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Impairment review of tangible and intangible assets and right-of-use assets | 12 Months Ended
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Dec. 31, 2019
Impairment review of tangible and intangible assets and right-of-use assets |
Impairment review of tangible and intangible assets and right-of-use assets | 14 Impairment review of tangible and intangible assets and right-of-use 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. Impairment losses of goodwill cannot be reversed. 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, the CGUs to which goodwill arisen from business combinations was allocated and costs for customer acquisition (Italian retail market and other foreign markets), electric power plants, international pipelines and other minor activities; (iii) in the Refining & Marketing business line, refining plants, and assets related to distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) in the Chemical business five lines of activities have been identified as autonomous CGUs: intermediates, polyethylene, styrenes, elastomers and biotech activities. As of 2019, following the application of IFRS 16, the book values of the identified CGUs include the right of use assets (RoU), associated to plants and equipment hired in connection with operations at specific CGUs operations. Because they are instrumental to specific CGUs operation, those RoU assets lack the requisites to be evaluated as autonomous CGUs. The CGUs’ cash flows to which the RoUs have been allocated exclude lease liability repayments according to the unlevered valuation methodology used for capital projects. Rather, a small number of RoU not allocated to CGU are considered corporate assets, whose recoverability depends on the whole of the company’s CGUs. 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, reserves, 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 considering the expected production rates and the associated projections of operating costs and development expenditures. The CGUs of Refining & Marketing, Chemical and Gas & Power, with a definite useful life, (i.e. 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%. In the forecast of the operating expenses are considered expected costs to be incurred in compliance to the so-called CO2 Emission Trading Scheme applicable to CGUs operating within the EU economic space. 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. The oil market continues to be affected by weak fundamentals against the backdrop of an unabated supply glut, fueled by continuing grow in U.S. tight oil output and a seemingly fading commitment on part of the oil producers of the OPEC+ agreement at supporting crude oil prices going forward. The market is also weighed down by uncertainties about the strength of the global economic recovery, exposed to a wide range of systemic risks, including geopolitical risks, any possible development in the trade dispute between USA and China, the relationship between the EU and the UK post Brexit. Eni’s management forecast a gradual rebalancing of global supplies and demand for crude oil over the medium term, under the assumptions of moderate economic growth and taking into account the stricter capital discipline adopted by major oil companies designed to curtail growth plans to boost shareholders’ returns and lately a shift in the financial approach retained by the U.S. independent producers which have de-emphasized growth to preserve the free cash flow. Based on these considerations and taking into account the forecasts made by specialized observatories and investment banks, management has retained its assumption of a long-term Brent crude oil price of 70$/BBL in real terms 2022, substantially in line with the assumption made in the annual report 2018. The oversupply condition is even more severe in the gas market due to excess production of associated gas in the USA and to the ramp-up of several liquefaction projects which have significantly increased global supplies of LNG at a time when the greatest consuming countries have slowed down (China, South Korea and Japan). Management expect gas prices to rebalance in the medium term considering an anticipated recovery of the Asian economies and also considering an ongoing switch from coal to gas in the power generation in Europe. Overall, price assumptions for the main gas benchmarks in Europe have been retained at the same level as the previous planning projections, whilst gas prices assumptions have been revised downward for the reference Henry Hub gas prices in USA due to structural headwinds. Having retained management’s long-term assumptions for crude oil prices unchanged from the previous financial statements, the impairment indicators at the Company’s oil&gas assets were mainly driven by downward reserves revisions and a lowered operating performance. Furthermore, management is forecasting unchanged spreads for natural gas between the selling prices at Eni’s reference market, Italy, and the spot prices at continental hub to which the gas procurement costs of our long-term contracts are indexed. This latter assumption excludes any evidence of impairment indicator in relation to the G&P fixed assets (particularly the goodwill recorded in the retail segment). The Company’s downstream businesses of the refining and the petrochemicals sectors are currently in a down-cycle due to weak end-demands, excess production capacity and oversupplies and continuing competitive pressures from overseas operators who can leverage better cost positions and scale economies (for example Middle East refiners and the ethane-based cracking of U.S. chemicals producers), while environmental issues are expected to negatively affect consumption and profitability of gasoil and single-use plastics. Operating costs for emission allowances as part of the European Emission Scheme are also forecast to increase. Furthermore, Eni’s complex refineries have been negatively affected by narrowing price differentials between sour crudes with high sulfur content and the light benchmark Brent crude, thus impairing the cost-advantage of complex refineries of processing low-quality crudes that under normal market conditions trade at a discount vs the Brent. Due to those structural weaknesses, management has reduced the profitability outlook of its refineries and petrochemicals plants. Management tested for impairment the totality of the Group’s fixed assets as provided by the Company’s internal guidelines. 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 specific 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 the 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. In 2019 the weighted-average cost of capital (WACC) to the Group increased marginally from 7.3% in 2018 to 7.4%. Based on our estimation the cost of equity has significantly appreciated driven by a sharp decline in government bond yields in 2019 that lifted the so-called equity risk premium, or the excess return for equities over a risk-free rate of return such as yields on treasuries of benchmark countries like USA and Germany and a step-up in the equity risk premium applied by financial markets to the oil&gas sector reflecting recent underperformance of the sector and uncertainties over future returns considering the structural decline in hydrocarbons prices and the risks associated with the energy transition. However, this impact has been mitigated by a higher leverage following the adoption of the accounting standard IFRS 16 which increased the total finance debt recorded in the balance sheet and by this way reduced the increase in the weighted average cost of capital to the Group due to the higher equity risk. Finally, a weighted-average premium for the country risk is added to the cost of equity; the weighting factor is the amount of invested capital in each country of operations. Calculation of country-specific WACC for each country is obtained by adjusting the Group WACC by the difference between the specific risk premium applicable to a given country and the average country risk premium of the Group portfolio. Based on those assumptions, the existence of impairment indicators and estimates of discount rates, management recorded the following net impairment losses: (i) in the Exploration & Production segment the Company recorded impairment losses before taxes for €1,217 million driven by downward reserve revisions and lowered future production rates mainly at properties in Congo (WACC at 7.6%), Italy (WACC at 6.4%) and USA (WACC at 6.5%), in this latter country upward estimates of operating costs and expenditures were projected, as well as a loss on the disposal of a property in Ecuador. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.4% was applied, corresponding to pre-tax rate of 6.9%; (ii) in the Refining & Marketing business line impairment losses of €819 million were recorded, with the largest amount relating to the Sannazzaro refinery for €684 million driven by the above mentioned revised profitability outlook and also in connection to higher projected costs for CO2 emissions; the remaining amount related to the investments of the year for compliance and stay-in-business made at CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.6% was applied, corresponding to pre-tax rate of 7.1%; (iii) in the Chemicals business impairment losses amounted to €103 million driven by the deteriorated market outlook described above; and (iv) in the G&P segment, €37 million of impairment losses were recorded at power generation plants in connection to a downward revision to the outlook for electricity margins due to higher competition and overcapacity. Furthermore, management assessed the recoverability of the expected costs associated with the Company’s plans to ramp up the participation in projects for forestry conservation and protection from degradation. Those projects which have been started in 2019 envisage the purchase of carbon credits certified in accordance with generally accepted international standards. Management projects to build in future years a portfolio of forestry projects intended to allow the Company to offset the net residual “Scope 1 and 2” carbon emissions of the E&P business calculated on equity production for the achievement of the carbon neutrality of the business from 2030 onwards. Those costs are considered part of the operating expenses of the E&P business and their recoverability has been evaluated in relation to the CGU E&P segment as a whole. When including those costs extrapolated along the reserves residual life in the determination of the value-in-use of the E&P segment, a 2% reduction in the headroom of the segment is observed. Ultimately, under management’s assumptions for a long-term Brent price at 70$/BBL (real terms 2022), which has remained unchanged for the last few years, and at a reference price for the Italian spot gas benchmark of 7.8$/Mbtu, Eni’s oil&gas properties have exhibited a substantial resilience of their carrying amounts, as highlighted by the trend in the recognition of impairment losses in the last three years. In 2017 we recorded a net reversal of €158 million and in 2018 we recorded net impairment losses of €726 million. Impairment losses in those three years have been driven mainly by asset-specific issues, which were acquired during a historic phase of suspected peak supply, and in relation to certain complex operating environments. However, considered the following trends of the sector: the increased volatility of crude oil prices which have been increasingly exposed to macro and global risks; the continued oversupply in the oil markets which has determined a reset in hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of the global oil demand in light of the rising commitment on part of the international community at fighting climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumers’ preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties at different stress-test scenarios, including the risk of stranded assets. Particularly, under the toughest of the assumptions at a flat long-term Brent price of 50$/BBL and at a flat Italian gas price of 5$/Mbtu, management is estimating that approximately 85% of the Company’s proven and probable/possible reserves (risked at 70% and 30% respectively) will be produced within 2035 realizing 94% of the overall net present value in the same period. The net present value of those production volumes, valued under the most conservative of the scenarios considered, is substantially aligned with the book values of the net fixed assets of Eni’s oil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in the calculation the expected cash outflows committed to the Company’s forestry projects.

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