Critical Audit Matters
Auditor Opinion Overview
| Filing | 2021 20-F | Company Page | Shell plc |
|---|---|---|---|
| Fiscal Year | 2021-12-31 | Signature Date | 2022-03-09 |
| Auditor | Ernst & Young LLP | Location | London, UNITED KINGDOM |
| Critical Audit Matters | |||
1: Proven and unproven reserves
"THE ESTIMATION OF OIL AND GAS RESERVES"
Description:
Description of the matter As described in Note 9 to the Consolidated Financial Statements, at December 31, 2021, production assets amounted to $118.4 billion and had an associated depreciation, depletion and amortisation (DD&A) charge of $15.8 billion. Also, as described in Note 9, exploration and evaluation (E&E) assets amounted to $7.1 billion at December 31, 2021. As further described in Note 9, impairment charges of $1.5 billion of production and E&E assets were recorded during the year. As described in Note 19 to the Consolidated Financial Statements, decommissioning and restoration (D&R) provisions amounted to $22.1 billion. Oil and gas reserves estimates are used in the calculation of DD&A, impairment testing and in the estimation of D&R provisions. The risk is the inappropriate recognition of proved reserves that impacts these accounting estimates. As stated in Note 4 to the Consolidated Financial Statements, in 2021 Shell launched their Powering Progress strategy to accelerate the transition of their business to net-zero emissions, including targets to reduce the carbon intensity of energy products they sell (scope 1, 2 and 3 emissions) by 6-8% by 2023, 20% by 2030, 45% by 2035 and 100% by 2050. Further in October 2021, Shell announced their target to reduce absolute scope 1 and scope 2 emissions by 50% by 2030, compared to 2016 levels. There is therefore a risk that Shell recognises oil and gas reserves that are not ultimately produced. If proved reserves are recognised that are not ultimately produced, depreciation will be understated, and the recoverable amount of assets may be overstated. Auditing the estimation of oil and gas reserves is complex, as there is significant estimation uncertainty in assessing the quantities of reserves and resources in place. Estimated reserves and resources in place are based on significant assumptions such as production curves and certain other inputs, including forecast production volumes, future capital and operating cost assumptions and life of field assumptions, all of which are inputs used by reserves experts to estimate oil and gas reserves. Estimation uncertainty is further elevated given the transition to a low-carbon economy which could impact life-of-field assumptions and increase the risk of underutilised or stranded oil and gas assets.
Description of the matter As described in Note 9 to the Consolidated Financial Statements, at December 31, 2021, production assets amounted to $118.4 billion and had an associated depreciation, depletion and amortisation (DD&A) charge of $15.8 billion. Also, as described in Note 9, exploration and evaluation (E&E) assets amounted to $7.1 billion at December 31, 2021. As further described in Note 9, impairment charges of $1.5 billion of production and E&E assets were recorded during the year. As described in Note 19 to the Consolidated Financial Statements, decommissioning and restoration (D&R) provisions amounted to $22.1 billion. Oil and gas reserves estimates are used in the calculation of DD&A, impairment testing and in the estimation of D&R provisions. The risk is the inappropriate recognition of proved reserves that impacts these accounting estimates. As stated in Note 4 to the Consolidated Financial Statements, in 2021 Shell launched their Powering Progress strategy to accelerate the transition of their business to net-zero emissions, including targets to reduce the carbon intensity of energy products they sell (scope 1, 2 and 3 emissions) by 6-8% by 2023, 20% by 2030, 45% by 2035 and 100% by 2050. Further in October 2021, Shell announced their target to reduce absolute scope 1 and scope 2 emissions by 50% by 2030, compared to 2016 levels. There is therefore a risk that Shell recognises oil and gas reserves that are not ultimately produced. If proved reserves are recognised that are not ultimately produced, depreciation will be understated, and the recoverable amount of assets may be overstated. Auditing the estimation of oil and gas reserves is complex, as there is significant estimation uncertainty in assessing the quantities of reserves and resources in place. Estimated reserves and resources in place are based on significant assumptions such as production curves and certain other inputs, including forecast production volumes, future capital and operating cost assumptions and life of field assumptions, all of which are inputs used by reserves experts to estimate oil and gas reserves. Estimation uncertainty is further elevated given the transition to a low-carbon economy which could impact life-of-field assumptions and increase the risk of underutilised or stranded oil and gas assets.
Response:
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s oil and gas reserves’ estimation process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested management’s controls over review of changes to year-on-year estimated oil and gas reserves volumes. We involved professionals with substantial oil and gas reserves audit experience to assist us in evaluating the key assumptions and methodologies applied by management. Our procedures included, amongst others, testing that significant additions or reductions in reserves had been made in the period in which new information became available, and assessing whether they were in compliance with Shell’s reserves and resources guidance. We evaluated the professional qualifications and objectivity of management’s reserves experts who performed the preparation of the reserve estimates and who are primarily responsible for providing independent review and challenge, and ultimately endorsement of, the reserve estimates. We also evaluated the completeness and accuracy of the inputs used by management in estimating the oil and gas reserves by agreeing the inputs to source documentation and we performed backtesting of historical data to identify indications of estimation bias over time. We evaluated management’s development plan for compliance with SEC rules that undrilled locations must be scheduled to be drilled within five years, unless specific circumstances justify a longer period. This evaluation was made by assessing the consistency of the development projections with Shell’s development plans and capital allocation framework. Where reserves are recognised beyond current licence terms, we assessed the assumption around licence renewal. In order to determine whether there is a risk that reserves recognised will not be produced, among other procedures, we estimated the carbon intensity of Shell’s Upstream and Integrated Gas fields, focussing on the most carbon intensive assets. We also analysed those assets that are currently forecast to be producing beyond 2030 and estimated the carbon intensity of the most significant fields that are expected to be producing after 2030. We analysed further the carbon intensity per barrel of those fields. For the assets where forecast emissions were highest, we evaluated whether Shell’s operating plan assumptions included planned actions and associated expenditures to reduce the carbon emissions of these projects. We gave specific consideration to whether the economic limit test incorporated Shell’s estimate of future carbon costs to reflect the potential impact of climate change and the energy transition. The economic limit is management’s estimation of the point at which the operating cash flow from a project becomes negative, and drives the Company's life of field assumption. Once the economic limit becomes negative, the fields would be decommissioned. How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s oil and gas reserves’ estimation process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested management’s controls over review of changes to year-on-year estimated oil and gas reserves volumes. We involved professionals with substantial oil and gas reserves audit experience to assist us in evaluating the key assumptions and methodologies applied by management. Our procedures included, amongst others, testing that significant additions or reductions in reserves had been made in the period in which new information became available, and assessing whether they were in compliance with Shell’s reserves and resources guidance. We evaluated the professional qualifications and objectivity of management’s reserves experts who performed the preparation of the reserve estimates and who are primarily responsible for providing independent review and challenge, and ultimately endorsement of, the reserve estimates. We also evaluated the completeness and accuracy of the inputs used by management in estimating the oil and gas reserves by agreeing the inputs to source documentation and we performed backtesting of historical data to identify indications of estimation bias over time. We evaluated management’s development plan for compliance with SEC rules that undrilled locations must be scheduled to be drilled within five years, unless specific circumstances justify a longer period. This evaluation was made by assessing the consistency of the development projections with Shell’s development plans and capital allocation framework. Where reserves are recognised beyond current licence terms, we assessed the assumption around licence renewal. In order to determine whether there is a risk that reserves recognised will not be produced, among other procedures, we estimated the carbon intensity of Shell’s Upstream and Integrated Gas fields, focussing on the most carbon intensive assets. We also analysed those assets that are currently forecast to be producing beyond 2030 and estimated the carbon intensity of the most significant fields that are expected to be producing after 2030. We analysed further the carbon intensity per barrel of those fields. For the assets where forecast emissions were highest, we evaluated whether Shell’s operating plan assumptions included planned actions and associated expenditures to reduce the carbon emissions of these projects. We gave specific consideration to whether the economic limit test incorporated Shell’s estimate of future carbon costs to reflect the potential impact of climate change and the energy transition. The economic limit is management’s estimation of the point at which the operating cash flow from a project becomes negative, and drives the Company's life of field assumption. Once the economic limit becomes negative, the fields would be decommissioned.
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s oil and gas reserves’ estimation process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested management’s controls over review of changes to year-on-year estimated oil and gas reserves volumes. We involved professionals with substantial oil and gas reserves audit experience to assist us in evaluating the key assumptions and methodologies applied by management. Our procedures included, amongst others, testing that significant additions or reductions in reserves had been made in the period in which new information became available, and assessing whether they were in compliance with Shell’s reserves and resources guidance. We evaluated the professional qualifications and objectivity of management’s reserves experts who performed the preparation of the reserve estimates and who are primarily responsible for providing independent review and challenge, and ultimately endorsement of, the reserve estimates. We also evaluated the completeness and accuracy of the inputs used by management in estimating the oil and gas reserves by agreeing the inputs to source documentation and we performed backtesting of historical data to identify indications of estimation bias over time. We evaluated management’s development plan for compliance with SEC rules that undrilled locations must be scheduled to be drilled within five years, unless specific circumstances justify a longer period. This evaluation was made by assessing the consistency of the development projections with Shell’s development plans and capital allocation framework. Where reserves are recognised beyond current licence terms, we assessed the assumption around licence renewal. In order to determine whether there is a risk that reserves recognised will not be produced, among other procedures, we estimated the carbon intensity of Shell’s Upstream and Integrated Gas fields, focussing on the most carbon intensive assets. We also analysed those assets that are currently forecast to be producing beyond 2030 and estimated the carbon intensity of the most significant fields that are expected to be producing after 2030. We analysed further the carbon intensity per barrel of those fields. For the assets where forecast emissions were highest, we evaluated whether Shell’s operating plan assumptions included planned actions and associated expenditures to reduce the carbon emissions of these projects. We gave specific consideration to whether the economic limit test incorporated Shell’s estimate of future carbon costs to reflect the potential impact of climate change and the energy transition. The economic limit is management’s estimation of the point at which the operating cash flow from a project becomes negative, and drives the Company's life of field assumption. Once the economic limit becomes negative, the fields would be decommissioned. How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s oil and gas reserves’ estimation process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested management’s controls over review of changes to year-on-year estimated oil and gas reserves volumes. We involved professionals with substantial oil and gas reserves audit experience to assist us in evaluating the key assumptions and methodologies applied by management. Our procedures included, amongst others, testing that significant additions or reductions in reserves had been made in the period in which new information became available, and assessing whether they were in compliance with Shell’s reserves and resources guidance. We evaluated the professional qualifications and objectivity of management’s reserves experts who performed the preparation of the reserve estimates and who are primarily responsible for providing independent review and challenge, and ultimately endorsement of, the reserve estimates. We also evaluated the completeness and accuracy of the inputs used by management in estimating the oil and gas reserves by agreeing the inputs to source documentation and we performed backtesting of historical data to identify indications of estimation bias over time. We evaluated management’s development plan for compliance with SEC rules that undrilled locations must be scheduled to be drilled within five years, unless specific circumstances justify a longer period. This evaluation was made by assessing the consistency of the development projections with Shell’s development plans and capital allocation framework. Where reserves are recognised beyond current licence terms, we assessed the assumption around licence renewal. In order to determine whether there is a risk that reserves recognised will not be produced, among other procedures, we estimated the carbon intensity of Shell’s Upstream and Integrated Gas fields, focussing on the most carbon intensive assets. We also analysed those assets that are currently forecast to be producing beyond 2030 and estimated the carbon intensity of the most significant fields that are expected to be producing after 2030. We analysed further the carbon intensity per barrel of those fields. For the assets where forecast emissions were highest, we evaluated whether Shell’s operating plan assumptions included planned actions and associated expenditures to reduce the carbon emissions of these projects. We gave specific consideration to whether the economic limit test incorporated Shell’s estimate of future carbon costs to reflect the potential impact of climate change and the energy transition. The economic limit is management’s estimation of the point at which the operating cash flow from a project becomes negative, and drives the Company's life of field assumption. Once the economic limit becomes negative, the fields would be decommissioned.
Reference:
Note 9, Note 19 and Note 4
Note 9, Note 19 and Note 4
2: Long-lived assets
"IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT AND JOINT VENTURE AND ASSOCIATES (JVA)"
Description:
Description of the matter As described in Notes 9 and 10 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised $118.4 billion of production assets, $49.1 billion of manufacturing, supply and distribution assets (refineries) (collectively, PP&E) and $23.4 billion of joint ventures and associates (JVAs). As disclosed in Note 9, Shell recognised $0.3 billion of impairment charges relating to production assets and $2.3 billion relating to manufacturing, supply and distribution assets. As discussed in Note 10, Shell recognised impairment charges of $0.0 billion relating to JVAs. The carrying values of PP&E and JVAs are sensitive to small changes in key assumptions, which increases the risk of indicators of impairment or impairment reversal not being identified. Our audit effort has therefore focused on the completeness and timely identification of indicators of impairment charges or impairment reversals. Auditing the impairment of PP&E and JVAs is subjective due to the significant amount of judgement involved in determining whether indicators of impairment or impairment reversal exist, particularly for longer term assets. Key judgements in determining whether indicators of impairment or impairment reversal exist include changes in forecast commodity price and refining margin assumptions, forecast carbon prices, movements in oil and gas reserves, changes in asset performance and future development plans and the expected useful lives of assets. The estimation of forecast commodity prices, refining margins, forecast carbon prices and expected useful lives of assets assumptions are particularly judgmental because of, among other factors, increased demand uncertainty and pace of decarbonisation due to climate change and the energy transition.
Description of the matter As described in Notes 9 and 10 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised $118.4 billion of production assets, $49.1 billion of manufacturing, supply and distribution assets (refineries) (collectively, PP&E) and $23.4 billion of joint ventures and associates (JVAs). As disclosed in Note 9, Shell recognised $0.3 billion of impairment charges relating to production assets and $2.3 billion relating to manufacturing, supply and distribution assets. As discussed in Note 10, Shell recognised impairment charges of $0.0 billion relating to JVAs. The carrying values of PP&E and JVAs are sensitive to small changes in key assumptions, which increases the risk of indicators of impairment or impairment reversal not being identified. Our audit effort has therefore focused on the completeness and timely identification of indicators of impairment charges or impairment reversals. Auditing the impairment of PP&E and JVAs is subjective due to the significant amount of judgement involved in determining whether indicators of impairment or impairment reversal exist, particularly for longer term assets. Key judgements in determining whether indicators of impairment or impairment reversal exist include changes in forecast commodity price and refining margin assumptions, forecast carbon prices, movements in oil and gas reserves, changes in asset performance and future development plans and the expected useful lives of assets. The estimation of forecast commodity prices, refining margins, forecast carbon prices and expected useful lives of assets assumptions are particularly judgmental because of, among other factors, increased demand uncertainty and pace of decarbonisation due to climate change and the energy transition.
Response:
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s asset impairment process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested the controls over management’s identification of indicators of impairment and reversals of impairment and the approval of oil and gas prices and refining margins. We evaluated Shell’s assessment of impairment and impairment reversal triggers, including changes in the forecast commodity price assumptions, movements in oil and gas reserves (see oil and gas reserves critical audit matter), changes in asset performance and changes in Shell’s business and operating plan assumptions. We further considered assets with high carbon intensity as a potential indicator of impairment, given Shell’s carbon emissions reductions targets. To test Shell’s commodity price assumptions, amongst other procedures, we compared future short and long-term oil and gas prices to an independently developed reasonable range of forecasts based on consensus analysts’ forecasts and those adopted by other international oil companies. To evaluate the impact of energy transition on Shell’s commodity price forecasts applied in the preparation of the financial statements, we also compared Shell’s oil and gas price scenarios to the IEA’s Net Zero Emissions 2050 (NZE) and to the IEA’s Announced Pledges Scenario (APS) price assumptions. We evaluated the reasonableness of Shell’s refining margin assumptions by comparing these to independent market and consultant forecasts. We also involved our oil and gas valuations specialists to assess the reasonableness of Shell’s refining margin estimation methodology and assumptions, including evaluating long-run demand forecasts, incorporating the impacts of the energy transition, supply dynamics, and the speed of the industry’s response to changing demand through either constructing new refineries or closing older refineries.Given the continued improvement in commodity prices and short-term refining margins, we assessed whether these higher price markers represented a trigger for impairment reversal and performed benchmarking to determine whether Shell’s oil and gas company peers reflected changes in oil and gas price and refining margin assumptions as indicators of impairment or impairment reversal. To test Shell’s forecast carbon price assumptions, we involved professionals with substantial climate change experience to review the methodology adopted and the reasonableness of the carbon prices applied in 25 different jurisdictions or regions, including 10 jurisdictions with the highest forecast carbon costs, by independently determining our view of a range of acceptable forecast carbon price assumptions. We also tested the carbon pricing included in the forecast cash flows and performed sensitivity analysis by using a range of carbon prices, such as those disclosed in the IEA Net Zero Emissions by 2050 scenario. Where carbon price assumptions were outside of our range, we carried out sensitivity analysis to assess if the impacts were material. To evaluate the accuracy of significant assumptions we performed a lookback by comparing actual performance of assets to the forecasts made in the prior year. We also assessed potential operational changes that have or are expected to have a significant adverse effect on an asset and whether such unplanned shutdowns should be considered as impairment triggers. In conjunction with our evaluation of the operating plan, we performed procedures to understand how management intend to achieve their planned Scope 1 and 2 and Net Carbon Footprint reductions and whether these actions have been reflected in Shell’s operating plan, which impact Shell’s financial statements and disclosures, specifically in impairment of PP&E, E&E assets, D&R provisions, and recognition of DTAs. Also, we assessed the operating and capital expenditure assumptions that were estimated necessary to achieve the emission reductions. This also involved assessing assumptions on acquisitions, divestments, investments in CCS technologies and Nature Based Solutions. We considered potential impairment triggers related to climate change and energy transition by estimating the carbon intensity of Shell’s Upstream and Integrated Gas fields and identifying the most carbon intensive assets. We assessed management’s plans to reduce the carbon intensity of these assets in the future to determine whether there is a material risk that reserves recognised will not be produced or if the carbon intensity limited the expected useful lives of the assets. We assessed consistency of Shell’s plans to reduce the carbon intensity of these assets with their carbon emissions reductions targets. In addition, we considered contradictory evidence, such as the results of comparable market transactions by other energy companies in jurisdictions with similar environmental and regulatory focus that could indicate a significant increase or decrease in the recoverable amount of Shell’s assets. We also considered public comments or commitments made by Shell in relation to the Powering Progress strategy and whether these could impact the future potential value of any assets. We assessed the appropriateness of Shell’s disclosure of information about the assumptions Shell makes that could, in the future, have a significant risk of material adjustments to the carrying amounts of assets and liabilities, including sensitivity disclosures. This included evaluating the sensitivity disclosures in Note 4 of the carrying value of Shell’s Upstream and Integrated Gas PP&E assets against a range of future oil and gas price assumptions, reflecting reduced demand scenarios due to climate change and the energy transition, including the IEA Net Zero Emissions by 2050 scenario.
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s asset impairment process. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested the controls over management’s identification of indicators of impairment and reversals of impairment and the approval of oil and gas prices and refining margins. We evaluated Shell’s assessment of impairment and impairment reversal triggers, including changes in the forecast commodity price assumptions, movements in oil and gas reserves (see oil and gas reserves critical audit matter), changes in asset performance and changes in Shell’s business and operating plan assumptions. We further considered assets with high carbon intensity as a potential indicator of impairment, given Shell’s carbon emissions reductions targets. To test Shell’s commodity price assumptions, amongst other procedures, we compared future short and long-term oil and gas prices to an independently developed reasonable range of forecasts based on consensus analysts’ forecasts and those adopted by other international oil companies. To evaluate the impact of energy transition on Shell’s commodity price forecasts applied in the preparation of the financial statements, we also compared Shell’s oil and gas price scenarios to the IEA’s Net Zero Emissions 2050 (NZE) and to the IEA’s Announced Pledges Scenario (APS) price assumptions. We evaluated the reasonableness of Shell’s refining margin assumptions by comparing these to independent market and consultant forecasts. We also involved our oil and gas valuations specialists to assess the reasonableness of Shell’s refining margin estimation methodology and assumptions, including evaluating long-run demand forecasts, incorporating the impacts of the energy transition, supply dynamics, and the speed of the industry’s response to changing demand through either constructing new refineries or closing older refineries.Given the continued improvement in commodity prices and short-term refining margins, we assessed whether these higher price markers represented a trigger for impairment reversal and performed benchmarking to determine whether Shell’s oil and gas company peers reflected changes in oil and gas price and refining margin assumptions as indicators of impairment or impairment reversal. To test Shell’s forecast carbon price assumptions, we involved professionals with substantial climate change experience to review the methodology adopted and the reasonableness of the carbon prices applied in 25 different jurisdictions or regions, including 10 jurisdictions with the highest forecast carbon costs, by independently determining our view of a range of acceptable forecast carbon price assumptions. We also tested the carbon pricing included in the forecast cash flows and performed sensitivity analysis by using a range of carbon prices, such as those disclosed in the IEA Net Zero Emissions by 2050 scenario. Where carbon price assumptions were outside of our range, we carried out sensitivity analysis to assess if the impacts were material. To evaluate the accuracy of significant assumptions we performed a lookback by comparing actual performance of assets to the forecasts made in the prior year. We also assessed potential operational changes that have or are expected to have a significant adverse effect on an asset and whether such unplanned shutdowns should be considered as impairment triggers. In conjunction with our evaluation of the operating plan, we performed procedures to understand how management intend to achieve their planned Scope 1 and 2 and Net Carbon Footprint reductions and whether these actions have been reflected in Shell’s operating plan, which impact Shell’s financial statements and disclosures, specifically in impairment of PP&E, E&E assets, D&R provisions, and recognition of DTAs. Also, we assessed the operating and capital expenditure assumptions that were estimated necessary to achieve the emission reductions. This also involved assessing assumptions on acquisitions, divestments, investments in CCS technologies and Nature Based Solutions. We considered potential impairment triggers related to climate change and energy transition by estimating the carbon intensity of Shell’s Upstream and Integrated Gas fields and identifying the most carbon intensive assets. We assessed management’s plans to reduce the carbon intensity of these assets in the future to determine whether there is a material risk that reserves recognised will not be produced or if the carbon intensity limited the expected useful lives of the assets. We assessed consistency of Shell’s plans to reduce the carbon intensity of these assets with their carbon emissions reductions targets. In addition, we considered contradictory evidence, such as the results of comparable market transactions by other energy companies in jurisdictions with similar environmental and regulatory focus that could indicate a significant increase or decrease in the recoverable amount of Shell’s assets. We also considered public comments or commitments made by Shell in relation to the Powering Progress strategy and whether these could impact the future potential value of any assets. We assessed the appropriateness of Shell’s disclosure of information about the assumptions Shell makes that could, in the future, have a significant risk of material adjustments to the carrying amounts of assets and liabilities, including sensitivity disclosures. This included evaluating the sensitivity disclosures in Note 4 of the carrying value of Shell’s Upstream and Integrated Gas PP&E assets against a range of future oil and gas price assumptions, reflecting reduced demand scenarios due to climate change and the energy transition, including the IEA Net Zero Emissions by 2050 scenario.
Reference:
Notes 9 and 10
Notes 9 and 10
3: Proven and unproven reserves
"EXPLORATION AND EVALUATION ASSETS"
Description:
Description of the matter As described in Note 9 to the Consolidated Financial Statements, at December 31, 2021, Shell recognised $7.1 billion of E&E assets. During the year, management recorded $1.8 billion of E&E write offs and impairments. In assessing whether to test E&E assets for impairment, the judgements to consider include, whether a licence is expected to be renewed, whether sufficient data exists to indicate that the carrying amount of E&E assets is likely to be recovered and whether or not commercially viable quantities of resources exist. Auditing impairment assessments of E&E assets is inherently judgemental given the exploration for and evaluation of the resources has not always reached a stage at which information sufficient to estimate future cash flows is available. Given the current environment, and the capital allocation and emissions reductions decisions that Shell intend to take through the energy transition, there is a heightened risk that projects will no longer proceed, in which case they may need to be written off or impaired. As a result of these factors, there is significant auditor judgement relating to the risk that certain E&E costs are not written off in the appropriate reporting period.
Description of the matter As described in Note 9 to the Consolidated Financial Statements, at December 31, 2021, Shell recognised $7.1 billion of E&E assets. During the year, management recorded $1.8 billion of E&E write offs and impairments. In assessing whether to test E&E assets for impairment, the judgements to consider include, whether a licence is expected to be renewed, whether sufficient data exists to indicate that the carrying amount of E&E assets is likely to be recovered and whether or not commercially viable quantities of resources exist. Auditing impairment assessments of E&E assets is inherently judgemental given the exploration for and evaluation of the resources has not always reached a stage at which information sufficient to estimate future cash flows is available. Given the current environment, and the capital allocation and emissions reductions decisions that Shell intend to take through the energy transition, there is a heightened risk that projects will no longer proceed, in which case they may need to be written off or impaired. As a result of these factors, there is significant auditor judgement relating to the risk that certain E&E costs are not written off in the appropriate reporting period.
Response:
How we addressed the matter in our audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over Shell’s E&E impairment assessment process. For example, we tested controls over management’s review of E&E assets for write off and impairment. To test the completeness and appropriateness of the E&E asset write off and impairment charges recorded, our procedures included, amongst others, assessing each significant licence area against the impairment criteria within IFRS 6 with a particular focus on those assets that were expected to be developed over the medium and long term, those assets where the dominant commodity that will be produced is oil, or highly carbon intensive projects. Through this analysis, we independently identified the assets that we considered most at risk of not being developed by Shell or being divested as a consequence of the Company’s emissions reductions targets. We evaluated the likelihood of management progressing the E&E assets, including the strategic fit of the assets, carbon intensity of the developments, planned capex and project economics and the expectation that sufficient cash resources will be available to fund the expected development of assets. For example, in evaluating the strategic fit of carbon intensive assets, we considered the inclusion of actions within Shell’s operating plan to achieve target Scope 1 and 2 and Net Carbon Footprint reductions, and that these were reflected in the asset-level forecasts. We assessed key internal and external evidence relevant to Shell's assessment of whether to continue to carry or write off assets in the group’s E&E portfolio, including analysing evidence of further activity being included in Shell’s operating plan and any contra evidence that suggests government or regulatory approvals will not be provided. In respect of E&E write offs and impairments recorded during the year, we considered whether evidence about current project activity, forecast future expenditure and operational plans was consistent with the decisions taken by management to write off or impair these assets. We also considered the disclosure of E&E asset write offs and impairments.
How we addressed the matter in our audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over Shell’s E&E impairment assessment process. For example, we tested controls over management’s review of E&E assets for write off and impairment. To test the completeness and appropriateness of the E&E asset write off and impairment charges recorded, our procedures included, amongst others, assessing each significant licence area against the impairment criteria within IFRS 6 with a particular focus on those assets that were expected to be developed over the medium and long term, those assets where the dominant commodity that will be produced is oil, or highly carbon intensive projects. Through this analysis, we independently identified the assets that we considered most at risk of not being developed by Shell or being divested as a consequence of the Company’s emissions reductions targets. We evaluated the likelihood of management progressing the E&E assets, including the strategic fit of the assets, carbon intensity of the developments, planned capex and project economics and the expectation that sufficient cash resources will be available to fund the expected development of assets. For example, in evaluating the strategic fit of carbon intensive assets, we considered the inclusion of actions within Shell’s operating plan to achieve target Scope 1 and 2 and Net Carbon Footprint reductions, and that these were reflected in the asset-level forecasts. We assessed key internal and external evidence relevant to Shell's assessment of whether to continue to carry or write off assets in the group’s E&E portfolio, including analysing evidence of further activity being included in Shell’s operating plan and any contra evidence that suggests government or regulatory approvals will not be provided. In respect of E&E write offs and impairments recorded during the year, we considered whether evidence about current project activity, forecast future expenditure and operational plans was consistent with the decisions taken by management to write off or impair these assets. We also considered the disclosure of E&E asset write offs and impairments.
Reference:
Note 9
Note 9
4: Asset retirement and environmental obligations
"THE ESTIMATION OF DECOMMISSIONING AND RESTORATION PROVISIONS"
Description:
Description of the matter As described in Note 19 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised $22.1 billion in D&R provisions. Auditing D&R provisions is complex because management’s estimation of future cash outflows involves significant judgement. As explained in Note 2 to the Consolidated Financial Statements, the estimate is based on current legal and constructive obligations, technology and price levels. However, the extent of the actual outflows incurred in the future may differ due to changes in laws, regulations, public expectations, technology, prices and conditions at the time of decommissioning, and can take place many years in the future. The timing of estimated future decommissioning activity is also a key judgement with the energy transition increasing the risk that oil and gas fields will be decommissioned earlier than anticipated. The key factor in determining the timing of decommissioning for Upstream and Integrated Gas assets will be the life of field assumptions, which is discussed in our oil and gas reserves critical audit matter. In respect of Oil Products and Chemicals operations, there is significant complexity in evaluating management’s judgements on the expected useful lives of manufacturing and production assets and, where decommissioning is expected to be generally more than 50 years into the future, that it is not possible to make an estimate of the obligation that is sufficiently reliable to use in recognising a D&R provision.
Description of the matter As described in Note 19 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised $22.1 billion in D&R provisions. Auditing D&R provisions is complex because management’s estimation of future cash outflows involves significant judgement. As explained in Note 2 to the Consolidated Financial Statements, the estimate is based on current legal and constructive obligations, technology and price levels. However, the extent of the actual outflows incurred in the future may differ due to changes in laws, regulations, public expectations, technology, prices and conditions at the time of decommissioning, and can take place many years in the future. The timing of estimated future decommissioning activity is also a key judgement with the energy transition increasing the risk that oil and gas fields will be decommissioned earlier than anticipated. The key factor in determining the timing of decommissioning for Upstream and Integrated Gas assets will be the life of field assumptions, which is discussed in our oil and gas reserves critical audit matter. In respect of Oil Products and Chemicals operations, there is significant complexity in evaluating management’s judgements on the expected useful lives of manufacturing and production assets and, where decommissioning is expected to be generally more than 50 years into the future, that it is not possible to make an estimate of the obligation that is sufficiently reliable to use in recognising a D&R provision.
Response:
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s process for the estimation of D&R provisions. We then evaluated the design of, and tested the operating effectiveness of, controls over the estimation of the D&R provision. For example, we tested controls over the review of the estimation and completeness of cost estimates. Our audit procedures included, amongst others, assessing changes in D&R cost estimates, and whether they reflected the latest regulatory requirements and technical developments. We audited cost assumptions relating to labour rates, rig type and rates, number of wells, well durations, and any contingencies applied by, amongst other procedures, inspecting contracts. We also evaluated whether the nature of the costs expected to be incurred were in accordance with the requirements of IAS 37. We evaluated management’s estimated life-of-field assumptions that determine the timing of decommissioning in Upstream and Integrated Gas as described in the estimation of oil and gas reserves critical audit matter. Also as described in the estimation of oil and gas reserves critical audit matter, we evaluated the estimated carbon intensity of the post 2030 production of Shell’s assets, in order to identify assets where there may be a higher risk of the reserves not ultimately being produced as this may impact the estimated cessation of production date for these assets. We tested the D&R accounting models and assumptions therein, including discount rates, and inflation rates. We validated the assumptions to external data sources and reconciled the assumptions with those used in other areas of measurement, such as impairment assessment. We evaluated the timing of recognition of D&R liabilities related to contingent liabilities and D&R liabilities arising from assets previously disposed of, including assessing the counterparty risk associated with those disposals. We also evaluated management’s assessment of the useful lives of manufacturing assets in the Oil Products and Chemicals portfolio. In particular, we evaluated whether D&R provisions were required for certain refineries and petrochemical facilities based on actions within Shell’s operating plan, including rationalisation of their manufacturing portfolio and plans to convert or dismantle existing units. This included assessing management’s ability to repurpose the units to increase production capabilities of refined products with lower carbon intensity. We assessed the disclosure of D&R provisions and contingent liabilities in the financial statements. We also evaluated management’s re-assessment of the need for contingent liability disclosures in respect of certain manufacturing assets.
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s process for the estimation of D&R provisions. We then evaluated the design of, and tested the operating effectiveness of, controls over the estimation of the D&R provision. For example, we tested controls over the review of the estimation and completeness of cost estimates. Our audit procedures included, amongst others, assessing changes in D&R cost estimates, and whether they reflected the latest regulatory requirements and technical developments. We audited cost assumptions relating to labour rates, rig type and rates, number of wells, well durations, and any contingencies applied by, amongst other procedures, inspecting contracts. We also evaluated whether the nature of the costs expected to be incurred were in accordance with the requirements of IAS 37. We evaluated management’s estimated life-of-field assumptions that determine the timing of decommissioning in Upstream and Integrated Gas as described in the estimation of oil and gas reserves critical audit matter. Also as described in the estimation of oil and gas reserves critical audit matter, we evaluated the estimated carbon intensity of the post 2030 production of Shell’s assets, in order to identify assets where there may be a higher risk of the reserves not ultimately being produced as this may impact the estimated cessation of production date for these assets. We tested the D&R accounting models and assumptions therein, including discount rates, and inflation rates. We validated the assumptions to external data sources and reconciled the assumptions with those used in other areas of measurement, such as impairment assessment. We evaluated the timing of recognition of D&R liabilities related to contingent liabilities and D&R liabilities arising from assets previously disposed of, including assessing the counterparty risk associated with those disposals. We also evaluated management’s assessment of the useful lives of manufacturing assets in the Oil Products and Chemicals portfolio. In particular, we evaluated whether D&R provisions were required for certain refineries and petrochemical facilities based on actions within Shell’s operating plan, including rationalisation of their manufacturing portfolio and plans to convert or dismantle existing units. This included assessing management’s ability to repurpose the units to increase production capabilities of refined products with lower carbon intensity. We assessed the disclosure of D&R provisions and contingent liabilities in the financial statements. We also evaluated management’s re-assessment of the need for contingent liability disclosures in respect of certain manufacturing assets.
Reference:
Note 19 and Note 2
Note 19 and Note 2
5: Deferred income taxes
"THE RECOGNITION AND MEASUREMENT OF DEFERRED TAX ASSETS (DTAs)"
Description:
Description of the matter As described in Note 17 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised gross DTAs of $29.4 billion. Auditing the recognition and measurement of DTA balances is subjective because the estimation requires significant judgement, including the timing of reversals of DTLs and the availability of future profits against which tax deductions represented by the DTA can be offset. In addition, auditing the recognition of DTA balances that are supported by the expectation of future taxable profits arising beyond Shell’s 10-year planning horizon required significant audit judgement, which was of heightened complexity given the future demand and price uncertainty due to climate change and the energy transition. There is greater uncertainty regarding future taxable profits that exist outside the 10-year planning period and where future taxable profits relate to new and emerging businesses with less history and therefore greater forecasting uncertainty.
Description of the matter As described in Note 17 to the Consolidated Financial Statements, at December 31, 2021 Shell recognised gross DTAs of $29.4 billion. Auditing the recognition and measurement of DTA balances is subjective because the estimation requires significant judgement, including the timing of reversals of DTLs and the availability of future profits against which tax deductions represented by the DTA can be offset. In addition, auditing the recognition of DTA balances that are supported by the expectation of future taxable profits arising beyond Shell’s 10-year planning horizon required significant audit judgement, which was of heightened complexity given the future demand and price uncertainty due to climate change and the energy transition. There is greater uncertainty regarding future taxable profits that exist outside the 10-year planning period and where future taxable profits relate to new and emerging businesses with less history and therefore greater forecasting uncertainty.
Response:
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s processes for the recognition and measurement of DTAs. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested controls over projections of future taxable income and the deferred tax calculations that support the recognition of DTAs. Amongst other procedures, we assessed management’s determination of the expected timing of utilisation of the DTAs, including the application of relevant tax laws that apply to the utilisation of tax losses. We tested management’s forecasted timing of the reversal of taxable temporary differences by evaluating the projected sources of taxable income and considered the nature of the temporary differences and the relevant tax law. We performed sensitivity analyses over Shell’s risk-weighted future taxable profits by jurisdiction, which take into account potential costs of decarbonisation, and specific risking applied to profits forecast through Shell's operating plan process to be generated through new and growing business activities, including biofuels and Electric Vehicle (EV) charging. We reconciled the forecast to that used in other areas of analysis, such as impairment. Our testing also included evaluating management’s negative stress test to assess the tolerance of the estimation uncertainty to further risking. We involved professionals with experience in auditing renewable businesses, including EV charging, in challenging management’s assumptions and the outcome of the stress testing performed.
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s processes for the recognition and measurement of DTAs. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested controls over projections of future taxable income and the deferred tax calculations that support the recognition of DTAs. Amongst other procedures, we assessed management’s determination of the expected timing of utilisation of the DTAs, including the application of relevant tax laws that apply to the utilisation of tax losses. We tested management’s forecasted timing of the reversal of taxable temporary differences by evaluating the projected sources of taxable income and considered the nature of the temporary differences and the relevant tax law. We performed sensitivity analyses over Shell’s risk-weighted future taxable profits by jurisdiction, which take into account potential costs of decarbonisation, and specific risking applied to profits forecast through Shell's operating plan process to be generated through new and growing business activities, including biofuels and Electric Vehicle (EV) charging. We reconciled the forecast to that used in other areas of analysis, such as impairment. Our testing also included evaluating management’s negative stress test to assess the tolerance of the estimation uncertainty to further risking. We involved professionals with experience in auditing renewable businesses, including EV charging, in challenging management’s assumptions and the outcome of the stress testing performed.
Reference:
Note 17
Note 17
6: Revenue from customer contracts
"REVENUE RECOGNITION: THE MEASUREMENT OF UNREALISED TRADING GAINS AND LOSSES"
Description:
Description of the matter As described in Note 5 of the Consolidated Financial Statements, at December 31, 2021 Shell recognised $262 billion of revenue. As described in Note 20, Shell recognised derivative financial instrument assets of $12.2 billion and derivative financial instrument liabilities of $17.2 billion. Shell’s trading and supply function is integrated within the Oil Products, Chemicals, Integrated Gas and Upstream segments and is spread across multiple regions. Auditing the measurement of unrealised trading gains and losses was complex because of the significant judgement used in determining the key assumptions used in valuing the trades, the risk of error, of unauthorised trading activity or of deliberate misstatement of Shell’s trading positions. Also, trading is not always carried out in active markets where prices are readily available, increasing subjectivity used in determining the pricing curve and volatility assumptions, which are key inputs to valuing the trades. Identifying unrealised trading gains and losses is also complex due to the significant volume of transactions entered into by Shell and the lack of market transparency of executed deals. The deliberate misstatement of Shell’s trading positions or mismarking of positions could result in understated trading losses, overstated trading profits and/or individual bonuses being manipulated through inappropriate inter-period profit/loss allocations.
Description of the matter As described in Note 5 of the Consolidated Financial Statements, at December 31, 2021 Shell recognised $262 billion of revenue. As described in Note 20, Shell recognised derivative financial instrument assets of $12.2 billion and derivative financial instrument liabilities of $17.2 billion. Shell’s trading and supply function is integrated within the Oil Products, Chemicals, Integrated Gas and Upstream segments and is spread across multiple regions. Auditing the measurement of unrealised trading gains and losses was complex because of the significant judgement used in determining the key assumptions used in valuing the trades, the risk of error, of unauthorised trading activity or of deliberate misstatement of Shell’s trading positions. Also, trading is not always carried out in active markets where prices are readily available, increasing subjectivity used in determining the pricing curve and volatility assumptions, which are key inputs to valuing the trades. Identifying unrealised trading gains and losses is also complex due to the significant volume of transactions entered into by Shell and the lack of market transparency of executed deals. The deliberate misstatement of Shell’s trading positions or mismarking of positions could result in understated trading losses, overstated trading profits and/or individual bonuses being manipulated through inappropriate inter-period profit/loss allocations.
Response:
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s process for the recognition of revenue relating to unrealised trading gains and losses, including controls over management’s processes around complex deal valuations. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested controls around the review of pricing curve and volatility assumptions applied in the valuation models. We involved audit professionals with significant experience auditing large commodity trading organisations. We assessed Shell’s valuation methodology against market practice and analysed whether a consistent framework was applied across the business and assessed the consistency of inputs used in deal valuations and other assumptions. We tested the pricing curve and volatility assumptions in management’s valuation models, including by comparing these to external broker quotes, market consensus providers, and our independent assessments. We involved EY valuation specialists to assist us in performing independent testing of the valuation models of Level 3 contracts, including the valuation of long-dated offtake contracts and those with illiquid tenor or price components. Our valuations were established using independently sourced inputs, where available. We evaluated contract terms and key assumptions against independent market information, including assessing complex deals for the existence of non-standard contractual terms or features. To audit the measurement and valuation of open trading positions, we focused specifically on over the counter (OTC) physical and financial transactions. Amongst other procedures, we obtained external confirmation of a sample of open trading positions with brokers and counterparties and, where deemed necessary, tested the existence of the position by agreement to signed contracts. We performed additional confirmation testing by obtaining confirmations from key counterparties who had open positions in the prior trading year, but no reported trading positions in the current year. We also performed procedures to identify unrecorded liabilities by comparing sales to trade receivables and purchases to trade payables that occurred near the end of the financial year to evaluate whether or not the transactions had been recorded appropriately and in the correct period. We assessed the Level 3 disclosures included in the consolidated financial statements.
How we addressed the matter in our audit We obtained an understanding of the controls over Shell’s process for the recognition of revenue relating to unrealised trading gains and losses, including controls over management’s processes around complex deal valuations. We then evaluated the design of these controls and tested their operating effectiveness. For example, we tested controls around the review of pricing curve and volatility assumptions applied in the valuation models. We involved audit professionals with significant experience auditing large commodity trading organisations. We assessed Shell’s valuation methodology against market practice and analysed whether a consistent framework was applied across the business and assessed the consistency of inputs used in deal valuations and other assumptions. We tested the pricing curve and volatility assumptions in management’s valuation models, including by comparing these to external broker quotes, market consensus providers, and our independent assessments. We involved EY valuation specialists to assist us in performing independent testing of the valuation models of Level 3 contracts, including the valuation of long-dated offtake contracts and those with illiquid tenor or price components. Our valuations were established using independently sourced inputs, where available. We evaluated contract terms and key assumptions against independent market information, including assessing complex deals for the existence of non-standard contractual terms or features. To audit the measurement and valuation of open trading positions, we focused specifically on over the counter (OTC) physical and financial transactions. Amongst other procedures, we obtained external confirmation of a sample of open trading positions with brokers and counterparties and, where deemed necessary, tested the existence of the position by agreement to signed contracts. We performed additional confirmation testing by obtaining confirmations from key counterparties who had open positions in the prior trading year, but no reported trading positions in the current year. We also performed procedures to identify unrecorded liabilities by comparing sales to trade receivables and purchases to trade payables that occurred near the end of the financial year to evaluate whether or not the transactions had been recorded appropriately and in the correct period. We assessed the Level 3 disclosures included in the consolidated financial statements.
Reference:
Note 5 and Note 20
Note 5 and Note 20