.00 100.00 100.00 100.00 100.00 Spain China EUR 17,299,100 Eni International BV 100.00 100.00 EUR 5,000,000 Eni International BV 100.00 100.00 Austria EUR 19,621,665.23 Austria EUR 34,156,232.06 Eni Mineralölh. GmbH Eni International BV Eni Austria GmbH 99.99 (..) 100.00 100.00 100.00 Germany EUR 2,000,000 Eni Deutsch. GmbH 100.00 100.00 Switzerland CHF 102,500,000 Eni International BV 100.00 100.00 USA USD 11,000,000 Eni International BV 100.00 100.00 Ecuador Ecuador USD USD 60,000 30,000 Switzerland CHF 7,000,000 Russia RUB 1,010,000 Ecuador USD 36,000 Eni Ecuador SA Third parties Eni Ecuador SA Tecnoesa SA Eni International BV Eni International BV Eni Oil Holdings BV Eni Ecuador SA Esain SA 87.00 13.00 99.99 (..) 100.00 99.01 0.99 99.99 (..) 100.00 Eq. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. F.C. Eq. F.C. Eq. Eq. Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 270 Chemical e m a n y n a p m o C Versalis SpA IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R San Donato Milanese (MI) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Italy EUR 1,364,790,000 Eni SpA 100.00 100.00 F.C. e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Consorzio Industriale Gas Naturale (in liquidation) San Donato Milanese (MI) Italia EUR 124,000 Versalis SpA Raff. di Gela SpA Eni SpA Syndial SpA Raff. Milazzo ScpA 53.55 18.74 15.37 0.76 11.58 Eq. OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság Budapest (Hungary) Hungary HUF 8,092,160,000 USA USD 100,000 Versalis SpA Versalis Deutschland GmbH Versalis International SA Versalis International SA 96.34 1.83 1.83 100.00 100.00 100.00 Versalis Americas Inc Versalis Congo Sarlu Versalis Deutschland GmbH Versalis France SAS Versalis International SA Versalis Kimya Ticaret Limited Sirketi Versalis Pacific (India) Private Ltd Versalis Pacific Trading (Shanghai) Co Ltd Versalis Singapore Pte Ltd Versalis UK Ltd Dover, Delaware (USA) Pointe-Noire (Republic of the Congo) Eschborn (Germany) Mardyck (France) Bruxelles (Belgium) Istanbul (Turkey) Mumbai (India) Shanghai (China) Singapore (Singapore) London (United Kingdom) Republic of the Congo CDF 1,000,000 Versalis International SA 100.00 Germany EUR 100,000 Versalis SpA 100.00 100.00 France EUR 126,115,582.90 Versalis SpA 100.00 100.00 Belgium EUR 15,449,173.88 Turkey India China TRY INR 20,000 238,700 CNY 1,000,000 Versalis SpA Versalis Deutschland GmbH Dunastyr Zrt Versalis France Versalis International SA Versalis Singapore P. Ltd Third parties Versalis SpA 59.00 23.71 14.43 2.86 100.00 99.99 (..) 100.00 100.00 100.00 Singapore SGD 80,000 Versalis SpA 100.00 100.00 United Kingdom GBP 4,004,042 Versalis SpA 100.00 100.00 F.C. F.C. Eq. F.C. F.C. F.C. Eq. Eq. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES 271 Corporate and other activities Corporate and financial companies IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Agenzia Giornalistica Italia SpA Rome Eni Adfin SpA (in liquidation) Eni Corporate University SpA EniServizi SpA Serfactoring SpA Servizi Aerei SpA Rome San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) San Donato Milanese (MI) OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C Italy Italy Italy Italy Italy Italy n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m EUR 2,000,000 Eni SpA 100.00 100.00 EUR 85,537,498.80 Eni SpA Third parties EUR 3,360,000 Eni SpA 99.67 0.33 99.67 100.00 100.00 EUR 13,427,419.08 Eni SpA 100.00 100.00 EUR 5,160,000 Eni SpA Third parties EUR 79,817,238 Eni SpA 49.00 51.00 49.00 100.00 100.00 F.C. F.C. F.C. F.C. F.C. F.C. y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Banque Eni SA Eni Finance International SA Eni Finance USA Inc Eni Insurance Designated Activity Company Eni International BV Bruxelles (Belgium) Bruxelles (Belgium) Belgium EUR 50,000,000 Belgium USD 2,474,225,632 Eni International BV Eni Oil Holdings BV Eni International BV Eni SpA 99.90 0.10 66.39 33.61 100.00 100.00 Dover, Delaware (USA) USA USD 15,000,000 Eni Petroleum Co Inc 100.00 100.00 Dublin (Ireland) Amsterdam (Netherlands) Ireland EUR 500,000,000 Eni SpA 100.00 100.00 Netherlands EUR 641,683,425 Eni SpA 100.00 100.00 Eni International Resources Ltd Eni Next Llc London (United Kingdom) United Kingdom Houston (USA) USA GBP USD 50,000 Eni SpA Eni UK Ltd 99.99 (..) 100.00 100 Eni Petroleum Co Inc 100.00 100.00 F.C. F.C. F.C. F.C. F.C. F.C. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018 272 Other Activities IN ITALY e m a n y n a p m o C Anic Partecipazioni SpA (in liquidation) Eni Energia Srl Eni New Energy SpA Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) Ing. Luigi Conti Vecchi SpA Syndial Servizi Ambientali SpA OUTSIDE ITALY e m a n y n a p m o C Arm Wind Llp Eni New Energy Egypt SAE Oleodotto del Reno SA Windirect BV e c ffi o d e r e t s i g e R Gela (CL) San Donato Milanese (MI) San Donato Milanese (MI) Gela (CL) Assemini (CA) San Donato Milanese (MI) e c ffi o d e r e t s i g e R Astana (Kazakhstan) Cairo (Egypt) Coira (Switzerland) Amsterdam (Netherlands) n o i t a r e p o f o y r t n u o C Italy Italy Italy Italy Italy Italy n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % EUR 23,519,847.16 EUR 10,000 Syndial SpA Third parties Eni SpA 99.97 0.03 100.00 EUR 9,296,000 Eni SpA 100.00 100.00 EUR 1,300,000 Syndial SpA Third parties 52.00 48.00 EUR 5,518,620.64 Syndial SpA 100.00 100.00 EUR 425,647,621.42 Eni SpA Third parties 99.99 (..) 100.00 y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. Co. F.C. Eq. F.C. F.C. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Kazakhstan KZT 2,133,967,100 Windirect BV 100.00 90.00 Egypt EGP 250,000 Eni International BV Ieoc Exploration BV Ieoc Production BV Switzerland CHF 1,550,000 Syndial SpA Netherlands EUR 10,000 Eni International BV Soci Terzi 99.98 0.01 0.01 100.00 90.00 10.00 90.00 F.C. Eq. Eq. F.C. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES JOINT ARRANGEMENTS AND ASSOCIATES Exploration & Production IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Mozambique Rovuma Venture SpA(†) San Donato Milanese (MI) Mozambique EUR 20,000,000 Eni SpA Third parties OUTSIDE ITALY e m a n y n a p m o C Agiba Petroleum Co(†) Angola LNG Ltd Ashrafi Island Petroleum Co Barentsmorneftegaz Sàrl(†) Cabo Delgado Gas Development Limitada(†) Cardón IV SA(†) Compañia Agua Plana SA Coral FLNG SA Coral South FLNG DMCC East Delta Gas Co (in liquidation) East Kanayis Petroleum Co(†) East Obaiyed Petroleum Company(†) El-Fayrouz Petroleum Co(†) (in liquidation) El Temsah Petroleum Co Fedynskmorneftegaz Sàrl(†) Isatay Operating Company Llp(†) e c ffi o d e r e t s i g e R Cairo (Egypt) Hamilton (Bermuda) Cairo (Egypt) Luxembourg (Luxembourg) Maputo (Mozambique) Caracas (Venezuela) Caracas (Venezuela) Maputo (Mozambique) Dubai (United Arab Emirates) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Luxembourg (Luxembourg) Astana (Kazakhstan) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Egypt EGP 20,000 Angola USD 10,082,000,000 Egypt Russia EGP USD 20,000 20,000 Mozambique MZN 2,500,000 Venezuela Venezuela VES VES 172.1 0.001 Mozambico MZN 100,000,000 United Arab Emirates AED 500,000 Ieoc Production BV Third parties Eni Angola Prod. BV Third parties Ieoc Production BV Third parties Eni Energy Russia BV Third parties Eni Mozambique LNG H. BV Third parties Eni Venezuela BV Third parties Eni Venezuela BV Third parties Eni Mozambique LNG H. BV Third parties Eni Mozambique LNG H. BV Third parties Egypt Egypt Egypt Egypt Egypt Russia EGP EGP EGP EGP EGP USD 20,000 20,000 20,000 20,000 20,000 20,000 Kazakhstan KZT 400,000 Ieoc Production BV Third parties Ieoc Production BV Third parties Ieoc SpA Third parties Ieoc Exploration BV Third parties Ieoc Production BV Third parties Eni Energy Russia BV Third parties Eni Isatay Third parties Agip Karachaganak BV Third parties Agip Karachaganak BV Third parties Eni Middle E. Ltd Third parties Karachaganak Petroleum Operating BV Amsterdam Kazakhstan EUR 20,000 Karachaganak Project Development Ltd (KPD) Khaleej Petroleum Co Wll (Netherlands) Reading, Berkshire (United Kingdom) Safat (Kuwait) United Kingdom GBP 100 Kuwait KWD 250,000 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. 273 o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m 35.71 J.O. o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Co. Eq. Co. Eq. Co. Eq. Co. Eq. Eq. Co. Co. Co. Co. Co. Eq. Co. Co. Eq. Eq. p i h s r e n w O % 35.71 64.29 p i h s r e n w O % 50.00 50.00 13.60 86.40 25.00 75.00 33.33 66.67 50.00 50.00 50.00 50.00 26.00 74.00 25.00 75.00 25.00 75.00 37.50 62.50 50.00 50.00 50.00 50.00 50.00 50.00 25.00 75.00 33.33 66.67 50.00 50.00 29.25 70.75 38.00 62.00 49.00 51.00 ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018 274 e m a n y n a p m o C e c ffi o d e r e t s i g e R Liberty National Development Co Llc Wilmington Mediterranean Gas Co Mellitah Oil & Gas BV(†) Nile Delta Oil Co Nidoco Norpipe Terminal Holdco Ltd North Bardawil Petroleum Co North El Burg Petroleum Co Petrobel Belayim Petroleum Co(†) PetroBicentenario SA(†) PetroJunín SA(†) PetroSucre SA Pharaonic Petroleum Co Point Resources FPSO Holding AS Point Resources FPSO AS PR Jotun DA Port Said Petroleum Co(†) Raml Petroleum Co Ras Qattara Petroleum Co Rovuma Basin LNG Land Limitada(†) Shorouk Petroleum Company Société Centrale Electrique du Congo SA Société Italo Tunisienne d’Exploitation Pétrolière SA(†) Sodeps - Société de Developpement et d’Exploitation du Permis du Sud SA(†) Tapco Petrol Boru Hatti Sanayi ve Ticaret AS(†) (in liquidation) Tecninco Engineering Contractors Llp(†) Thekah Petroleum Co (in liquidation) United Gas Derivatives Co VIC CBM Ltd(†) Virginia Indonesia Co CBM Ltd(†) (USA) Cairo (Egypt) Amsterdam (Netherlands) Cairo (Egypt) London (United Kingdom) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Caracas (Venezuela) Caracas (Venezuela) Caracas (Venezuela) Cairo (Egypt) Sandnes (Norway) Sandnes (Norway) Sandnes (Norway) Cairo (Egypt) Cairo (Egypt) Cairo (Egypt) Maputo (Mozambique) Cairo (Egypt) Pointe-Noire (Republic of the Congo) Tunisi (Tunisia) Tunisi (Tunisia) Istanbul (Turkey) Aksai (Kazakhstan) Cairo (Egypt) Cairo (Egypt) London (United Kingdom) London (United Kingdom) n o i t a r e p o f o y r t n u o C USA Egypt Libya Egypt Norway Egypt Egypt Egypt Venezuela Venezuela Venezuela Egypt Norway y c n e r r u C USD EGP EUR EGP GBP EGP EGP EGP VES VES VES EGP NOK o i t a r y t i u q E % l a t i p a C e r a h S s r e d l o h e r a h S 0(a) Eni Oil & Gas Inc Third parties 20,000 Ieoc Production BV Third parties 20,000 Eni North Africa BV Third parties 20,000 Ieoc Production BV Third parties 55.69 Eni SpA Third parties 20,000 Ieoc Exploration BV Third parties 20,000 Ieoc SpA Third parties 20,000 Ieoc Production BV Third parties 3,790 Eni Lasmo Plc Third parties 24,021 Eni Lasmo Plc Third parties 2,203 Eni Venezuela BV Third parties 20,000 Ieoc Production BV Third parties 60,000 Vår Energi AS p i h s r e n w O % 32.50 67.50 25.00 75.00 50.00 50.00 37.50 62.50 14.20 85.80 30.00 70.00 25.00 75.00 50.00 50.00 40.00 60.00 40.00 60.00 26.00 74.00 25.00 75.00 100.00 Norway NOK 150,100,000 PR FPSO Holding AS 100.00 Norway Egypt Egypt Egypt NOK EGP EGP EGP Mozambique MZN Egypt Republic of the Congo Tunisia Tunisia Turkey EGP XAF TND TND TRY 0(a) PR FPSO AS PR FPSO Holding AS 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 20,000 Ieoc Production BV Third parties 140,000 Mozambique Rovuma Venture SpA Third parties 20,000 Ieoc Production BV Third parties 44,732,000,000 Eni Congo SA Third parties 5,000,000 Eni Tunisia BV Third parties 100,000 Eni Tunisia BV Third parties 9,850,000 Eni International BV Third parties Kazakhstan KZT 29,478,455 EniProgetti SpA Third parties Egypt Egypt EGP 20,000 Ieoc Exploration BV Third parties USD 153,000,000 Eni International BV Indonesia Indonesia USD USD Third parties 1,315,912 Eni Lasmo Plc Third parties 631,640 Eni Lasmo Plc Third parties 95.00 5.00 50.00 50.00 22.50 77.50 37.50 62.50 33.33 66.67 25.00 75.00 20.00 80.00 50.00 50.00 50.00 50.00 50.00 50.00 49.00 51.00 25.00 75.00 33.33 66.67 50.00 50.00 50.00 50.00 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. (a) Shares without nominal value. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. Co. Co. Co. Eq. Eq. Co. Co. Eq. Eq. Eq. Co. Co. Co. Co. Co. Co. Eq. Eq. Co. Co. Eq. Co. Eq. Eq. Eq. ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES 275 e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Vår Energi AS(†) (ex Eni Norge AS) West Ashrafi Petroleum Co(†) (in liquidation) Forus (Norway) Cairo (Egypt) Norway NOK 399,425,000 Eni International BV Third parties Egypt EGP 20,000 Ieoc Exploration BV Third parties o i t a r y t i u q E % p i h s r e n w O % 69.60 30.40 50.00 50.00 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. Co. Gas & Power IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Mariconsult SpA(†) Milan Società EniPower Ferrara Srl(†) Transmed SpA(†) San Donato Milanese (MI) Milan OUTSIDE ITALY e m a n y n a p m o C Angola LNG Supply Services Llc Blue Stream Pipeline Co BV(†) Gas Distribution Company of Thessaloniki-Thessaly SA(†) GreenStream BV(†) Premium Multiservices SA SAMCO Sagl e c ffi o d e r e t s i g e R Wilmington (USA) Amsterdam (Netherlands) Ampelokipi- Menemeni (Greece) Amsterdam (Netherlands) Tunisi (Tunisia) Lugano (Switzerland) n o i t a r e p o f o y r t n u o C Italy Italy Italy y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S EUR 120,000 EUR 140,000,000 EUR 240,000 Eni SpA Third parties EniPower SpA Third parties Eni SpA Third parties n o i t a r e p o f o y r t n u o C USA Russia y c n e r r u C USD USD l a t i p a C e r a h S s r e d l o h e r a h S 19,278,782 22,000 Greece EUR 247,127,605 Libya EUR 200,000,000 Tunisia TND 200,000 Switzerland CHF 20,000 Eni USA Gas M. Llc Third parties Eni International BV Third parties Eni gas e luce SpA Third parties Eni North Africa BV Third parties Sergaz SA Third parties Eni International BV Transmed. Pip. Co Ltd Third parties Eni SpA Third parties Eni SpA Third parties o i t a r y t i u q E % 51.00 o i t a r y t i u q E % 50.00 50.00 50.00 p i h s r e n w O % 50.00 50.00 51.00 49.00 50.00 50.00 p i h s r e n w O % 13.60 86.40 50.00 50.00 49.00 51.00 50.00 50.00 49.99 50.01 5.00 90.00 5.00 50.00 50.00 50.00 50.00 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. J.O. Eq. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. J.O. Eq. J.O. Eq. Eq. J.O. Eq. Transmediterranean Pipeline Co Ltd(†)(19) St. Helier (Jersey) Unión Fenosa Gas SA(†) Madrid (Spain) Jersey USD 10,310,000 Spain EUR 32,772,000 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. (19) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is subject to the Italian taxation. The company is considered as a controlled subsidiary as provided by article 167, paragraph 3, of the Italian Tax Consolidated Text. ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018 276 Refining & Marketing and Chemical Refining & Marketing IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Arezzo Gas SpA(†) Arezzo n o i t a r e p o f o y r t n u o C Italy y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m EUR 394,000 Eq. Eq. Co. J.O. Eq. Eq. J.O. Eq. J.O. Co. Eq. J.O. J.O. CePIM Centro Padano Interscambio Merci SpA Fontevivo (PR) Italy EUR 6,642,928.32 Consorzio Operatori GPL di Napoli Napoli Costiero Gas Livorno SpA(†) Livorno Italy Italy EUR 102,000 EUR 26,000,000 Disma SpA Segrate (MI) Italy EUR 2,600,000 Livorno LNG Terminal SpA Livorno Petroven Srl(†) Genova Porto Petroli di Genova SpA Genova Italy Italy Italy EUR EUR 200,000 156,000 EUR 2,068,000 Raffineria di Milazzo ScpA(†) Milazzo (ME) Italy EUR 171,143,000 Seram SpA Fiumicino (RM) Italy EUR 852,000 Sigea Sistema Integrato Genova Arquata SpA Genova Società Oleodotti Meridionali - SOM SpA(†) San Donato Milanese (MI) Italy Italy EUR 3,326,900 EUR 3,085,000 Eni Fuel SpA Third parties Ecofuel SpA Third parties Eni Fuel SpA Third parties Eni Fuel SpA Third parties Eni Fuel SpA Third parties Costiero Gas L. SpA Third parties Ecofuel SpA Third parties Ecofuel SpA Third parties Eni SpA Third parties Eni SpA Third parties Ecofuel SpA Third parties Eni SpA Third parties 50.00 50.00 44.78 55.22 25.00 75.00 65.00 35.00 25.00 75.00 50.00 50.00 68.00 32.00 40.50 59.50 50.00 50.00 25.00 75.00 35.00 65.00 70.00 30.00 65.00 68.00 50.00 70.00 Termica Milazzo Srl(†) Milazzo (ME) Italy EUR 100,000 Raff. Milazzo ScpA 100.00 50.00 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES 277 o i t a r y t i u q E % 20.00 n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. J.O. Eq. Co. Eq. Co. Co. Eq. Eq. Co. 50.00 J.O. Eq. Eq. OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S AET - Raffineriebeteiligungsgesellschaft mbH(†) Bayernoil Raffineriegesellschaft mbH(†) Schwedt (Germany) Vohburg (Germany) City Carburoil SA(†) Egyptian International Gas Technology Co ENEOS Italsing Pte Ltd FSH Flughafen Schwechat Hydranten-Gesellschaft OG Fuelling Aviation Services GIE Mediterranée Bitumes SA Routex BV Saraco SA Supermetanol CA(†) TBG Tanklager Betriebsgesellschaft GmbH(†) Weat Electronic Datenservice GmbH Rivera (Switzerland) Cairo (Egypt) Singapore (Singapore) Vienna (Austria) Tremblay en France (France) Tunisi (Tunisia) Amsterdam (Netherlands) Meyrin (Switzerland) Jose Puerto La Cruz (Venezuela) Salisburgo (Austria) Düsseldorf (Germany) Germany EUR 27,000 Germany EUR 10,226,000 Switzerland CHF 6,000,000 Egypt EGP 100,000,000 Singapore SGD 12,000,000 Austria EUR 7,798,020.99 France EUR 1 Tunisia TND 1,000,000 Netherlands EUR 67,500 Switzerland CHF 420,000 Venezuela VES 120.867 Austria EUR 43,603.70 Germany EUR 409,034 Eni Deutsch. GmbH Third parties Eni Deutsch. GmbH Third parties Eni Suisse SA Third parties Eni International BV Third parties Eni International BV Third parties Eni Marketing A. GmbH Eni Mineralölh. GmbH Eni Austria GmbH Third parties Eni France Sàrl Third parties Eni International BV Third parties Eni International BV Third parties Eni Suisse SA Third parties Ecofuel SpA Supermetanol CA Third parties Eni Marketing A. GmbH Third parties Eni Deutsch. GmbH Third parties p i h s r e n w O % 33.33 66.67 20.00 80.00 49.91 50.09 40.00 60.00 22.50 77.50 14.56 14.56 14.56 56.32 25.00 75.00 34.00 66.00 20.00 80.00 20.00 80.00 (a) 34.51 30.07 35.42 50.00 50.00 20.00 80.00 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. (a) Controlling interest: Ecofuel SpA 50.00 Third parties 50.00 ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018 278 Chemical IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Brindisi Servizi Generali Scarl Brindisi n o i t a r e p o f o y r t n u o C Italy y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m EUR 1,549,060 49.00 20.20 8.90 21.90 19.74 11.58 10.70 57.98 50.00 50.00 80.00 20.00 25.00 75.00 33.11 4.61 62.28 42.13 30.37 1.85 25.65 48.44 38.39 13.17 p i h s r e n w O % 50.00 50.00 80.00 20.00 o i t a r y t i u q E % Eq. Eq. Eq. Eq. Eq. Eq. Eq. Eq. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. Eq. IFM Ferrara ScpA Ferrara Italy EUR 5,270,466 Matrìca SpA(†) Newco Tech SpA(†) (in liquidation) Novamont SpA Priolo Servizi ScpA Porto Torres (SS) Novara Novara Melilli (SR) Italy Italy Italy Italy EUR 37,500,000 EUR 179,000 Versalis SpA Genomatica Inc EUR 13,333,500 EUR 28,100,000 Ravenna Servizi Industriali ScpA Ravenna Italy EUR 5,597,400 Servizi Porto Marghera Scarl Porto Marghera (VE) Italy EUR 8,695,718 Versalis SpA Syndial SpA EniPower SpA Third parties Versalis SpA Syndial SpA S.E.F. Srl Third parties Versalis SpA Third parties Versalis SpA Third parties Versalis SpA Syndial SpA Third parties Versalis SpA EniPower SpA Ecofuel SpA Third parties Versalis SpA Syndial SpA Third parties OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Lotte Versalis Elastomers Co Ltd(†) Versalis Zeal Ltd(†) Yeosu (South Korea) Takoradi (Ghana) South Korea KRW 301,800,000,000 Ghana GHS 5,650,000 Versalis SpA Third parties Versalis International SA Third parties (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (†) Jointly controlled entity. ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES 279 o i t a r y t i u q E % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Eq. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Co. Eq. Eq. Corporate and other activities Corporate and financial companies OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Commonwealth Fusion Systems Llc Wilmington (USA) n o i t a r e p o f o y r t n u o C USA y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % USD 148,291,710.38 Eni Next Llc Third parties 35.72 66.28 Corporate e Altre attività Other activities IN ITALY e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S Ferrandina (MT) Italy EUR 4,644,000 Nuoro San Donato Milanese (MI) Italy Italy EUR 516,000 EUR 2,191,384,693 Syndial SpA Third parties Syndial SpA Third parties Eni SpA Saipem SpA Third parties p i h s r e n w O % (a) 59.56 40.44 30.00 70.00 30.54 1.46 68.00 (b) e m a n y n a p m o C Filatura Tessile Nazionale Italiana - FILTENI SpA (in liquidation) Ottana Sviluppo ScpA (in liquidation) Saipem SpA(#)(†) OUTSIDE ITALY e m a n y n a p m o C Grid Edge (Private) Ltd(†) e c ffi o d e r e t s i g e R Saddar Town - Karachi (Pakistan) n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % o i t a r y t i u q E % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Pakistan PKR 1,200,000 Eni International BV Third parties 40.00 60.00 Eq. (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (#) Company with shares quoted in the regulated market of Italy or of other EU countries. (†) Jointly controlled entity. (a) Controlling interest: Syndial SpA (b) Controlling interest: Eni SpA 48.00 Third parties 52.00 30.99 Third parties 69.01 ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018 280 ■ OTHER SIGNIFICANT INVESTMENTS Exploration & Production IN ITALY e m a n y n a p m o C Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Pisa e c ffi o d e r e t s i g e R Administradora del Golfo de Paria Este SA Brass LNG Ltd Darwin LNG Pty Ltd New Liberty Residential Co Llc Nigeria LNG Ltd North Caspian Operating Co NV OPCO - Sociedade Operacional Angola LNG SA Petrolera Güiria SA SOMG - Sociedade de Operações e Manutenção de Gasodutos SA Torsina Oil Co Caracas (Venezuela) Lagos (Nigeria) West Perth (Australia) West Trenton (USA) Port Harcourt (Nigeria) Amsterdam (Netherlands) Luanda (Angola) Caracas (Venezuela) Luanda (Angola) Cairo (Egypt) l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m 135,000 Eni SpA Third parties 25.00 75.00 F.V. n o i t a r e p o f o y r t n u o C Italy n o i t a r e p o f o y r t n u o C Venezuela Nigeria y c n e r r u C EUR y c n e r r u C VES USD Angola Venezuela Angola Egitto AOA VES AOA EGP Australia AUD 530,060,381.89 Eni G&P LNG Aus. BV Third parties USA USD 0(a) Eni Oil & Gas Inc Third parties Nigeria USD 1,138,207,000 Kazakhstan EUR 128,520 l a t i p a C e r a h S s r e d l o h e r a h S 0.001 1,000,000 Eni Venezuela BV Third parties Eni Int. NA NV Sàrl Third parties Eni Int. NA NV Sàrl Third parties Agip Caspian Sea BV Third parties Eni Angola Prod. BV Third parties 7,400,000 10 Eni Venezuela BV Third parties 7,400,000 Eni Angola Prod. BV Third parties 20,000 Ieoc Production BV Third parties n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. p i h s r e n w O % 19.50 80.50 20.48 79.52 10.99 89.01 17.50 82.50 10.40 89.60 16.81 83.19 13.60 86.40 19.50 80.50 13.60 86.40 12.50 87.50 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Shares without nominal value. ANNEX TO FINANCIAL STATEMENTS | OTHER SIGNIFICANT INVESTMENTS 281 Gas & Power OUTSIDE ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R n o i t a r e p o f o y r t n u o C y c n e r r u C l a t i p a C e r a h S s r e d l o h e r a h S p i h s r e n w O % n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m Norsea Gas GmbH Emden (Germany) Germany EUR 1,533,875.64 Eni International BV Third parties 13.04 86.96 F.V. Refining & Marketing e Chimica Refining & Marketing IN ITALY e m a n y n a p m o C e c ffi o d e r e t s i g e R Consorzio Nazionale per la Gestione Raccolta e Trattamento degli Oli Minerali Usati Società Italiana Oleodotti di Gaeta SpA(14) Rome Rome OUTSIDE ITALY e m a n y n a p m o C BFS Berlin Fuelling Services GbR Compania de Economia Mixta “Austrogas” Dépôt Pétrolier de Fos SA Dépôt Pétrolier de la Côte d’Azur SAS Joint Inspection Group Ltd Saudi European Petrochemical Company ‘IBN ZAHR’ S.I.P.G. Société Immobilier Pétrolier de Gestion Snc Sistema Integrado de Gestion de Aceites Usados Tanklager - Gesellschaft Tegel (TGT) GbR TAR - Tankanlage Ruemlang AG Tema Lube Oil Co Ltd e c ffi o d e r e t s i g e R Hamburg (Germany) Cuenca (Ecuador) Fos-Sur-Mer (France) Nanterre (France) London (United Kingdom) Al Jubail (Saudi Arabia) Tremblay en France (France) Madrid (Spain) Hamburg (Germany) Ruemlang (Switzerland) Accra (Ghana) n o i t a r e p o f o y r t n u o C Italy Italy n o i t a r e p o f o y r t n u o C Germany Ecuador France France United Kingdom Saudi Arabia France Spain Germany y c n e r r u C EUR ITL y c n e r r u C EUR USD EUR EUR GBP SAR EUR EUR EUR l a t i p a C e r a h S s r e d l o h e r a h S 36,149 360,000,000 Eni SpA Third parties Eni SpA Third parties l a t i p a C e r a h S s r e d l o h e r a h S 89,199 3,028,749 3,954,196.40 207,500 0(a) 1,200,000,000 40,000 175,713 4,953 Eni Deutsch. GmbH Third parties Eni Ecuador SA Third parties Eni France Sàrl Third parties Eni France Sàrl Third parties Eni SpA Third parties Ecofuel SpA Third parties Eni France Sàrl Third parties Eni Iberia SLU Third parties Eni Deutsch. GmbH Third parties Eni Suisse SA Third parties Eni International BV Third parties n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.V. F.V. n o i t a d i l o s n o C n o i t a t u l a v r o ) * ( d o h t e m F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. F.V. p i h s r e n w O % 12.43 87.57 72.48 27.52 p i h s r e n w O % 12.50 87.50 13.31 86.69 16.81 83.19 18.00 82.00 12.50 87.50 10.00 90.00 12.50 87.50 15.44 84.56 12.50 87.50 16.27 83.73 12.00 88.00 Switzerland CHF 3,259,500 Ghana GHS 258,309 (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Shares without nominal value. (14) Company under extraordinary administration procedure pursuant to law No. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development. ANNEX TO FINANCIAL STATEMENTS | OTHER SIGNIFICANT INVESTMENTSEni Annual Report 2018 282 ■ CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2018 Fully consolidated subsidiaries COMPANIES INCLUDED (NO. 10) Arm Wind Llp Eni East Ganal Ltd Eni Lebanon BV Eni Next Llc Eni Rovuma Basin BV Eni Sharjah BV Astana London Other activities Acquisition Exploration & Production Constitution Amsterdam Exploration & Production Relevancy Houston Corporate and financial companies Constitution Amsterdam Exploration & Production Relevancy Amsterdam Exploration & Production Constitution Gas Supply Company Thessaloniki-Thessalia SA Thessaloniki Gas & Power Acquisition of the control Mestni Plinovodi distribucija plina doo Koper Gas & Power Acquisition Versalis Singapore Pte Ltd Singapore Chemical Relevancy Windirect BV Amsterdam Other activities Acquisition COMPANIES EXCLUDED (NO. 10) Eni Bulungan BV Eni Croatia BV Amsterdam Exploration & Production Irrelevancy Amsterdam Exploration & Production Sale Sale Eni Trinidad and Tobago Ltd Port of Spain Exploration & Production Eni Engineering E&P Ltd Eni Liverpool Bay Operating Co Ltd Liverpool Bay Ltd Mestni Plinovodi distribucija plina doo Eni Norge AS London London London Koper Forus Exploration & Production Cancellation Exploration & Production Irrelevancy Exploration & Production Irrelevancy Gas & Power Merger Exploration & Production Loss of control Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság Hajdúszoboszló Gas & Power Tigáz-Dso Földgázelosztó kft Hajdúszoboszló Gas & Power Sale Sale (*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value. (a) Shares without nominal value. (14) Company under extraordinary administration procedure pursuant to law No. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development. ANNEX TO FINANCIAL STATEMENTS | CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2018Eni SpA Headquarters Piazzale Enrico Mattei, 1 - Rome - Italy Capital Stock as of December 31, 2018: € 4,005,358,876.00 fully paid Tax identification number 00484960588 Branches Via Emilia, 1 - San Donato Milanese (Milan) - Italy Piazza Ezio Vanoni, 1 - San Donato Milanese (Milan) - Italy Publications Relazione Finanziaria Annuale pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 (in Italian) Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Fact Book (in Italian and English) Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 (in Italian and English) Corporate Governance Report pursuant to rule 123-bis of Legislative Decree No. 58/1998 (in Italian and English) Remuneration Report pursuant to rule 123-ter of Legislative Decree No. 58/1998 (in Italian and English) ENI IN 2018 – Summary Annual Review (in English) ENI FOR 2018 – Sustainability Report (in Italian and English) Internet home page www.eni.com Rome office telephone +39-0659821 Toll-free number 800940924 e-mail segreteriasocietaria.azionisti@eni.com Investor Relations Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com Layout and supervision K-Change - Rome Printing Varigrafica Alto Lazio – Viterbo - Italy

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