Equinor ASA – Annual report – 31 December 2021
Industry: oil and gas
2 Significant accounting policies (extract)
Key sources of estimation uncertainty
The preparation of the Consolidated financial statements requires that management makes estimates and assumptions that affect reported amounts of assets, liabilities, income and expenses. The estimates are prepared based on tailormade models, while the assumptions on which the estimates are based rely on historical experience, external sources of information and various other factors that management assesses to be reasonable under the current conditions and circumstances. These estimates and assumptions form the basis of making the judgements about carrying values of assets and liabilities when these are not readily apparent from other sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an on-going basis considering the current and expected future set of conditions.
Equinor is exposed to a number of underlying economic factors which affect the overall results, such as liquids prices, natural gas prices, refining margins, foreign currency exchange rates, market risk premiums and interest rates as well as financial instruments with fair values derived from changes in these factors. In addition, Equinor’s results are influenced by the level of production, which in the short term may be influenced by, for instance, maintenance programmes. In the long-term, the results are impacted by the success of exploration, field development and operating activities.
The most important matters in understanding the key sources of estimation uncertainty that are involved in preparing these Consolidated financial statements are disclosed in the following under each paragraph, where relevant.
Estimation uncertainty from initiatives to limit climate changes and the energy transition
The effects of the initiatives to limit climate changes and the potential impact of the energy transition are relevant to some of the economic assumptions in our estimations of future cash flow. The results the development of such initiatives may have in the future, and the degree Equinor’s operations will be affected by them, are sources of uncertainty. Estimating global energy demand and commodity prices towards 2050 is a challenging task, assessing the future development in supply and demand, technology change, taxation, tax on emissions, production limits and other important factors. The assumptions may change which could materialise in different outcomes from the current projected scenarios. This could result in significant changes to accounting estimates, such as economic useful life (affects depreciation period and timing of asset retirement obligations) and value-in-use calculations (affects impairment assessments). See note 3 Consequences of initiatives to limit climate changes for more details.
3 Consequences of initiatives to limit climate changes
Equinor’s ambitions and our strategy
Climate change and reaching the goals set out in the Paris Agreement represent fundamental challenges to society. As outlined in the COP26 Glasgow Climate Pact, achieving the most ambitious goals of the Paris Agreement now requires rapid, deep and sustained reductions in global greenhouse gas emissions. This includes reducing global carbon dioxide emissions by 45% by 2030 relative to 2010 levels, and to net zero around mid-century. Equinor’s ambition is to be a leading company in the energy transition and to become a net-zero company by 2050, including emissions from production through to final energy consumption. Equinor’s strategy is to create value as a leader in the energy transition by pursuing high-value growth in renewables and new markets opportunities in low carbon solutions at the same time as it optimises its oil and gas portfolio.
Assessment of risks arising from climate change and the energy transition
Climate changes and a transition to a lower carbon economy will affect Equinor’s business and entails a broad range of different risk factors. Equinor’s climate roadmap and all of our climate-related ambitions are a response to these challenges and risks related to climate change.
- Market and technology risks. A transition to a low carbon economy contributes to uncertainty over future demand and prices for oil and gas. Increased demand for and improved cost competitiveness of renewable energy, and innovation and technology changes supporting the further development and use of renewable energy and low-carbon technologies, represent both threats and opportunities for Equinor.
- Physical risks. Changes in physical climate parameters could impact Equinor through increased costs or incidents affecting Equinor’s operations. Examples of physical parameters that could impact Equinor’s facility design and operations include acute effects like increasing frequency and severity of extreme weather events, and chronic effects like rising sea level, changes in sea currents and reduced water availability. Unexpected changes in meteorological parameters, such as average wind speed, can also affect renewable power generation outputs, resulting in performance above or below expectations.
- Regulatory risk. Equinor expects, and is preparing for, regulatory changes and policy measures targeted at reducing greenhouse gas emissions, such as changes in carbon costs and taxes, emission standards or energy subsidy policies. Stricter climate regulations and policies could impact Equinor’s financial outlook, including the value of assets, access to acreage, or indirectly through changes in consumer behaviour or technology developments.
- Reputational and litigation risk. Increased concern over climate change could lead to increased expectations on fossil fuel producers, as well as a more negative perception of the oil and gas industry. This could lead to increased litigation-related costs and poor reputation could affect Equinor’s license to operate as well as the ability to attract and retain talent and key competences.
- Risk of diminished access to financing. Strong competition for assets may lead to diminishing returns within the renewable and low carbon industries and hamper the transition into a broader energy company. Competitive auctions/tenders where prices don’t allow absorption of higher costs may increase the exposure to inflation risk. This is also relevant for assets where the costs and income have been locked in before the final investment decision. There is also a risk of increased cost of capital for fossil fuel producers. Certain lenders have recently indicated that they will direct or restrict their lending activities based on environmental parameters.
Effects on estimation uncertainty
The effects of the initiatives to limit climate changes and the potential impact of the energy transition are relevant to some of the economic assumptions in our estimations of future cash flows. The results of the development of such initiatives, and the degree to which Equinor’s operations will be affected by them, are sources of uncertainty. Estimating global energy demand and commodity prices towards 2050 is a challenging task, as this comprises assessing the future development in supply and demand, technology change, taxation, tax on emissions, production limits and other important factors. The assumptions may change, which could materialise in different outcomes from the current projected scenarios. This could result in significant changes to accounting estimates, such as economic useful life (affects depreciation period and timing of asset retirement obligations) and value-in-use calculations (affects impairment assessments).
Equinor’s commodity price assumptions applied in value-in-use impairment testing, are set in accordance with accounting regulations and based on management’s best estimate of the development of relevant current circumstances and the likely future development of such circumstances. This price-set is currently not equal to a price-set required to achieve the goals in the Paris Agreement as described in the WEO Sustainability Development Scenario, or the Net Zero Emissions by 2050 Scenario. A future change in the trajectory of how the world acts with regards to implementing actions in accordance with the goals in the Paris agreement could, depending on the detailed characteristics of such a trajectory, have a negative impact on the valuation of Equinor’s property, plant and equipment in total. A calculation of a possible effect of using the prices (including CO2 prices) in a 1.5oC compatible Net Zero Emission by 2050 Scenario as estimated by the International Energy Agency (IEA) could result in an impairment of around USD 7 billion before tax. This illustrative impairment sensitivity is based on a simplified model and limitations further described in note 11 Property, plant & equipment.
Equinor expects greenhouse gas emission costs to increase from current levels and to have a wider geographical range than today. A global tax on CO2 emissions will have a negative impact on the valuation of Equinor’s oil and gas assets, but this risk is mitigated by Equinor’s internal carbon price applied to all potential new projects and investments, currently set at 58 USD/tonne and increasing towards 100 USD/tonne by the year 2030 and stays flat thereafter. As such, climate considerations are a part of the investment decisions following Equinor’s strategy and commitments to the energy transition.
Climate considerations are included in the impairment calculations directly by estimating the CO2 taxes in the cash flows. Indirectly, the expected effect of climate change is also included in the estimated commodity prices where supply and demand are considered. The CO2 prices also have effect on the estimated production profiles and economic cut-off of the projects.
Impairment calculations are based on best estimate assumptions. To reflect that carbon will have a cost for all our assets, the current best estimate is considered to be EU ETS for countries outside EU where carbon is not already subject to taxation or where Equinor has not established specific estimates. The EU ETS price has increased significantly from 56 EUR/tonne in 2020 and is expected to remain high, in the region of 80 EUR/tonne for the next couple of years. Then the price is expected to be 65 EUR/tonne (27.5 EUR/tonne) in 2030 and thereafter increasing to 100 EUR/tonne (41 EUR/tonne) in 2050 (assumptions used in 2020 in brackets). Norway’s Climate Action Plan for the period 2021-2030 (Meld. St 13 (2020-2021)) which assumes a gradually increased CO2 tax (the total of EU ETS + Norwegian CO2 tax) in Norway to 2,000 NOK/tonne in 2030 is used for impairment calculations of Norwegian upstream assets.
Total expensed CO2 cost related to emissions and purchase of CO2 quotas for the companies Equinor ASA and Equinor Energy AS related to activities on the Norwegian Continental Shelf (Equinor’s share of the operating licences) and land-based operating facilities in Norway owned by Equinor amounts to USD 428 million in 2021, and USD 268 million in 2020.
Upstream oil & gas (stranded assets)
The transition to renewable energy, technological development and reduction in global demand for carbon-based energy, may have a negative impact on the future profitability of investments in upstream oil and gas assets, in particular assets with long estimated useful lives, projects in an early development phase and undeveloped assets controlled by Equinor. Equinor seeks to mitigate this risk by focusing on improving the resilience of the existing upstream portfolio, maximising the efficiency of our infrastructure on the Norwegian Continental Shelf and optimising our high-quality international portfolio. Equinor will also continue to selectively explore for new resources with a focus on mature areas that can make use of existing infrastructure to minimise emissions and maximise value. During the transition, Equinor will allocate less of our capital budget to oil and gas in the coming years and eventually decrease the volume of production over time. Equinor’s plans to become a net-zero company by 2050 have not resulted in the identification of additional assets being triggered for impairment or earlier cessation of production as of year-end 2021.
Any future exploration may be restricted by regulations, market and strategic considerations. Provided that the economic assumptions would deteriorate to such an extent that undeveloped assets controlled by Equinor should not materialize, assets at risk mainly comprise the intangible assets Oil and Gas prospects, signature bonuses and the capitalised exploration costs, with a total carrying value of USD 4.6 billion. See note 12 Intangible assets for more information regarding Equinor’s intangible assets.
Timing of Asset Retirement Obligations (ARO)
If the business cases of Equinor’s oil and gas producing assets should change materially from governmental initiatives to limit climate change, this could affect the timing of our asset retirement obligations. A shorter production period, accelerating the time for when assets need to be removed after ended production, will increase the carrying value of the liability. The effect of performing removal five years earlier than currently scheduled, is estimated to increase the liability by USD 0.2 billion. See note 21 Provisions and other liabilities for more information regarding Equinor’s ARO.
2 Significant accounting policies (extract 2)
Impairment of property, plant and equipment, right-of-use assets and intangible assets including goodwill
Equinor assesses individual assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Assets are grouped into cash generating units (CGUs) which are the smallest identifiable groups of assets that generate cash inflows that are largely independent of the cash inflows from other groups of assets. Normally, separate CGUs are individual oil and gas fields or plants. Each unconventional asset play is considered a single CGU when no cash inflows from parts of the play can be reliably identified as being largely independent of the cash inflows from other parts of the play. In impairment evaluations, the carrying amounts of CGUs are determined on a basis consistent with that of the recoverable amount. In Equinor’s line of business, judgement is involved in determining what constitutes a CGU. Development in production, infrastructure solutions, markets, product pricing, management actions and other factors may over time lead to changes in CGUs such as the disaggregation of one original CGU into several.
In assessing whether a write-down of the carrying amount of a potentially impaired asset is required, the asset’s carrying amount is compared to the recoverable amount. The recoverable amount of an asset is the higher of its fair value less cost of disposal or its value in use. Fair value less cost of disposal is determined based on comparable recent arm’s length market transactions or based on Equinor’s estimate of the price that would be received for the asset in an orderly transaction between market participants. Such fair value estimates are mainly based on discounted cash flow models, using assumed market participants’ assumptions, but may also reflect market multiples observed from comparable market transactions or independent third-party valuations. Value in use is determined using a discounted cash flow model. The estimated future cash flows applied in establishing value in use are based on reasonable and supportable assumptions and represent management’s best estimates of the range of economic conditions that will exist over the remaining useful life of the assets, as set down in Equinor’s most recently approved long-term forecasts. Assumptions and economic conditions in establishing the long-term forecasts are reviewed by management on a regular basis and updated at least annually. See note 11 Property, plant and equipment for a presentation of the most recently updated commodity price assumptions. For assets and CGUs with an expected useful life or timeline for production of expected oil and natural gas reserves extending beyond five years, including planned onshore production from shale assets with a long development and production horizon, the forecasts reflect expected production volumes, and the related cash flows include project or asset specific estimates reflecting the relevant period. Such estimates are established based on Equinor’s principles and assumptions and are consistently applied.
In performing a value-in-use-based impairment test, the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate which is based on Equinor’s post-tax weighted average cost of capital (WACC). Country risk specific to a project is included as a monetary adjustment to the projects’ cash flow. Equinor regards country risk primarily as an unsystematic risk. The cash flow is adjusted for risk that influence the expected cash flow of a project and which is not part of the project itself. The use of post-tax discount rates in determining value in use does not result in a materially different determination of the need for, or the amount of, impairment that would be required if pre-tax discount rates had been used.
Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset or CGU to which the unproved properties belong may exceed its recoverable amount, and at least once a year. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether major capital expenditure can be justified or where the economic viability of that major capital expenditure depends on the successful completion of further exploration work, will remain capitalised during the evaluation phase for the exploratory finds. Thereafter it will be considered a trigger for impairment evaluation of the well if no development decision is planned for in the near future and there are no firm plans for future drilling in the licence.
An assessment is made at each reporting date as to whether there is any indication that previously recognised impairment losses may no longer be relevant or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years.
Impairment losses and reversals of impairment losses are presented in the Consolidated statement of income as Exploration expenses or Depreciation, amortisation and net impairment losses, on the basis of their nature as either exploration assets (intangible exploration assets) or development and producing assets (property, plant and equipment and other intangible assets), respectively.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. Impairment is determined by assessing the recoverable amount of the CGU, or group of units, to which the goodwill relates. Where the recoverable amount of the CGU, or group of units, is less than the carrying amount, an impairment loss is recognised. When impairment testing goodwill originally recognised as an offsetting item to the computed deferred tax provision in a post-tax transaction on the NCS, the remaining amount of the deferred tax provision will factor into the impairment evaluations. Once recognised, impairments of goodwill are not reversed in future periods.
Estimation uncertainty regarding impairment
Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired, requiring its carrying amount to be written down to its recoverable amount. Impairments are reversed if conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgement and may to a large extent depend upon the selection of key assumptions about the future.
The key assumptions used will bear the risk of change based on the inherent volatile nature of macro-economic factors such as future commodity prices or discount rate and uncertainty in asset specific factors such as reserve estimates and operational decisions impacting the production profile or activity levels for our oil and natural gas properties. Changes in foreign currency exchange rates will also affect value-in-use, especially for NCS-assets, where the functional currency is NOK. When estimating the recoverable amount, the expected cash flow approach is applied to reflect uncertainties in timing and amounts inherent in the assumptions used in the estimated future cash flows, including climate-related matters affecting those assumptions. For example, climate-related matters (see also Note 3 Consequences of initiatives to limit climate changes) are expected to have a pervasive effect on the energy industry, affecting not only supply, demand and commodity prices, but also technology-changes, increased emission-related levies and other matters with mainly mid-term and long-term effects. These effects have been factored into the price assumptions used for estimating future cash flows using probability-weighted scenario analyses.
Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the relevant asset or CGU may exceed its recoverable amount, and at least annually. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. Subsequent to the initial evaluation phase for a well, it will be considered a trigger for impairment testing of a well if no development decision is planned for the near future and there is no firm plan for future drilling in the licence. Impairment of unsuccessful wells is reversed, as applicable, to the extent that conditions for impairment are no longer present.
Where recoverable amounts are based on estimated future cash flows, reflecting Equinor’s, market participants’ and other external sources’ assumptions about the future and discounted to their present value, the estimates involve complexity. Impairment testing requires long-term assumptions to be made concerning a number of economic factors such as future market prices, refinery margins, foreign currency exchange rates and future output, discount rates, impact of the timing of tax incentive regulations, and political and country risk among others, in order to establish relevant future cash flows. Long-term assumptions for major economic factors are made at a group level, and there is a high degree of reasoned judgement involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs and in determining the ultimate terminal value of an asset.
Oil and gas exploration, evaluation and development expenditures
Equinor uses the successful efforts method of accounting for oil and gas exploration costs. Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration and evaluation expenditures within intangible assets until the well is complete and the results have been evaluated, or there is any other indicator of a potential impairment. Exploration wells that discover potentially economic quantities of oil and natural gas remain capitalised as intangible assets during the evaluation phase of the discovery. This evaluation is normally finalised within one year after well completion. If, following the evaluation, the exploratory well has not found potentially commercial quantities of hydrocarbons, the previously capitalised costs are evaluated for derecognition or tested for impairment. Geological and geophysical costs and other exploration and evaluation expenditures are expensed as incurred.
Capitalised exploration and evaluation expenditures, including expenditures to acquire mineral interests in oil and gas properties related to offshore wells that find proved reserves, are transferred from Exploration expenditures and Acquisition costs – oil and gas prospects (Intangible assets) to Property, plant and equipment at the time of sanctioning of the development project. The timing from evaluation of a discovery until a project is sanctioned could take several years depending on the location and maturity, including existing infrastructure, of the area of discovery, whether a host government agreement is in place, the complexity of the project and the financial robustness of the project. For onshore wells where no sanction is required, the transfer from Exploration expenditures and Acquisition cost – oil and gas prospects (Intangible assets) to Property, plant and equipment occurs at the time when a well is ready for production.
For exploration and evaluation asset acquisitions (farm-in arrangements) in which Equinor has made arrangements to fund a portion of the selling partner’s exploration and/or future development expenditures (carried interests), these expenditures are reflected in the Consolidated financial statements as and when the exploration and development work progresses. Equinor reflects exploration and evaluation asset dispositions (farm-out arrangements) on a historical cost basis with no gain or loss recognition.
A gain related to a post-tax-based disposition of assets on the NCS includes the release of tax liabilities previously computed and recognised related to the assets in question. The resulting after-tax gain is recognised in full in Other income in the Consolidated statement of income.
Consideration from the sale of an undeveloped part of an onshore asset reduces the carrying amount of the asset. The part of the consideration that exceeds the carrying amount of the asset, if any, is reflected in the Consolidated statement of income under Other income.
Even exchanges (swaps) of exploration and evaluation assets with only immaterial cash considerations are accounted for at the carrying amounts of the assets given up with no gain or loss recognition.
Accounting judgement and estimation uncertainty regarding exploration activities
Equinor capitalises the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. Equinor also capitalises leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgements as to whether these expenditures should remain capitalised, be de-recognised or written down in the period may materially affect the carrying values of these assets and consequently, the operating income for the period.
Property, plant and equipment
Property, plant and equipment is reflected at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of an asset retirement obligation, if any, exploration costs transferred from intangible assets and, for qualifying assets, borrowing costs. Proceeds from production ahead of a project’s final approval are regarded as ‘early production’ and is recognised as revenue rather than as a reduction of acquisition cost. Contingent consideration included in the acquisition of an asset or group of similar assets is initially measured at its fair value, with later changes in fair value other than due to the passage of time reflected in the book value of the asset or group of assets, unless the asset is impaired. Property, plant and equipment include costs relating to expenditures incurred under the terms of PSAs in certain countries, and which qualify for recognition as assets of Equinor. State-owned entities in the respective countries, however, normally hold the legal title to such PSA-based property, plant and equipment.
Exchanges of assets are measured at fair value, primarily of the asset given up, unless the fair value of neither the asset received, nor the asset given up is measurable with sufficient reliability.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits associated with the item will flow to Equinor, the expenditure is capitalised. Inspection and overhaul costs, associated with regularly scheduled major maintenance programmes planned and carried out at recurring intervals exceeding one year, are capitalised and amortised over the period to the next scheduled inspection and overhaul. All other maintenance costs are expensed as incurred.
Capitalised exploration and evaluation expenditures, development expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of production wells, and field-dedicated transport systems for oil and gas are capitalised as Producing oil and gas properties within Property, plant and equipment. Such capitalised costs, when designed for significantly larger volumes than the reserves from already developed and producing wells, are depreciated using the unit of production method based on proved reserves expected to be recovered from the area during the concession or contract period. Depreciation of production wells uses the unit of production method based on proved developed reserves, and capitalised acquisition costs of proved properties are depreciated using the unit of production method based on total proved reserves. In the rare circumstances where the use of proved reserves fails to provide an appropriate basis reflecting the pattern in which the asset’s future economic benefits are expected to be consumed, a more appropriate reserve estimate is used. Depreciation of other assets and transport systems used by several fields is calculated on the basis of their estimated useful lives, normally using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For exploration and production assets, Equinor has established separate depreciation categories which as a minimum distinguish between platforms, pipelines and wells.
The estimated useful lives of property, plant and equipment are reviewed on an annual basis, and changes in useful lives are accounted for prospectively. An item of property, plant and equipment is de-recognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in Other income or Operating expenses, respectively, in the period the item is derecognised.
Monetary or non-monetary grants from governments, when related to property, plant and equipment and considered reasonably certain, are recognised in the Consolidated balance sheet as a deduction to the carrying value of the asset and subsequently recognised in the Consolidated statement of income over the life of the depreciable asset as a reduced depreciation expense.
Estimation uncertainty regarding determining oil and gas reserves
Reserves estimates are complex and based on a high degree of professional judgement involving geological and engineering assessments of in-place hydrocarbon volumes, the production, historical recovery and processing yield factors and installed plant operating capacity. Recoverable oil and gas quantities are always uncertain. The reliability of these estimates at any point in time depends on both the quality and availability of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Reserves quantities are, by definition, discovered, remaining, recoverable and economic.
Estimation uncertainty; Proved oil and gas reserves
Proved oil and gas reserves may impact the carrying amounts of oil and gas producing assets, as changes in the proved reserves, for instance as a result of changes in prices, will impact the unit of production rates used for depreciation and amortisation. 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. Unless evidence indicates that renewal is reasonably certain, estimates of proved reserves only reflect the period before the contracts providing the right to operate expire. For future development projects, proved reserves estimates are included only where there is a significant commitment to project funding and execution and when relevant governmental and regulatory approvals have been secured or are reasonably certain to be secured.
Proved reserves are divided into proved developed and proved undeveloped reserves. Proved developed reserves are to be recovered through existing wells with existing equipment and operating methods, or where the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major capital expenditure is required for recompletion. Undrilled well locations can be classified as having proved undeveloped reserves if a development plan is in place indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time horizon. Specific circumstances are for instance fields which have large up-front investments in offshore infrastructure, such as many fields on the NCS, where drilling of wells is scheduled to continue for much longer than five years. For unconventional reservoirs where continued drilling of new wells is a major part of the investments, such as the US onshore assets, the proved reserves are always limited to proved well locations scheduled to be drilled within five years.
Proved oil and gas reserves have been estimated by internal qualified professionals on the basis of industry standards and are governed by the oil and gas rules and disclosure requirements in the U.S. Securities and Exchange Commission (SEC) regulations S-K and S-X, and the Financial Accounting Standards Board (FASB) requirements for supplemental oil and gas disclosures. The estimates have been based on a 12-month average product price and on existing economic conditions and operating methods as required, and recovery of the estimated quantities have a high degree of certainty (at least a 90% probability). An independent third party has evaluated Equinor’s proved reserves estimates, and the results of this evaluation do not differ materially from Equinor’s estimates.
Estimation uncertainty; Expected oil and gas reserves
Changes in the expected oil and gas reserves, for instance as a result of changes in prices, may materially impact the amounts of asset retirement obligations, as a consequence of timing of the removal activities. It may also impact value-in-use calculations for oil and gas assets, possibly also affecting impairment testing and the recognition of deferred tax assets. Expected oil and gas reserves are the estimated remaining, commercially recoverable quantities, based on Equinor’s judgement of future economic conditions, from projects in operation or decided for development. Recoverable oil and gas quantities are always uncertain. As per Equinor’s internal guidelines, expected reserves are defined as the ‘forward looking mean reserves’ when based on a stochastic prediction approach. In some cases, a deterministic prediction method is used, in which case the expected reserves are the deterministic base case or best estimate. Expected reserves are therefore typically larger than proved reserves as defined by the SEC, which are high confidence estimates with at least a 90% probability of recovery when a probabilistic approach is used. Expected oil and gas reserves have been estimated by internal qualified professionals on the basis of industry standards and classified in accordance with the Norwegian resource classification system issued by the Norwegian Petroleum Directorate.
Asset retirement obligations (ARO)
Provisions for ARO costs are recognised when Equinor has an obligation (legal or constructive) to dismantle and remove a facility or an item of property, plant and equipment and to restore the site on which it is located, and when a reliable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditures determined in accordance with local conditions and requirements. The cost is estimated based on current regulations and technology, considering relevant risks and uncertainties. The discount rate used in the calculation of the ARO is a risk-free rate based on the applicable currency and time horizon of the underlying cash flows. To better represent the risks specific to the ARO liability, and as described in a previous paragraph regarding changes in accounting policies, Equinor no longer includes a credit premium reflecting Equinor’s own credit risk. Normally an obligation arises for a new facility, such as an oil and natural gas production or transportation facility, upon construction or installation. An obligation may also arise during the period of operation of a facility through a change in legislation or through a decision to terminate operations or be based on commitments associated with Equinor’s ongoing use of pipeline transport systems where removal obligations rest with the volume shippers. The provisions are classified under Provisions in the Consolidated balance sheet.
When a provision for ARO cost is recognised, a corresponding amount is recognised to increase the related property, plant and equipment and is subsequently depreciated as part of the costs of the facility or item of property, plant and equipment. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment. When a decrease in the ARO provision related to a producing asset exceeds the carrying amount of the asset, the excess is recognised as a reduction of Depreciation, amortisation and net impairment losses in the Consolidated statement of income. When an asset has reached the end of its useful life, all subsequent changes to the ARO provision are recognised as they occur in Operating expenses in the Consolidated statement of income. Removal provisions associated with Equinor’s role as shipper of volumes through third party transport systems are expensed as incurred.
Estimation uncertainty regarding asset retirement obligations
Establishing the appropriate estimates for such obligations are based on historical knowledge combined with knowledge of ongoing technological developments and involve the application of judgement and involve an inherent risk of significant adjustments. The costs of decommissioning and removal activities require revisions due to changes in current regulations and technology while considering relevant risks and uncertainties. Most of the removal activities are many years into the future, and the removal technology and costs are constantly changing. The speed of the transition to new renewable energy may also influence the timing of the production period, hence the timing of the removal activities. The estimates include assumptions of norms, rates and time required which can vary considerably depending on the assumed removal complexity. Moreover, changes in the discount rate and foreign currency exchange rates may impact the estimates significantly. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgement.
Estimation uncertainty regarding the Covid-19 pandemic
During 2020, the Covid-19 pandemic slowed economic growth and had dramatic consequences for energy demand, particularly mobility fuels, resulting in a collapse in commodity prices in the first half of 2020. Commodity prices rebounded through the second half of 2020 and have since the first quarter of 2021 surpassed pre-pandemic levels. When setting Equinor’s estimates for global supply, demand and commodity prices, management factored in the effects of global roll-out of vaccines during 2021 and 2022. Virus mutation is still causing new waves of lockdown and other restrictions, but the Omicron variant seems less dangerous, letting governments ease restrictions as former variants are being outcompeted. Even though we expect to see the end of the pandemic in the near future, there is always inherent uncertainties and a risk of new virus flareups for as long as the virus is allowed to mutate. The outlook is still somewhat uncertain and dominated by downside risks such as virus infection flare-ups, and we expect that continued global vaccination and the scope of monetary and fiscal governmental stimuli will still affect the economy in the short term. As such, the full resulting operational and economic impact for Equinor from the pandemic cannot be fully ascertained at this time.
Apart from the financial impact, Equinor has only experienced immaterial effects on production from assets in operation, due to actions taken to maintain and secure safe production during the pandemic. Minor virus outbreaks at some of our facilities have occurred, but effective measures such as isolation and quarantines combined with social distancing and increased sanitation requirements have prevented production shutdown, and operations have not been significantly impacted.
For projects under development, the Covid-19 pandemic has impacted progress due to personnel limitations on offshore and onshore facilities / yards due to infection control measures and associated travel restrictions for migrant workforce. The situation is to a certain degree still unpredictable and may have additional consequences for the progress and costs of our projects.
11 Property, plant and equipment (extract)
Net impairments/(reversal) of impairments
1) Producing and development assets, refining and manufacturing plants, goodwill and other intangible assets are subject to impairment assessment under IAS 36. The total net impairment losses recognised under IAS 36 in 2021 amount to USD 1.285 billion, compared to 2020 when the net impairment amounted to USD 6.401 billion, including impairment of acquisition costs – oil and gas prospects (intangible assets).
2) Acquisition costs related to exploration activities, subject to impairment assessment under the successful efforts method (IFRS 6).
3) See note 12 Intangible assets.
For impairment purposes, the asset’s carrying amount is compared to its recoverable amount. The recoverable amount is the higher of fair value less cost of disposal (FVLCOD) and estimated value in use (VIU).
The base discount rate for VIU calculations is 5.0% real after tax. The discount rate is derived from Equinor’s weighted average cost of capital. For projects, mainly within the REN segment, in periods with fixed low risk income a lower discount rate will be considered. A derived pre-tax discount is in the range of 18-32% for E&P Norway, 5-9% for E&P International, 6-7% for E&P USA and 7% for MMP depending on asset specific characteristics, such as specific tax treatments, cash flow profiles and economic life. See note 2 Significant accounting policies to the Consolidated financial statements for further information regarding impairment on property, plant and equipment.
The table below describes, per area, the Producing and development assets being impaired/(reversed) and the valuation method used to determine the recoverable amount; the net impairment/(reversal), and the carrying amount after impairment.
Exploration & Production Norway
In 2021, the impairment reversals were USD 1.102 billion, caused by increased price estimates and upward reserve revision. In 2020, the impairments were USD 1.219 billion, mainly because of reduction in future price estimates. Negative reserve revisions and increased cost estimates added to the impairment losses.
Exploration & Production USA – onshore
In 2021, the net impairment was USD 48 million of which net reversal of USD 2 million was classified as exploration expenses. The impairments were USD 108 million of which USD 20 million classified as exploration expensed were caused by downward reserve revision and sale of an asset. The reversal of USD 60 million of which USD 22 million was classified as exploration expenses was caused by upward reserve revision.
In 2020, the net impairment was USD 2.313 billion of which USD 0.680 billion was classified as exploration expenses. The impairment losses of USD 2.547 billion of which USD 0.743 billion classified as exploration expenses, were caused by decreased price assumptions and a change to fair value less cost of disposal valuation in relation to held for sale classification. The impairment reversals of USD 0.234 billion in 2020 were caused by improved production profile.
Exploration & Production USA – offshore Gulf of Mexico
In 2021, the impairment was USD 18 million caused by downward reserve revision.
In 2020, the impairments were USD 305 million caused by decreased price assumptions.
Exploration & Production International – North America offshore other areas
In 2021, the impairment reversal was USD 22 million related to sale of an asset.
In 2020, the impairment was USD 146 million due to operational issues.
Exploration & Production International – Europe and Asia
In 2021, the net impairment was USD 1.609 billion. Impairments were USD 1.786 billion mainly caused by downward reserve revisions. The reversal of USD 0.177 billion was caused by higher prices
In 2020, the impairments were USD 1.280 billion due to decreased price assumptions and negative reserve revisions.
Marketing, Midstream & Processing
In 2021, the impairment losses were USD 716 million mainly caused by increased CO2 fees and – quotas on a refinery and change to fair value less cost of disposal valuation in connection with a held for sale classification.
In 2020, the impairment losses were USD 1.052 billion mainly due to reduced refinery margin estimates and increased cost estimates. Reduced volume-estimates from processing added to the impairment loss.
Management’s future commodity price assumptions and currency assumptions are used for value in use impairment testing. The same assumptions are also used for evaluating investment opportunities, together with other relevant criteria, including among others robustness targets (value creation in lower commodity price scenarios). While there are inherent uncertainties in the assumptions, the commodity price assumptions as well as currency assumptions reflect management’s best estimate of the price and currency development over the life of the Group’s assets based on its view of relevant current circumstances and the likely future development of such circumstances, including energy demand development, energy and climate change policies as well as the speed of the energy transition, population and economic growth, geopolitical risks, technology and cost development and other factors. Management’s best estimate also takes into consideration a range of external forecasts.
Equinor has performed a thorough and broad analysis of the expected development in drivers for the different commodity markets and exchange rates. Significant uncertainty exists regarding future commodity price development due to the transition to a lower carbon economy, future supply actions by OPEC+ and other factors. The management’s analysis of the expected development in drivers for the different commodity markets and exchange rates resulted in changes in the long-term price assumptions with effect from the third quarter of 2021. The following price assumptions have been the basis for the impairment assessments.
All commodity prices are on a real 2021 basis, and comparable prices as per the fourth quarter of 2020 and up to the third quarter of 2021 are given in brackets.
For Brent blend, Equinor expects a price of 65 USD/bbl in 2025 (67 USD/bbl) then gradually an increase to a peak in 2030 before declining to 64 USD/bbl in 2040 (66 USD/bbl), and further down to below 60 USD/bbl in the 2050s. Price assumptions from 2025 are unchanged compared to year-end 2020, with the exception that the real year has been changed from 2020 to 2021.
For natural gas in the UK (NBP), we expect some volatility, where the trend is a decrease to 6.4 USD/mmbtu in 2030 (6.7 USD/mmbtu). From 2030, a flatter price-curve is expected, with the price gradually increasing to 7.7 USD/mmbtu in 2040 (8.0 USD/mmbtu). Beyond 2040, a declining price trend is foreseen as the energy transition is expected to impact the demand side. For 2050, the price is expected to be at the pre-2035 level of 7.0 USD/mmbtu (7.7 USD/mmbtu).
Henry Hub is expected to decrease to 3.2 USD/mmBtu in 2030 (3.3 USD/mmbtu) and 3.3 USD/mmbtu in 2040 (3.8 USD/mmbtu), a level that is expected to continue through the 2040s.
The electricity prices are expected to increase significantly in the future. Due to the increasing gas and CO2 prices the electricity prices in Germany are by the end of fourth quarter expected to be 157 EUR/MWh in 2022 (61 EUR/MWh), the expectation for 2022 by the end of the third quarter was 77 EUR/MWh. In 2030 the prices are expected to be 58 EUR/MWh (43 EUR/MWh) and then rather flat towards 2050.
Climate considerations are included in the impairment calculations directly by estimating the CO2 taxes in the cash flows. Indirectly, the expected effect of climate change is also included in the estimated commodity prices where supply and demand are considered. The prices also have effect on the estimated production profiles and economic cut-off of the projects. Furthermore, climate considerations are a part of the investment decisions following Equinor’s strategy and commitments to the energy transition.
The EU ETS price has increased significantly from 56 EUR/tonne since the third quarter assessment and is expected to remain high, in the region of 80 EUR/tonne for the next few years. Then the price is expected to be 65 EUR/tonne (27.5 EUR/tonne) in 2030 and thereafter increasing to 100 EUR/tonne (41 EUR/tonne) in 2050 (assumptions used in 2020 in brackets). Norway’s Climate Action Plan for the period 2021-2030 (Meld. St 13 (2020-2021)) which assumes a gradually increased CO2 tax (the total of EU ETS + Norwegian CO2 tax) in Norway to 2,000 NOK/tonne in 2030 is used for impairment calculations of Norwegian upstream assets.
Impairment calculations are based on what is considered to be best estimate. To reflect that carbon will have a cost for all our assets the current best estimate is considered to be EU ETS for countries outside EU where carbon is not already subject to taxation or where Equinor has not established specific estimates.
The long-term NOK currency exchange rates are expected to be unchanged. The NOK/USD rate from 2024 and onwards is kept at 8.50, the NOK/EUR at 10.0 and the USD/GBP rate at 1.35.
The Weighted Average Cost of Capital (WACC) rate is 5%. This rate is basically the interest rate used for upstream activities. For other business areas the discount rate will be determined based on a risk assessment. Typically, the rate will decrease for assets/projects where the revenue is secured by fixed fees or government grants.
Commodity prices have historically been volatile. Significant downward adjustments of Equinor’s commodity price assumptions would result in impairment losses on certain producing and development assets in Equinor’s portfolio including intangible assets that are subject to impairment assessment, while an opposite adjustment could lead to impairment-reversals. If a decline in commodity price forecasts over the lifetime of the assets were 30%, considered to represent a reasonably possible change, the impairment amount to be recognised could illustratively be in the region of USD 9 billion before tax effects. See note 3 Consequences of initiatives to limit climate changes for possible effect of using the prices in a 1.5oC compatible Net Zero Emission by 2050 scenario as estimated by the International Energy Agency (IEA)
These illustrative impairment sensitivities, both based on a simplified method, assumes no changes to input factors other than prices; however, a price reduction of 30% or those representing Net Zero Emission scenario is likely to result in changes in business plans as well as other factors used when estimating an asset’s recoverable amount. These associated changes reduce the stand-alone impact on the price sensitivities. Changes in such input factors would likely include a reduction in the cost level in the oil and gas industry as well as offsetting foreign currency effects, both of which have historically occurred following significant changes in commodity prices. The illustrative sensitivities are therefore not considered to represent a best estimate of an expected impairment impact, nor an estimated impact on revenues or operating income in such a scenario. In comparison, following the amended assumptions described above in the accounting assumptions section and the decline in commodity prices, the impairment impact recognised is considerably lower. A significant and prolonged reduction in oil and gas prices would also result in mitigating actions by Equinor and its licence partners, as a reduction of oil and gas prices would impact drilling plans and production profiles for new and existing assets. Quantifying such impacts is considered impracticable, as it requires detailed technical, geological and economical evaluations based on hypothetical scenarios and not based on existing business or development plans.