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Reversals (Impairments) of tangible and intangible assets and right-of-use assets | 12 Months Ended
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Dec. 31, 2022
Reversals (Impairments) of tangible and intangible assets and right-of-use assets |
Reversals (Impairments) of tangible and intangible assets and right-of-use assets | 15 Reversals (I mpairment s) of tangible and intangible assets and right-of-use assets. Sensitivity of outcomes to alternative scenarios. 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 sector on total consolidated assets. 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 hydrocarbons prices, assets’ useful lives, projections of future operating and capital expenditures, including CO 2 emission costs relating to geographies where legal obligations are present, the volumes of reserves that will ultimately be recovered and costs of decommissioning oil&gas assets at the end of their useful lives. Forecasts of hydrocarbons prices adopted by Eni are based on the review of the fundamentals of supply and demand in the long term, considering the possible evolution of the global energy mix by 2050 in relation to the decarbonisation commitments of the countries and the EU in view of the achievement of the goals of the Paris Agreement, the pace of the energy transition, global economic and demographic growth, the evolution of technologies and the evolution in consumers’ preferences. These assumptions are reflected in the corporate strategies and investment decisions, as well as being used in recoverability assessments of the carrying amount of oil&gas projects. In the short term, market forward prices are also considered 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 carbon neutrality by 2050. Consistent with this long-term path and with the progressive evolution of the Company's product portfolio, management is assuming a mid-cycle scenario for the price of the Brent crude oil and other price benchmarks, which assumes a balance between global supply and demand, a moderation in economic growth and inflationary pressures and a gradual reduction in the consumption of crude oil in view of achieving the goals of the Paris agreement. The forecast prices of the mid-cycle scenario represent management's best estimate and form the basis for investment decisions, operational plans and recoverability tests of Eni's oil & gas assets. Below are the main price assumptions for assessing the recoverability of oil & g as assets, expressed in 2021 real terms.
| 2023 |  |  | 2025 |  |  | 2030 |  |  | 2040 |  |  | 2050 |
Brent $/bbl | 73 |  |  | 63 |  |  | 62 |  |  | 53 |  |  | 43 |
TTF natural gas price $mmBtu | 23.5 |  |  | 13.5 |  |  | 6.0 |  |  | 6.0 |  |  | 5.3 |
This scenario does not differ significantly from the one adopted in the previous report ing year. The discount rate of the future cash flows of the CGUs was estimated as the weighted average cost of equity (Ke) and net borrowings, based on the Capital Asset Pricing Model methodology. Specifically, the cost of equity considers both a premium for the non-diversifiable market risk measured on the basis of the long-term returns of the S&P500, and an additional premium that considers exposure to operational risks of the countries of activity and the risks of the energy transition. For 2022, a Group cost of capital “WACC” of approximately 7% was estimated unchanged compared to 2021 due to a lower cost of equity as a consequence of the reduction in the company's financial risk as a result of the deleveraging process carried out, which offset the increased yields on risk-free assets. The Group WACC is adjusted to account for the specific operational risks of each geography against the average portfolio, where oil&gas activities are conducted, by adding a corrective factor (WACC adjusted on a country-by-country basis). The impairment test was performed at all of the Group’s oil&gas CGUs based on the price scenario of the management and the country WACCs described above, which substantially confirmed the carrying amounts of the properties, with the exception of few assets which were marked to their lower recoverable values due to downward reserves revisions and costs updates, recognizing €432 million of net impairment losses. The impaired assets were mainly located in Congo, Egypt, USA and Algeria, in this latter case due to the release of a concession. Furthermore, a residual goodwill amount was written-off in UK. The post-tax discount rates were comprised in a 6.2% - 11.1% range. The value in use (VIU) of the oil&gas CGUs under the management’s scenario assumptions displayed a headroom (difference between VIU and book values) of approximately 100% of the assets’ carrying amounts, also discounting the expected expenses associated with the purchase of carbon credits as part of the Company’s strategy to decarbonize its oil&gas operations through participation in forestry conservation projects, which belong to the REDD+ framework defined by the United Nations. Considering the subjectivity of the assumptions underlying the estimates of the VIU, management has elaborated the following sensitivity analyses ​​of the oil&gas CGUs values to different scenarios: (i) a linear cut of -10% of hydrocarbon prices in all the years of the cash flows projections; (ii) the projections of hydrocarbon prices and CO2 costs of the decarbonization scenario Net Zero Emission 2050 (NZE 2050) elaborated by IEA. Those sensitivity analysis included assets of all consolidated entities, joint ventures and associates, excluding Vår Energi ASA, Azule Energy Holdings Ltd and an asset under arbitration procedure. The results of the sensitivity test in terms of changes in the cumulated headroom of oil&gas CGUs and potential pre-tax income statement impacts are provided below:
| Value in use of the O&G CGUs Headroom vs Carrying amounts |  |  | Assumption at 2050 in real terms USD 2021 |
| tax-deductible CO2 charges |  |  | non tax-deductible CO2 charges |  |  | Brent price |  |  | European gas price |  |  | Cost of CO2 |
Eni's scenario | >100 | % |  | - |  |  | 43 $/bbl |  |  | 5.3 $/mmBTU |  |  | CO2 costs projections in the EU/ETS + projections of forestry costs |
10% haircut of Eni's prices assumptions | 80 | % |  | - |  |  | 39 $/bbl |  |  | 4.8 $/mmBTU |  |  | CO2 costs projections in the EU/ETS + projections of forestry costs |
IEA NZE 2050 scenario | 55 | % |  | 49 | % |  | 24 $/bbl |  |  | 3.8 $/mmBTU |  |  | 250-180 $ per tonne of CO2 (*) |
(*) Prices relating to advanced/emerging economies |
Sensitivity - 10% to Eni prices assumptions |  |
(€ billion) |  | Sensitivity |
Exploration & Production assets |  | (0.7 | )
Hydrocarbon prices and CO2 costs of the IEA NZE 2050 scenario |  |
(€ billion) |  | Sensitivity |
|  | Tax-deductible CO2 charges |  |  | Non tax-deductible CO2 charges |
Exploration & Production assets |  | (2.1 | ) |  | (2.8 | )
These sensitivities do not consider possible actions to mitigate a changed price environment, such as rescheduling and/or cancellation of planned development activities, contractual renegotiations, costs efficiencies or actions aimed at accelerating the pay-back period. The sensitivity was not applied to the Chemical business and to the gas-fired power generation business considering the immateriality of the residual book values of property, plant and equipment ​​(€595 million and €690 million, respectively) and of economic-technical lives, while no impact can be associated for refineries considering that their book values have been completely impaired in past reporting periods.

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