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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, 2021
Impairment review of tangible and intangible assets and right-of-use assets |
Impairment review of tangible and intangible assets and right-of-use assets | 15 Impairment review of tangible and intangible assets and right-of-use assets The impairment test assumptions of the Plenitude & Power operating segment are disclosed in note 14 - Intangible assets. The recoverability test of carrying amounts of oil&gas cash genenerating units (CGUs) is the most important of the critical accounting estimates in the preparation of Eni’s consolidated financial statements. This owes to the relative weight of the invested capital in the oil&gas sector with respect to the total consolidated assets and to the complexity of thee estimation process of the values-in-use (VIUs) of oil&gas CGUs. Future expected cash flows associated with the use of oil&gas assets are based on management’s judgment and subjective evaluation about highly uncertain matters like future, long-term hydrocarbons prices, assets’ useful lives, projections of future operating and capital expenditures, the volumes of reserves that will ultimately be recovered and costs of decommissioning oil&gas assets at the end of their useful lives. Among all these variables, future hydrocarbons prices are the main value driver and because we are in a commodity business, they tend to be very volatile and unpredictable due both to the number of driving forces underlying long-term trends in demands and supplies of hydrocarbons, and to the trend of financial markets. Forecasts of hydrocarbons prices adopted by Eni’s management for the purpose of evaluating both oil&gas assets recoverability and of making final investment decisions are estimated on the basis of management’s view of a number of fundamental trends, namely the expected evolution of the global energy mix in the next twenty-to-thirty years in line with the decarbonization goals of countries as agreed at COP 21 in Paris in 2015 and reaffirmed at the Glasgow COP 26 conference last year, the pace of the energy transition, the enduring impacts of the COVID-19 pandemic, technology developments, long-term trends in demand and supplies of hydrocarbons, global macroeconomic and demographic growth, the evolution of technologies and climate policies, together with the evolution in consumers’ and investors' preferences. In the short term, Eni’s hydrocarbons forecasts also consider market forward prices of crude oil and natural gas, as well as projections made by investment banks and other market observatories. Eni recognizes and fully endorses the transition of the economy towards a low-carbon development model and the goals of the Paris COP21 agreements and based on this has designed a strategy to achieve the decarbonization of the Company’s products and industrial processes targeting net zero emissions in Scope 1+2+3 by 2050. Consistently with this long-term path which is factoring possible trends in markets, technologies and a gradual evolution in the Company’s products, management is assuming a long-term price of the Brent crude oil benchmark of 62 $/barrel in 2020 USD until the year 2035 and then a declining trend to 46 $/barrel in 2050 due to the expected phase-out of crude oil from the global energy mix in view of achieving the goals of the Paris agreement. In the year 2022-2023, management is projecting nominal prices of 80 $ and 75 $/barrel, respectively, considering a strong macroeconomic cycle, financial discipline and consequent limitation of investments by listed oil companies and production issues in countries of the OPEC+ alliance. The corresponding pricing assumptions in the 2020 financial statements were 55 $ and 60 $/barrel. Regarding natural gas future prices, while in the short-to-medium term the benchmark price for spot sales at the Euroepan continental hub “TTF” is forecast to strengthen considerably due to tight supplies at 21.2 $ and 14.4 $/mmBTU in 2022 and 2023, respectively (in the 2020 financial statements the corresponding projections were 4.7 $ and 4.9 $/mmBTU), in the long-term management expects a decline due to the assumption of increasing competition from renewable energies and consumption efficiency for a TTF price forecast of 8.5 $/mmBTU in real currency 2020 in the period 2025-2045 and a further decline to 6.2 $/mmBTU in 2050. Short-term forecasts are exposed to the unpredictable consequences of the ongoing conflict between Russia and Ukraine, which up to date has caused an unprecedented phase of volatility in the energy commodity market. The post-tax, discount rate of future expected cash flows associated with the use of oil&gas CGUs was estimated based on the weighted average cost of equity (Ke) and of financial debt, in line with the methodology recommended by the capital asset pricing model. The cost of equity considers a market risk premium measured on the basis of the long-term returns of the S&P 500 and an additional premium which was estimated by management to discount the operational risks of the countries of activity and the risks of the energy transition. As a result of these assumptions, our cost of equity is estimated at about 10%, counterbalancing a decline in yields of risk-free assets, which are incorporated both in the cost of equity and in cost of the financial debt. Overall, our risk-adjusted weighted average cost of capital (adjusted WACC) was about 7% in 2021. In 2021, management has recognized reversals at previously impaired oil&gas CGUs driven by strengthened hydrocarbons prices, particularly gas prices. The main amounts regarded gas fields in Italy and fields in Congo, Libya, USA, Algeria, Turkmenistan, Nigeria and East Timor. The post-tax, risk-adjusted WACC that were used in the impairment review ranged between 10.7% and 6.5%. In the case of a reversal higher than €100 million, a risk-adjusted post-tax WACC of 6.8% was used, which redetermines to about 18% pre-tax. The VIU of the whole portfolio of oil&gas CGUs estimated under management’s pricing and other operating assumptions shows a headroom greater than 90% of the underlying book values, also discounting the expected expenses associated with the purchase of carbon credits as part of the Company’s strategy to decarbonize its products/processes through the participation to forestry conservation projects, which belong to the REDD+ framework defined by the United Nations. The calculation included all the assets of consolidated companies, joint ventures and associates excluding Vår Energi AS and an asset under arbitration procedure. Considering the level of judgment in the estimation process of the VIUs of oil&gas assets, management has prepared a stress-test analysis utilizing alternative decarbonization scenario as adopted by the IEA in its SDS WEO ’21 and net zero emissions 2050 (NZE 2050) scenarios. The sensitivity tests to the IEA SDS and NZE 2050 scenario consider energy commodity pricing assumptions different from those adopted by the management and the utilization of a cost for carbon emissions across all geographic areas where Eni operates its oil & gas activities based on the prices reported in the following table: ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Value in use of the O&G CGUs | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Headroom vs Carrying amounts | ​ | Assumption at 2050 in real terms USD 2020
​ | ​ | tax-deductible | ​ | non tax-deductible | ​ | ​ | ​ | European gas | ​ | ​
​ |  | CO2 charges |  | CO2 charges |  | Brent price |  | price |  | Cost of CO2
Eni's scenario |  | ~90 | % | — | ​ | 46 $/bbl |  | 6.2 $/mmBTU |  | CO2 costs projections in the EU/ETS + projections of forestry costs
IEA SDS WEO 2021 scenario |  | 76 | % | 75 | % | 50 $/bbl |  | 4.5 $/mmBTU |  | 200/95 per tonne of CO2 (*)
IEA NZE 2050 scenario |  | 35 | % | 32 | % | 24 $/bbl |  | 3.6 $/mmBTU |  | 250/55 per tonne of CO2 (*)
​ (*) Prices relating to advanced/emerging economies In relation to the NZE 2050 scenario, for which possible value recovery actions are not considered, such as rescheduling/cancellation of planned development activities, contractual renegotiations, effect on costs or actions aimed at accelerating the pay-back period, a headroom is determined, that is, the excess of the total value-in-use compared to the corresponding book value of the E&P CGU, consistent and in excess of more than 30% compared to the book value. The 2021 valuation of the recoverability of the assets also resulted in the write-down of the residual book value of the refineries and the joint operations in Italy and Europe for an amount of €1,179 million (including the stay-in-business investments of the CGUs previously impaired). The driver of this loss is the significant decline in margins, compressed by the worsening of crack spreads for the products and the increase in the cost of gas-indexed utilities, and the reduced profitability prospects of Eni's CGUs due to structural weaknesses in the European refining sector (suboptimal size of the plants and competitive pressure from more efficient refiners) and the projections of limited recovery in the demand for fuels also due to competition from electric mobility. In addition, operating costs are penalized by the increase in charges for the purchase of emission certificates under the European Emission Trading System scheme.

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