Note 4 - Climate change and energy transition

This note describes how Shell has considered climate-related impacts in key areas of the financial statements and how this translates into the valuation of assets and measurement of liabilities as Shell makes progress in the energy transition. The note is structured as follows:

Note 2 Significant accounting policies, judgements and estimates describes uncertainties, including those that have the potential to have a material effect on the Consolidated Balance Sheet in the next 12 months. This note describes the key areas of climate impacts that potentially have short-, medium- and longer-term effects on amounts recognised in the Consolidated Balance Sheet at December 31, 2022. Where relevant, this note contains references to other notes to the Consolidated Financial Statements and aims to provide an overarching summary of the energy transition impact.

In 2021, Shell launched its Powering Progress strategy to become a net-zero emissions business by 2050. The strategy includes targets to reduce absolute emissions from its operations and the energy it buys to run them, compared with 2016 levels. Shell’s targets include reducing Scope 1 and 2 emissions by 50% by 2030 and reducing the carbon intensity of energy products sold (Scope 1, 2 and 3 emissions) by 6-8% by 2023, 9-12% by 2024, 9-13% by 2025, 20% by 2030, 45% by 2035, and 100% by 2050.

Financial planning and assumptions

This section provides an overview of key assumptions used for financial planning related to climate change and the energy transition. These assumptions that underpin the amounts recognised in these financial statements -- such as future oil and gas prices, discount rates, future costs of decommissioning and restoration, and deferred tax assets -- take climate change and energy transition into account and are similarly used for impairment testing of carrying amounts of assets. Areas described focus on those most pertinent to Shell’s business and how financial planning and assumptions interact with scenarios. Subsequently, the sensitivity of carrying amounts to commodity prices, carbon costs, discount rates and demand, if different assumptions were applied, is described.

There is no one single scenario that underpins the financial statements. Shell scenarios are designed to challenge management’s perspectives on the future business environment and stretch management to consider even events that may be only remotely possible. As a result, these scenarios are not intended to be predictions of likely future events or outcomes and are not the basis for Shell’s financial statements and Operating Plans.

Shell scenarios and the range of possible outcomes inform the development of Shell’s strategy and Shell’s view on future oil and gas price outlooks and refining margins. These oil and gas price outlooks are one of the key assumptions that underpin Shell’s financial statements. Shell’s scenarios inform high-, mid- and low-price outlooks. The mid-price outlook represents management’s reasonable best estimate and is the basis for Shell’s financial statements, Operating Plans and impairment testing. Impairment testing applies management’s reasonable best estimates across the full life cycle of assets.

Shell’s targets to reduce absolute Scope 1 and 2 emissions [A] by 50% by 2030, compared with 2016 levels on a net basis, and a 20% reduction of net carbon intensity [B] by 2030 have been included in Shell’s Operating Plan. The Operating Plan also includes expected costs for evolving carbon regulations (see section “Carbon cost sensitivities” below) based on a forecast of Shell’s equity share of emissions from operated and non-operated assets also taking into account the estimated impact of free allowances.

[A] Operational control boundary
[B] GHG emissions based on the energy product sales included in the Net Carbon Intensity (NCI) using equity boundary.

Goodwill, other intangible assets, property, plant and equipment and joint ventures and associates

As from January 1, 2022 segments are aligned with the Powering Progress strategy. (see Note 8)

The carrying value of goodwill, other intangible assets, property plant and equipment, and joint ventures and associates by segment as at December 31, 2022, was as follows:

For Integrated Gas and Upstream, sensitivity to commodity prices and carbon prices has been tested (see below) covering the carrying amount of goodwill, other intangible assets, property plant and equipment, and joint ventures and associates. Sensitivity testing was performed applying alternative price scenarios to the forecasted cash flows for the whole period until the end of life of the asset tested. For Chemicals and Products, sensitivity to refining margins has been tested (see below). Marketing and Renewables and Energy Solutions are expected to be resilient through the energy transition with limited exposure of stranded assets.

In addition, sensitivity to changes in the discount rate applied in impairment testing has also been tested (see below).

Carrying value of Integrated Gas and Upstream assets

Within Integrated Gas and Upstream, the assets potentially most sensitive to the energy transition are production assets and exploration and evaluation assets. Both production assets of $117 billion and exploration and evaluation assets of $6 billion are recognised within Property, plant and equipment within Integrated Gas and Upstream.

Portfolio changes

Since 2016, the carrying amount of production assets in Integrated Gas and Upstream decreased from $169 billion as at December 31, 2016, to $117 billion as at December 31, 2022. Over this period, depreciation was higher than additions for each year, and disposals of property, plant and equipment with a carrying amount of some $25 billion occurred. The carrying amount of capitalised exploration and evaluation expenses decreased from $19 billion as at December 31, 2016, to $6 billion at December 31, 2022. This is the result of final investment decisions, reclassifications to production assets and amounts charged to expenses exceeding additions.

Estimated useful life

The energy transition and the pace at which it progresses may impact the remaining life of assets. Integrated Gas and Upstream assets are generally depreciated using a unit-of-production methodology where depreciation generally depends on production of SEC proved reserves (see Note 2). Based on production plans of existing assets, some 35%, 5% and 0% of SEC proved reserves as at December 31, 2022, would currently be left by 2030, 2040 and 2050, respectively. Based on the unit-of-production depreciation methodology applied, carrying amounts for individual assets are depreciated to nil in the same pattern as the depletion of reserves towards nil. An analysis of Integrated Gas and Upstream production assets of $117 billion as at December 31, 2022, based on planned reserves depletion shows that these assets would be significantly further depreciated under the unit-of-production method by 2030 and fully depreciated by 2050. This provides a further perspective on the risk of stranded assets carried in the Consolidated Balance Sheet as at December 31, 2022.

Price sensitivities using climate price lines

As noted, in accordance with IFRS, Shell’s financial statements are based on reasonable and supportable assumptions that represent management’s current best estimate of the range of economic conditions that may exist in the foreseeable future. The mid-price outlook informed by Shell’s scenario planning represents management’s best estimate. A change of -10% or +10% to the mid-price outlook, as an average percentage over the whole life cycle of assets, would result in around $2-5 billion (2021: $12-15 billion) impairment or of some $2-4 billion (2021: $6-9 billion) impairment reversal respectively in Integrated Gas and Upstream (see Note 12). Compared with prior year the impact of a 10% change in commodity prices is significantly lower as a result of the higher short- and medium-term commodity prices that both resulted in impairment reversals in 2022 and higher headroom in impairment testing.

The energy transition will continue to bring volatility and there is significant uncertainty as to how commodity prices will develop over the next decades. Some price lines see a structurally lower price during the transition period, while other price lines see structurally higher commodity prices as a result of changes in both supply and demand. As the risk of stranded assets is prevalent with downside price risk in energy transition scenarios, sensitivities have only been undertaken for such downside scenarios. If different price outlooks from external and often normative climate change scenarios were used, this would impact the recoverability of certain assets recognised in the Consolidated Balance Sheet as at December 31, 2022. These external scenarios are not representative of management’s mid-price reasonable best estimate.

Sensitivity of carrying amounts to commodity prices described below is under the assumption that all other factors in the models used, such as cost levels, volumes, mid-price CO₂ assumptions and the discount rate, to calculate recoverability of carrying amounts remain unchanged. Sensitivity testing has been performed by applying the alternative commodity price scenarios to cash flows for the whole period until the end of life of the assets tested. The alternative commodity prices were applied in the local cash flow models and thereafter aggregated by segment. Changes to commodity prices are applied because of the significant impact on Shell’s business. It should be noted that a significant decrease in long-term forecasted commodity prices would probably lead to further changes, such as in portfolio choices and cost levels.

Sensitivity to changes in commodity prices has been tested as follows:

Priceline 1 – Average prices from three [A] 1.5-2 degrees Celsius external climate change scenarios: in view of the broad range of price outlooks across the various scenarios, the average of three external price outlooks was taken.

[A] The IEA SDS scenario applied in 2021 is no longer published and has therefore been taken out for 2022.

• IHS Markit/ACCS 2022 – under this scenario oil prices (real terms 2022 (RT22)) gradually decrease towards $36.5 per barrel (/b) in 2039, recovering to $94.3/b in 2050. Gas prices (RT22) decrease from $3.7 per million British thermal units (/MMBtu) in 2023 towards 2024 to slightly below $3/MMBtu for Henry Hub, remaining around that level until 2050. For Europe, prices decrease from $35/MMbtu in 2023 towards around $4/MMBtu in 2029, remaining around that level until 2040 and then gradually increasing to a level around $5/MMBtu in 2050. For Asia, prices decrease towards around $5/MMBtu in 2029, again gradually increasing from 2045 to a level around $6/MMBtu in 2050.
• Woodmac WM AET-1.5 degree – under this scenario oil prices (RT22) gradually decrease towards $27/b in 2050. Gas prices (RT22) decrease from around $5/MMBtu in 2023 to $3/MMBtu in 2024, gradually increasing to some $4/MMBtu in 2045 and again decreasing to some $3/MMBtu in 2050 for Henry Hub. For Asia and Europe, gas prices (RT22) decrease from around $30/MMBtu in 2023 to some $6/MMBtu and $5/MMBtu respectively in 2031, gradually increasing again to some $10/MMBtu and some $8/MMbtu respectively around 2040 and subsequently decreasing to $6/MMBtu and some $5/MMBtu respectively in 2050.
• IEA NZE50 – under this scenario oil prices (RT22) gradually decrease towards some $25/b in 2050. Gas prices (RT22) decrease from some $3.5/MMBtu in 2023 to around $2/MMBtu for Henry Hub in 2030, remaining slightly below that level until 2050. For Asia and Europe, gas prices (RT22) decrease from some $10/MMBtu and $9/MMBtu respectively in 2023 to some $6/MMBtu and $5/MMBtu respectively around 2030, with a decrease towards some $5/MMBtu and $4/MMBtu respectively in 2050.

This average priceline provides an external view of the development of commodity prices under 1.5-2 degrees Celsius external climate change scenarios over the whole period under review.

Applying this priceline to Integrated Gas assets of $75 billion (2021: $65 billion [A]) and Upstream assets of $88 billion (2021: $89 billion [A]) as at December 31, 2022, shows recoverable amounts that are $4-6 billion (2021: $13-16 billion) and $1-2 billion (2021: $14-17 billion) lower, respectively, than the carrying amounts as at December 31, 2022.

[A] In 2022 goodwill and other intangibles were included in the scope for sensitivity testing. In 2021 these assets were not within the scope of sensitivity testing. Based on the 2022 sensitivity testing performed, it is unlikely that if these assets would have been included in the scope for 2021 testing, this would have resulted in a material impact on the outcome of sensitivity testing.

Priceline–2 – Hybrid Shell Plan and IEA NZE50: this priceline applies Shell’s mid-price outlook for the next 10 (see Note 12). Because of the greater uncertainty, the International Energy Agency (IEA) normative Net Zero Emissions scenario for the period after 10 years is applied. This weights less price-risk uncertainty to the first 10 reflected in the Operating Plan period and applies more risk to the more uncertain subsequent periods.

Applying this priceline to Integrated Gas assets of $75 billion (2021: $65 billion) and Upstream assets of $88 billion (2021: $89 billion) as at December 31, 2022, shows recoverable amounts that are $4-6 billion (2021: $10-12 billion) and $1-2 billion (2021:$5-6 billion) lower, respectively, than the carrying amounts as at December 31, 2022.

Priceline–3 – IEA NZE50: this priceline applies the IEA normative Net Zero Emissions scenario over the whole period under review. This priceline has been applied for the first time in the current year in order to also reflect the sensitivity to a pure net-zero emissions scenario from the IEA.

Applying this priceline to Integrated Gas assets of $75 billion and Upstream assets of $88 billion as at December 31, 2022, shows recoverable amounts that are $9-12 billion and $8-11 billion lower, respectively, than the carrying amounts as at December 31, 2022.

The graph above shows the oil pricelines on a real-terms basis applied for the period until 2050 for Shell’s mid-price outlook in comparison with the IEA announced pledges (IEA APS) scenario, the NGFS GCAM NZE 2050 scenario, the average prices from three 1.5-2 degrees Celsius external climate change scenarios (Priceline 1, above) and the IEA Net Zero Emissions by 2050 scenario (IEA NZE50, Priceline 3 above). The development of future oil prices is uncertain and oil prices have been subject to significant volatility in the past. Future oil prices may be impacted by future changes in macroeconomic factors, available supply, demand, geopolitical and other factors. The pricelines as per the scenarios NGFS GCAM NZE 2050, IEA APS, the average prices from three 1.5-2 degrees Celsius external climate change scenarios and IEA NZE50 differ from Shell’s best estimate and view of the future oil price.

Carbon price sensitivities

Carbon costs in the Operating Plan

The Operating Plan includes capital expenditure and operating costs to achieve Scope 1 and 2 emission reduction targets (see above). These include asset level abatement project costs that drive efficiencies and reduce emissions, expected costs for evolving carbon regulations based on a forecast of Shell’s equity share of emissions and costs of offsets for any residual amounts.

The total capital expenditure for abatement projects in relation to efficiency improvements, energy and chemicals parks transformations and use of renewable power included in the Operating Plan are in excess of $4 billion. Total yearly carbon emission costs in Shell’s Operating Plan gradually increase from some $0.8 billion in 2023 to some $1.5 billion in 2032 using the mid-price scenario. The sensitivity of carrying values of assets to changes in carbon prices is described in the section below.

Methods for estimating costs vary depending on the nature of the cost. Abatement projects costs to improve efficiencies and reduce emissions are estimated by applying a bottom-up approach where individual opportunities on an asset-level, project-by-project basis are identified.

Costs for evolving carbon regulations are based on a forecast of Shell’s equity share of emissions and are included in the Operating Plan at Shell’s mid-price outlook on a country-by-country basis and represent management’s best estimate. In the short and near term, up to 2030, costs for carbon emissions estimates are largely policy driven, through emission trading schemes or taxation levied by governments which currently vary significantly on a country-by-country basis. Beyond 2030, where policy predictions are more challenging, the costs for carbon emissions are estimated based on the expected costs of abatement technologies required for 2050. The costs are estimated to be at $125 per tonne (RT22) under Shell’s mid-price scenario. Under Shell’s high-price scenario, the costs are set at $220 per tonne (RT22), the top of the bioenergy with CCS cost range and the lower end of the direct air capture cost range.

Sensitivity to changes in carbon price assumptions

There is significant uncertainty as to how carbon costs will develop over the next decades. These will depend on policies set by countries and the pace of the energy transition. In accordance with IFRS, Shell’s financial statements are based on reasonable and supportable assumptions that represent management’s current best estimate which is policy based up to 2030 and then the mid-price outlook beyond 2030. As the risk of stranded assets is prevalent with higher carbon emission prices than anticipated, sensitivity analyses have only been undertaken for such a downside scenario. If the IEA NZE 2050 outlook is applied, this would impact the recoverability of certain assets recognised in the Consolidated Balance Sheet as at December 31, 2022. This scenario is not representative of management’s mid-price reasonable best estimate.

Sensitivity of carrying amounts to carbon emission costs as described below is under the assumption that all other factors in the models used to calculate recoverability of carrying amounts remain unchanged. Changes to carbon emission costs are applied for Integrated Gas and Upstream because of the potential impact on Shell’s business.

Applying the IEA NZE 2050 carbon price scenario to Integrated Gas assets of $75 billion and Upstream assets of $88 billion, up to the end of life of these assets, shows recoverable amounts that are $2-5 billion lower for Integrated Gas and not significantly lower for Upstream than the carrying amounts as at December 31, 2022.

For the key regions and countries the following carbon prices per tonne (RT22) have been assumed in the Operating Plan:

The graph below shows the carbon pricelines per tonne for the European Union on an RT22 basis under Shell’s mid-price outlook in comparison with the IEA NZE 2050 scenario. The IEA NZE 2050 scenario differs from Shell’s best estimate and view of the future CO₂ prices. Sensitivity of carrying amounts to the IEA NZE 2050 carbon price scenario is provided above.

Carrying value of Chemicals and Products assets

Within Chemicals and Products, the assets potentially most sensitive to the energy transition are refineries.

Portfolio changes

Since 2016, Shell’s Chemicals and Products portfolio has evolved, shifting from 15 refineries at the end of 2016 towards five energy and chemicals parks. During that period Shell assumed the sole ownership of two refineries through the dissolution of the Motiva joint venture, and disposed of, converted or closed nine refineries. The carrying amount of refineries decreased from $10 billion as at December 31, 2016, to $6 billion as at December 31, 2022. In line with Shell’s strategy, Shell’s refining footprint is being transformed into five energy and chemicals parks that will provide feedstocks for the chemicals and lubricants business, as well as other low-carbon energy products, including biofuels and hydrogen. This transformation will involve investments in assets within these energy parks that will be recognised as separate cash-generating units and are expected to be resilient in the energy transition, and hence their carrying amounts may increase.

Estimated useful life

Refineries in the Chemicals and Products segment (carrying amount as at December 31, 2022, $6 billion (2021: $6 billion) of which $5 billion (2021: $5 billion) relates to refineries in the five energy and chemicals parks (2021: excluding refineries classified as held for sale)) may be impacted under a two-degrees-Celsius or less external climate scenario.

For refineries in Chemicals and Products, depreciation of assets is on a straight-line basis over the life of the assets, starting at the date the asset becomes available for use, over a period of 20 years (see Note 2). Over the course of the energy transition, the current carrying amount of refineries will be fully depreciated, offset by anticipated investments in assets that are expected to be resilient in the energy transition as described above. Based on current depreciation of the carrying amounts as at December 31, 2022, and assuming no further investment, all refineries would be fully depreciated between four and 14 years.

In addition to refineries, further assets of $39 billion include $28 billion of assets in relation to Chemicals which are expected to be resilient through the energy transition as chemical products are not produced with the aim to combust and consequently do not generate GHG emissions.

Other assets of $11 billion includes $7 billion of assets in relation to trading and supply are also expected to be resilient in the energy transition. Another $1.6 billion of assets relates to oil sands. Based on production plans for oil sands assets, some 80%, 56% and 31% of SEC proved reserves as at December 31, 2022, would currently be left by 2030, 2040 and 2050, respectively. Taking into consideration the carrying amount as at December 31, 2022 and depreciation under the unit-of-production methodology, this provides a further perspective on the risk of stranded oil sands assets carried in the Consolidated Balance Sheet as at December 31, 2022.

Price sensitivities

Refining margins included in the Operating Plan are at an average of $6.22/bbl. A change of -$1/bbl or +$1/bbl to the refining margin outlook period would result in around $1-3 billion impairment or in some $1-3 billion impairment reversal respectively in Chemicals and Products (see Note 12).

Carrying value of Marketing assets

Portfolio changes

Assets in the Marketing segment are expected to be resilient through the energy transition with a change in the product mix as the energy transition progresses. The demand for products sold such as chemicals, lubricants, biofuels, bitumen, electric vehicle charging and convenience retail is not expected to decrease and is expected to increase for a variety of these products in many markets. As a result the carrying value of these assets is not expected to be impacted by the energy transition or lower commodity price scenarios.

Carrying value of Renewables and Energy Solutions assets

Portfolio changes

Assets in the Renewables and Energy Solutions segment are expected to be resilient through the energy transition.

Discount rate sensitivity

The discount rate applied for impairment testing is based on a nominal post-tax weighted average cost of capital (WACC) and is determined at 5% for Power activities and 6.5% for all other businesses. The discount rate includes generic system risk for climate change risk. In addition, cash flow projections applied in individual assets include specific asset risks, including risk of transition. An increase in systematic climate risk could lead to a higher WACC and consequently to a higher discount rate to be applied in impairment testing. An increase of the discount rate applied for impairment testing of 1% under the assumption that all other factors in the models used to calculate recoverability of carrying amounts remain unchanged would lead to a change in the carrying amount of $1-3 billion for Integrated Gas, and up to $1 billion in each of the following segments: Upstream, Chemicals and Products and Renewables and Energy Solutions, and no significant impairment in Marketing and Corporate.

Global oil and gas demand sensitivities

A decrease in global demand and unchanged supply of oil and gas would likely lead to a decrease in price (see price sensitivity above). During 2022 Shell’s production of oil and gas accounted for 1.5% and 2% of total global production of oil and gas respectively. Changes in global oil and gas demand are therefore not expected to directly impact the ability to sell volumes of oil and gas produced by Shell at market prices.

Deferred tax assets

In general, it is expected that sufficient deferred tax liabilities and forecasted taxable profits within the planning period of 10 years are available for recovery of the deferred tax assets recognised at December 31, 2022. Integrated Gas and Upstream deferred tax assets recognised are expected to be recovered within the period of production of each asset. For deferred tax assets of $303 million as at December 31, 2022 (2021: $711 million) this period extends beyond 10 years. Deferred tax assets in Chemicals and Products and in Marketing expected to be recovered in more than 10 years are $382 million as at December 31, 2022 (2021: $854 million). In Chemicals and Products, cash flows beyond 10 years (for a maximum of an additional 10 years) were further risked to determine recoverability of deferred tax assets beyond 10 years (see Note 22).

Decommissioning and other provisions

The energy transition may result in decommissioning and restoration occurring earlier than expected. The risk on the timing of decommissioning and restoration activities for Integrated Gas and Upstream fields is limited, supported by production plans in the foreseeable future (see “Estimated useful life” above). Acceleration of decommissioning and restoration activities has also been reflected in the assessment of the appropriate discount rate. In 2021, the discount rate was revised from a 30-year to a 20-year term in line with the average remaining life of Integrated Gas and Upstream assets. On an undiscounted basis the provision for decommissioning and restoration as at December 31, 2022 was $33 billion, recognised on a discounted basis in the Consolidated Balance Sheet as at December 31, 2022 at $20 billion (2021: $22 billion). Sensitivity to changes in the discount rate is provided in Note 24.

In Chemicals and Products, it was industry practice not to recognise decommissioning and restoration provisions associated with manufacturing facilities. This was on the basis that these assets were considered to have indefinite lives, so it was considered remote that an outflow of economic benefits would be required. In 2020, Shell considered the changed macroeconomic fundamentals, together with Shell’s plans to rationalise the Group’s manufacturing portfolio. Shell also reconsidered whether it remained appropriate not to recognise decommissioning and restoration provisions for manufacturing facilities. Since 2020, decommissioning and restoration provisions are recognised for certain shorter-lived manufacturing facilities (see Notes 24 and 31). The remaining five energy and chemicals parks are considered longer-lived facilities that are expected to be resilient in the energy transition, and decommissioning would generally be more than 50 years away.

Onerous contracts

Closure or early termination of activities may lead to supply contracts becoming onerous. Onerous contract provisions (see Note 24) have been recognised as at December 31, 2022, to reflect changes in expected future utilisation of certain assets. These include contracts in relation to unused terminals and refineries. The total carrying amount of the provision for onerous contracts as at December 31, 2022 was $1.5 billion (2021: $1.7 billion) principally related to contracts in relation to unused terminals and refineries.

Dividend resilience

External stakeholders have requested disclosures on how climate change affects dividend-paying capacity. If a further impairment had been recognised in 2022 using any of the climate change scenarios described above, this would not have impacted the ability to pay dividends in this financial year because of the strong cash flow generation and financial reserves. Had Shell applied the IEA NZE50 scenario (see above), and if this had led to a decrease in the recoverable amount of Integrated Gas and Upstream assets of $17-23 billion and recognition of an equivalent impairment, this would not have impacted the distributable reserves available to Shell from which to pay dividends in 2022. This is on the basis that such impairment would have resulted in part-realisation of the merger reserve recognised by the Company of $234 billion as at December 31, 2022.

A forward-looking statement regarding future dividend-paying capacity cannot be provided because of unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements.

Physical risks

Potential physical impacts to Shell’s assets, irrespective of cause, are important for Shell to manage.

Climate variability is considered in the design and operation of Shell’s assets and infrastructure to minimise the risk of adverse incidents to Shell’s employees and contractors, the communities where Shell operates, its equipment and infrastructure. Shell’s new projects consider anticipated weather and climatic events in their design and Metocean (meteorology and oceanography) engineering experts are available, if required, to assist Shell’s assets and project teams in the evaluation of physical risks.

On an ongoing basis, Shell’s assets leverage broad risk and threat management processes to identify and respond to emerging challenges to their ongoing safe, compliant and efficient operation, as required by Shell’s HSSE & SP Control Framework.