Equinor ASA – Annual report – 31 December 2020
Industry: oil and gas
2 Significant accounting policies (extract)
Impairment of property, plant and equipment and intangible assets other than 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 and 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 10 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 recognized 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.
Impairment of goodwill
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.
Critical accounting judgements and key sources of estimation uncertainty (extract)
Key sources of estimation uncertainty (extracts)
Consequences of 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 components of some of the economic assumptions in our estimations of future cash flow, including for example commodities prices. The results the development of such initiatives may have in the future, and the degree Equinor operations will be affected by them are a source of uncertainty. The assumptions may change which could materialize 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 is transitioning towards becoming a broad energy company, ambitious to be a leading company in the energy transition needed to change the global energy mix for the world to reach the climate targets set out in the Paris Agreement. Estimating global energy demand towards 2050 is an extremely difficult task, assessing the future development in supply and demand, technology change, taxation, tax on emissions, production limits and other important factors, and Equinor’s long-term perspectives must be based on scenarios that span these outcomes, building on different plausible combinations of assumptions for where global energy markets may develop. These different scenarios are continually used as a backdrop when considering accounting estimates.
Equinor aims to be leading in the energy transition and has the ambition to become a net-zero energy company by 2050. However, despite a record drop in global emissions in 2020, the world is far from doing enough to achieve a decisive decline needed to achieve net-zero emissions by 2050 in support of the Paris Agreement. It is Equinor’s belief that in order to reach a scenario with less than a 2 degrees Celsius increase, global energy-related CO2-emissions must drop 4% on average every single year and by two thirds within 2050. This can only be reached by a combination of changing the energy mix from fossil fuels to renewable energy and slowing the economic growth in industrialised regions in favour of emerging regions where economic growth accelerate. A reprising of goods and services must provide incentives for wealthier countries to reduce waste and overconsumption. Equinor’s commodity price assumptions that are used for value-in-use impairment testing are set in accordance with accounting regulations that require such estimates to be based on management’s best estimate of the development of relevant current circumstances and the likely future development of such circumstances. This includes the energy demand development, energy and climate change policies as well as the speed of the energy transition, population and economic growth, geopolitical risk, technology and cost development and other factors. The best estimate price-set is currently not equal to a price-set in accordance with the achievements of the goals in the Paris Agreement as described in the WEO sustainability development scenerio. A future change in the trajectory of how the world acts with regards to implementing actions in accordance with a net-zero energy environment, supporting the goals in the Paris Agreement, could hence have a negative impact on the valuation of Equinor’s oil and gas assets. See note 10 Property, plant and equipment for an impairment sensitivity based on a price set considered in alignment with the goals in the Paris Agreement.
The Covid-19 pandemic
During 2020, the Covid-19 pandemic has slowed economic growth and had dramatic consequences for energy demand, particularly mobility fuels. The collapse in commodity prices seen in the first half of 2020, though followed by a partial rebound in the second half, significantly impacted the energy industry and Equinor by an unprecedented decrease in short term demand and increased uncertainty with regards to the phase of recovery and future oil and gas demand. The increasing momentum and commitment towards a transition into a low carbon future aided by technological advances and decreasing cost of renewable energy has also increased the uncertainty in estimating the future development in supply and demand. According to the International Energy Agency (IEA), Global energy demand in 2020 was estimated to drop by 5-6%. The OPEC+ agreement to continue production cuts of some 7 mmboe per day in the first quarter of 2021 to clear surpluses built up over the pandemic, has supported prices to levels not seen since January 2020. When setting Equinor’s estimates for global supply, demand and commodity prices, management has factored in the effects of global roll-out of vaccines during 2021, allowing an accelerated re-opening of the economy through the year. Even though we expect the cyclical economic upturn to continue into 2022 where GDP growth rates should normalise from the effects of the pandemic, we expect the global oil demand never to reach pre-pandemic levels. But second and third wave Covid-19 lockdowns which continue to dampen demand are likely to put a cap on prices in the short-term. We acknowledge that the speed and effect of global vaccination as well as the scope of monetary and fiscal governmental stimuli will affect the economy, the outlook is highly uncertain and dominated by downside risks such as virus infection flare-ups, high unemployment suppressing consumption and increasing public and private debt levels, and as such the full resulting operational and economic impact for Equinor 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 still unpredictable and may have additional consequences for the progress and costs of our projects.
Actions taken to mitigate the impact of the pandemic and commodity price decline, including the USD 3 billion action plan implemented in the spring of 2020, have had consequences on investment level and activity level in general. Capital expenditure has been reduced during 2020, representing both final reductions (stopped projects i.e. based on updated future price estimates and break-even levels) and changes with regards to scope and timing. As a result, some value creation has been cut or delayed. Part of cost improvements and cost cuts identified and implemented during 2020 as part of the action plan are expected to be of a sustainable nature and impact future cost levels. Cost related to activities postponed from 2020 due to the pandemic will impact cost when these activities are carried out.
Energy demand development and commodity prices
During 2020, Equinor has revised the future short- and long-term commodity price assumptions, and while Covid-19 has had a significant effect on the energy demand in 2020 and is expected to still have an effect on short term prices, the energy and climate change politics, population and economic growth, technology development and such other factors are expected to have a more pervasive effect on the energy demand development, energy mix development and commodity prices for oil and gas for decades to come. The revised assumptions have led to significant impairment of assets, and we refer to note 10 Property, plant and equipment for management’s best estimate of future commodity prices and the portfolio’s sensitivity to additional impairments for an additional decline of commodity prices of 30% over the lifetime of the assets. A 30% decline in commodity prices for the period up until 2050 represents management’s best estimate of a reasonably possible change, considering the beforementioned circumstances.
Oil and gas reserves estimates
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.
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.
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, and value-in-use calculations for oil and gas assets, possibly affecting impairment testing and also 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 is 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.
Exploration and leasehold acquisition costs
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.
Impairment/reversal of impairment
Equinor has significant investments in property, plant and equipment and intangible assets. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired, requiring it’s carrying amount to be written down to its recoverable amount. Impairments are reversed if conditions for impairment are no longer present. In certain circumstances, due to technological changes, as a result of the transition from fossil fuels to renewable energy to limit global warming or for other reasons causing a significant global drop in demand and commodity prices, there is a possible risk that certain investments in upstream production of fossil energy, especially those with a long time horizon, can be impaired to such a degree that production shuts down, never to commence – so-called “stranded assets”. Equinor does not have any stranded assets as of now. 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. The continued development of the Covid-19 pandemic and the mitigating actions performed by governmental health authorities, and the unknown speed of the new energy transition, cause a volatile market environment, with difficult conditions for predictions and setting reasonable key assumptions. 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 pandemic-related or climate-related matters affecting those assumptions. For example, Covid-19 effects have been factored into the estimated future cash flows with a reduced demand for oil and gas and lower commodity prices, particularly for the short term. Climate-related matters (see also section above related to consequences of initiatives to limit climate changes and the energy transition) are expected to have more pervasive effects 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. The phase and strength of the energy transition and the ambition of a net-zero emission by 2050 in accordance with the Paris Agreement is uncertain and will impact management assessment of future commodity prices and consequently the value of Equinor’s oiland gas assets. 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 partially mitigated by Equinor’s currently applied internal carbon price of USD 56 per tonne carbon dioxide equivalent to all potential projects and investments. In countries where the actual or predicted carbon price is higher (such as in Norway where both a CO2 tax and the EU Emission Trading System apply), Equinor applies the actual or expected cost. The Norwegian government has in 2021 announced their intentions to increase the tax on CO2 emissions from NOK 590 per tonne to NOK 2000 per tonne by the year 2030. Compared to Equinor’s estimates at 31 December 2020, it is expected that the cost increase for Equinor for the year 2030 will be approximately USD 0.4 billion pre-tax. Such an increase will affect the value-in-use calculations used for impairment evaluations for assets where this tax applies.
Asset retirement obligations
Equinor has significant obligations to decommission and remove offshore installations at the end of the production period. Establishing the appropriate estimates for such obligations 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.
10 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 2020 amount to USD 6,401 million, compared to 2019 when the net impairment amounted to USD 4,043 million, 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 11 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% (2019: 6%) real after tax. The discount rate is derived from Equinor’s weighted average cost of capital. For projects, mainly within the NES 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 8-15% for E&P Norway, 5-10% for E&P International, 6-7% for E&P USA and 6- 11% 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 assets being impaired/(reversed) and the valuation method used to determine the recoverable amount; the net impairment/(reversal), and the carrying amount after impairment.
1) Formerly named as North America – unconventional
2) Formerly named as North America – conventional offshore US Gulf of Mexico
3) Formerly named as North America – conventional other areas
Exploration & Production Norway
In 2020 the impairments were USD 1,219 million, mainly because of reduction in future price estimates. Negative reserve revisions and increased cost estimates added to the impairment losses.
In 2019 impairment losses of USD 1,119 million were recognised. The impairments were triggered by cost increases and decreased price assumptions. The impairment amount was impacted by how tax uplift is to be included in the pre-tax net present value estimate.
Exploration & Production USA – onshore
In 2020 the net impairment was USD 2,313 million of which USD 680 million was classified as exploration expenses. The impairment losses of USD 2,547 million of which USD 743 million 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 234 million were caused by improved production profile.
In 2019 impairment losses of USD 2,241 million of which USD 608 million was classified as exploration expenses were recognised mainly caused by reduced long-term price assumptions and reduced fair value of one asset.
Exploration & Production USA – offshore Gulf of Mexico
In 2020 the impairments were USD 305 million caused by decreased price assumptions.
In 2019 net impairment loss of USD 292 million was recognised due to reduced reserve estimates.
Total impairments in Exploration & Production USA in the period 2007 till 2020 is USD 16.5 billion including impairment of goodwill of USD 1.2 billion and exploration assets USD 1.3 billion.
Exploration & Production International – North America offshore other areas
In 2020 the impairment was USD 146 million due to operational issues.
Exploration & Production International – Europe and Asia
In 2020 the impairments were USD 1,280 million due to decreased price assumptions and negative reserve revisions.
Marketing, Midstream & Processing
In 2020 the impairment losses were USD 1,052 million mainly due to reduced refinery margin estimates and increased cost estimates.
Reduced volume-estimates from processing added to the impairment loss.
In 2019 impairment loss of USD 178 million was recognised related to the South Riding Point oil terminal as a result of the damages caused by the hurricane Dorian on Bahamas.
Management’s future commodity price assumptions and foreign 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 foreign currency assumptions reflect management’s best estimate of the price and foreign 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.
Following the ongoing Covid-19 pandemic, Equinor has performed a thorough and broad analysis and gained more insight into the expected development in drivers for the different commodity markets and exchange rates in which Equinor operates. Significant uncertainty continues to exist regarding future commodity price development due to the potential long-term impact on demand resulting from the ongoing Covid-19 pandemic and the measures taken to contain it, energy investments in the transition to a lower carbon economy and 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 as from the third quarter of 2020. The following price assumptions have been the basis for the impairment calculations.
All commodity prices are on a real 2020 basis, and comparables as per year-end 2019 and until the third quarter of 2020 are given in brackets.
In 2025, the oil price assumption is 65 USD/bbl (78 USD/bbl), with a further increase towards 2030. Beyond 2030, we expect a gradual decline with an estimate of 64 USD/bbl in 2040 (82 USD/bbl), which approximates the average price level for the period 2021-2050. In 2050, the oil prices are expected to be below 60 USD/bbl.
For natural gas in the UK (NBP), some volatility is expected, where the trend is a gradual increase in prices from today’s current prices up to 6.5 USD/mmBtu in 2030 (7.7 USD/mmBtu). From 2030, we expect prices at levels sufficient to incentivise the next LNG investment cycle and a flatter price-curve, with the price gradually increasing to 7.8 USD/mmBtu close to 2040 (7.7 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 has been set at the pre-2035 level. Henry Hub is expected to be 3.3 USD/mmBtu in 2030 (3.7 USD/mmBtu) and gradually increasing to 3.7 USD/mmBtu in 2040 (3.7 USD/mmBtu) before gradually declining through the 2040s.
Equinor has performed analysis of the foreign currency exchange rates between NOK and other currencies, which suggests that a return to a previously assumed long-term equilibrium is less likely. This conclusion is supported by the historical 5-year average and spot prices in the currency market, as well as an expected lower oil price and increased market uncertainty. Equinor has therefore implemented new long-term exchange rates from 2023 onwards. The NOK/USD rate has been revised to 8.5 (previously 7.0), while the NOK/EUR rate has been revised to 10.0 (from previously 9.0).
During the first nine months of 2020 there was a significant drop in the risk-free interest rates. The stock market recovery after the initial Covid-19 impact in March indicated a lower market risk premium. The low interest rates combined with lack of good alternative investment opportunities, channelled more funds towards the equity market resulting in investors accepting lower return on investments, resulting in a downward shift in the estimated equity risk premium. Taking this into account, Equinor adjusted the Weighted Average Cost of Capital (WACC) for accounting purposes, real post-tax, down from 6% to 5%.
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 under IAS36, 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 11 billion before tax effects.
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 oil and gas assets. A calculation of a possible effect of using the prices in a sustainable development scenario as estimated by the International Energy Agency (IEA) could result in an impairment of around USD 6 billion before tax.
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 the Sustainable Development 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 commodity price sensitivity. 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.